[Bernstein] Era of Cheap Oil Over as Secular Growth in Upstream_Cost Inflation Underpins Triple Digit Oil Prices

7/26/2019 [Bernstein] Era of Cheap Oil Over as Secular Growth in Upstream_Cost Inflation Underpins Triple Digit Oil Prices

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A s i a - P a c i f i c O i l & G

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Neil Beveridge, Ph.D. (Senior Analyst) • [email protected] • +852-2918-5741

Oswald Clint, Ph.D., ACA (Senior Analyst) • [email protected] • +44-207-170-5089

Bob Brackett, Ph.D. (Senior Analyst) • [email protected] • +1-212-756-4656

Scott Gruber, CFA (Senior Analyst) • [email protected] • +1-212-756-1935

Lu Wang • [email protected] • +852-2918-5723

See Disclosure Appendix of this report for important disclosures and analyst certifications.

Bernstein Energy: Era of Cheap Oil Over As Secular Growth inUpstream Cost Inflation Underpins Triple Digit Oil Prices

Please see the Disclosure Appendix for the ratings and price targets of the companies covered in this report.

Highlights

Our analysis of the 50 largest publically traded oil and gas companies (ex-FSU) shows that cost inflation

continues to increase sharply within the global upstream oil and gas industry. In 2011, production costsincreased by 26% while the unit cost of production increased by 21%, which was higher than longer termtrends. In 2011, the marginal cost of production the same companies increased 10.8% to US$92.26/bbl.

∑ We have analyzed cost data for the 50 largest listed international oil and gas companies (ex-FSU)

which we define as the 'Upstream G50'. Following the recent release of 2011 20-F and annual reportsfrom the 50 largest producing oil and gas companies, we have constructed a database which includes allkey upstream financial and operating metrics.

∑ Production cost inflation for the Upstream G50 was higher last year than long term average trends.

In 2011, upstream production costs increased by 26% y-o-y relative to 10yr CAGR growth rates of 20%.Unit costs increased by 21% y-o-y to US$35.9 which was also higher relative to the 10yr CAGR growthrate of 17% , highlighting continued cost pressures facing by the global oil and gas industry. The ratio between oil prices and upstream unit costs remains at close to three times.

∑ Organic F&D (reserve replacement) costs for the Upstream G50 increased by a slower rate of 11%

in 2011 as higher reserve replacement rates offset capex growth. F&D costs increased 11% toUS$17.5/bbl which was in line with longer term growth rates. Three year reserve replacement ratios

continue to trend higher to a multi-year high of 130% highlighting improved industry success atreplacing reserves.

∑ The marginal cost of production for the Upstream G50 increased in 2011 by 10.6% to

US$92.26/bbl. The total marginal cost of production for the 50 largest oil and gas producers continues totrend higher increasing from US$83/bbl to US92/bbl. The rate of growth in F&D costs in 2011 wasslightly lower than the 10 year GAGR growth in marginal of 14% CAGR. The cash cost of productionincreased more by 37% to US$39.95/bbl.

∑ De-coupling of oil prices from gas prices and wider Brent/WTI spreads resulted in near record

spreads between revenue per boe and Brent in 2011. Average revenue per boe for the Upstream G50was US65.54/bbl in 2011 which was 41% lower than benchmark Brent index price for the year. Recordoil/gas price spreads in the US and globally plus Brent/WTI spreads continued to drive the large

differentials in realized price relative to Brent.∑ Despite the 39% increase in Brent from US$79.73 to US$111.05/bbl in 2011, net income per barrel

remained constant at 15% of the benchmark oil price. Average net income per boe increased by 35%to US$16.36/bbl in 2011 which was a slight increase in 2011 despite the 26% increase revenue per boe(relative to 39% increase in Brent). Net income per boe remains flat at 15% of Brent and net incomemargins at 25% of realized price.

∑ While we remain cautious on crude prices in the near term, the increase in global upstream costs

continues to be supportive of higher long term oil prices. The increase in unit costs, production costs




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and ultimately marginal cost of production continues to be the key driver of global oil prices. Data from2011 continue to show strong growth in upstream costs remains intact across all regions. Absent acollapse in demand or growth in a new source of low cost oil supply, rising upstream costs will continueto be supportive of higher long term oil prices.

Investment Conclusion

Long term oil prices remain fundamentally linked to the marginal cost of production. The key message forinvestors from our 2011 survey of global oil and gas companies is that upstream costs continue to increasesharply. Tracking data from the 50 largest listed oil and gas producing companies globally (ex FSU)indicates that cash, production and unit costs in 2011 grew at a rate significantly faster than the 10 yearaverage. Last year production costs increased 26% y-o-y, while the unit cost of production increased by21% y-o-y to US$35.88/bbl. This is significantly higher than the longer term cost growth rates, highlightingcontinued cost pressures faced by the E&P industry as the incremental barrel continues to become moreexpensive to produce. The marginal cost of the 50 largest oil and gas producers globally increased toUS$92/bbl in 2011, an increase of 11% y-o-y and in-line with historical average CAGR growth. Assuminganother double digit increase this year, marginal costs for the 50 largest oil and gas producers could reachclose to US$100/bbl.

While we see near term downside to oil prices on weaker demand growth, the longer term outlook forhigher oil prices continues to be supported by the rising costs of production. Globally we continue to likecompanies with strong organic upstream growth, high and improving returns, strong reserves replacementand high operating leverage to commodity prices. Amongst global E&Ps and integrated oil and gas majorswe have outperform ratings on CNOOC, Oil Search, Reliance, Total, Apache, Noble Energy, Gazprom,GALP, Repsol, EOG, Tullow Oil and BG.

Details

We have analyzed the 50 largest international oil and gas producing companies globally (ex-FSU) which

we term the 'Upstream G50'. The data for our analysis comes from 20-F reports and from annual reportswhere there is no 20-F available. Three companies (Inpex, ONGC and Pemex) have not yet released their2011annual reports and hence we use quarterly estimates and extrapolate full year result.

Within this report we use several definitions of cost such as cash cost, production cost, unit costs andmarginal costs. These costs are linked in some cased but measure slightly different aspects of cost. Thedefinitions of costs we use within the report are provided below.

Cash Costs = Operating Costs + Production Taxes+ SG&A

Production Costs = Operating Costs + Production Taxes

Unit Costs = Production Costs + Exploration Expense + DD&A+ SG&A

Organic F&D Costs = Organic Capex / Reserve Additions from Discoveries or Revisions.

The Marginal Cost of Production and Cash Cost of Production use the definitions which can be accessedfrom Bernstein Energy: The Non-OPEC Supply Curve; The Rising Marginal Cost of Oil ProductionFrom America To Asia

In this research note, we provide an analysis of the cost trends for the Upstream G50 together with anupdated marginal cost calculation.

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Break down of the global barrel

How is the global barrel broken down? Using the Upstream G50 data base and using production weightedaverages it is possible to define the make-up of the global barrel Exhibit 1, Exhibit 2. Using Brent as theindex, the realization spread between revenue per boe and Brent in 2011 was US$45.41/bbl or 41% of the

price of Brent. Much of the differential in realization results from the spread between oil and gas (currentlydomestic gas is around US$15/boe in the US and US$30/boe in Asia) plus the spread between Brent andinternational crude prices. The next largest component of the barrel is production costs which include production related taxes and account for 19% of the barrel. Income tax is the next largest component whichcomprises12% of the global barrel followed by DD&A, SG&A and other and exploration expense whichcombined make up 13% of the barrel. Net income accounts for 15% of the overall barrel.

Exhibit 1Summary of global barrel key metrics

Source: Bloomberg, Bernstein analysis and estimates

In addition to the breakdown of the global barrel the components of the global barrel have remainedrelatively constant over the past 10 years despite the fact that oil prices have increased from US20/bbl toover US 100/bbl. For example, the unit costs have remained at about 30-35% of the global oil price, incometax at 10-20%, while net income has remained at about 15-20% of the global barrel.

10Yr

US $/bbl 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 CAGR

WTI 25.96 26.17 31.06 41.51 56.59 66.09 72.23 99.92 61.99 79.51 95.05 14%

Brent 24.40 25.02 28.87 38.32 54.51 65.42 72.71 97.69 62.04 79.73 111.05 16%

Revenue 14.33 15.70 19.62 28.66 38.24 44.89 48.75 60.97 40.93 51.93 65.64 16%

Resalization Spread 10.07 9.32 9.25 9.66 16.27 20.53 23.96 36.72 21.11 27.80 45.41 16%

Production Costs 3.51 3.97 4.76 6.10 7.71 9.15 10.53 16.78 13.32 16.73 21.14 20%

Exploration Expense 0.63 0.63 0.68 0.82 0.92 1.27 1.70 1.91 1.85 1.78 1.99 12%DD&A 2.61 3.38 3.55 4.54 5.07 6.04 7.18 8.76 8.40 9.22 9.86 14%SG&A & Other 0.54 0.87 0.73 1.10 1.72 1.56 1.89 2.40 2.15 1.89 2.89 18%

Income Tax 2.97 2.96 3.89 8.50 11.91 13.93 14.44 14.36 6.82 10.21 13.41 16%Implied CT Rate 42% 43% 39% 53% 52% 52% 53% 46% 45% 46% 45%

Net Income 4.07 3.90 6.00 7.59 10.92 12.94 13.02 16.76 8.40 12.11 16.36 15%Net Income Margin 28% 25% 31% 26% 29% 29% 27% 27% 21% 23% 25%

Unit Costs 7.29 8.84 9.73 12.57 15.41 18.02 21.30 29.85 25.72 29.61 35.88 17%

Organic F&D Costs 5.10 5.79 6.55 10.32 12.67 13.32 16.54 20.22 10.94 15.76 17.45 13%RRR (3 Year Average) 130% 132% 119% 114% 101% 105% 101% 98% 108% 115% 129%

Cash Flow (Pro-Forma) 7.31 7.90 10.24 12.95 16.91 20.25 21.89 27.43 18.65 23.11 28.20 14%FCF 0.60 (1.35) 1.84 2.35 2.70 1.42 2.50 3.19 (0.30) (3.74) 2.84 17%Capex 6.71 9.26 8.40 10.60 14.21 18.83 19.39 24.24 18.95 26.85 25.36 14%Re-Investment Ratio 92% 117% 82% 82% 84% 93% 89% 88% 102% 116% 90%

Maginal Cost 25.30 29.50 36.27 45.17 57.55 54.39 63.81 96.14 67.80 83.23 92.26 14%

Cash Cost 9.69 9.72 12.45 15.00 21.66 23.04 24.35 32.36 24.02 28.87 39.65 15%

WTI/ Marginal Cost 1.03 0.89 0.86 0.92 0.98 1.22 1.13 1.04 0.91 0.96 1.03Brent/ Unit Cost 3.35 2.83 2.97 3.05 3.54 3.63 3.41 3.27 2.41 2.69 3.10




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Exhibit 2Break down of global barrel

Source: Corporate Reports, Bernstein Analysis

The most important factor driving oil prices over the long run is the growth in the marginal cost of production. In addition to marginal cost, cash costs, production costs, unit costs and F&D costs are alluseful measures of costs. Over the past 10 years, these costs have growth at between 10-20% CAGR in-line

with oil prices which have increased at about 16% CAGR growth in the last decade Exhibit 3.

Exhibit 3 Y-o-Y growth rate (2001-2011)


18% 17% 16% 21% 20% 20% 20% 18% 17% 14% 15% 15%

12% 14% 16%

16% 16% 14% 14% 14% 17% 21% 21% 19%

2% 3% 2%

2% 2% 2% 2% 2% 2% 3% 2%2%9%

11% 14%

12%12%

9% 9% 10% 9%14% 12%

9%1%2%

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3%2%

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12%12%

13% 22%

22% 21% 20%15%

11% 13%

12%

44% 41% 37%

32%25%

30% 31% 33%38% 34% 35%

41%

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Net Income Production Costs Exploration Expense DD&A SG&A & Other Income Tax Resalization Spread

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2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Brent Production Costs DD&A

Unit Costs Cash Costs Organic F&D Costs




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Examining the growth in costs of the past 10 years according to various definitions, production and cashcosts have grown more than others, increasing at close to 20% p.a. Exhibit 4. As we have described previously, this reflects a combination of higher material costs and reduced productivity per well BernsteinCommodities & Power: Will Fraccing Lead to A Reversal in Global Oil Industry Productivity andEnergy Deflation? Organic F&D costs have increased at around 13% over the past 10 years which is at thelower end across the overall measures of cost. Not surprisingly the unit cost of production which is the broadest measure of cost tracks most closely with overall oil price inflation which has averaged 17% CAGRover the past decade.

Exhibit 410 year CAGR (2001-2011). Upstream oil and gas costs have increased at 10-20% CAGR over the past decade


Last year, oil prices grew at 39%, followed by cash costs and production costs which increased by 29% and26% respectively Exhibit 5. Unit costs which track oil prices most closely over the past 10 years grew at

21%. Growth in cash production and unit costs were all significantly above the long term 10 year averagegrowth rates. Although F&D (reserve replacement) costs grew at a slower rate of 11% p.a. the growth wasin line long term growth rates of 13%. One of the factors which kept organic F&D costs lower was thecontinued high reserve replacement rate. Three year organic reserve replacement rates are now at a multi-year high of 130%.

20% 19%18%

17%16%

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ProductionCosts

Cash Costs SG&A & Other Uni t Costs Oil (Brent ) DD&A Organic F&DCosts

ExplorationExpense

1 0 y e a r C A G R

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Exhibit 51 year growth rate (2010-2011). Cash Cost and Production costs have increased above the long term 10 year average


The 2011 Non-OPEC ex FSU Marginal Cost Curve

As part of this analysis, we have constructed a global database of the 50 largest oil-producing companiesglobally (Exhibit 6). We have excluded OPEC and Russian companies given the limited time series or thedata and some of the limitations around how some of the data is reported. In terms of total production, thelargest companies are ExxonMobil, Pemex, PetroChina and BP. We have included 13 companies with total production greater than 1 million boe per day.

Exhibit 6

The Upstream G50. Summary of companies included in non-OPEC ex FSU cost curve (2011)

Source: Corporate Reports , Capital IQ, Bernstein analysis

39%

29%26%

21%

12% 11%7%

0%

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50%

SG&A & Other Oil (Brent) Cash Costs ProductionCosts

Unit Costs ExplorationExpense

Organic F &DCosts

DD&A

1 y e a r g r o w t h r a t e

53%

Company Country Production % oil M. Cap Company Country Production % oil M. Cap

kboepd $bn kboepd $bn

ExxonMobil USA 4,506 51% 405 EOG USA 423 37% 29

Pemex Mexico 3,649 70% NA Hess USA 370 72% 17

PetroChina China 3,522 69% 286 Marathon USA 358 60% 21

BP UK 3,410 63% 138 Talisman Canada 352 42% 14

Shell UK 3,256 51% 229 Husky Canada 281 65% 25

Chevron USA 2,676 69% 209 PTTEP Thailand 265 29% 19

Petrobras Brazil 2,392 85% 149 Reliance India 257 10% 46

Total France 2,227 55% 109 Imperial USA 242 84% 39

Statoil Norway 1,581 59% 85 Noble USA 223 39% 18

ConocoPhilips USA 1,552 51% 92 Nexen Canada 188 80% 10

ENI Italy 1,472 57% 81 Murphy USA 179 58% 11

ONGC India 1,131 60% 43 Woodside Australia 178 43% 30

Sinopec China 1,118 79% 97 Penn West Canada 163 63% NA

CNOOC China 904 78% 94 Newfield USA 138 40% 5

Repsol Spain 767 50% 23 Pioneer USA 133 48% 14

Apache USA 748 50% 36 Santos Australia 129 25% 14Occidental USA 733 72% 74 Plains E&P USA 100 49% 5

Anadarko USA 674 42% 37 Tullow UK 78 73% 23

Devon USA 649 35% 28 Enerplus Canada 72 42% 4

BG UK 641 26% 80 Denbury USA 66 93% 7

CNRL Canada 599 65% 37 Pengrowth Canada 61 48% 3

EnCana Canada 580 4% 15 Forest USA 56 28% 1

Chesapeake USA 545 16% 11 Berry USA 36 69% 2

INPEX Japan 427 57% 24 OilSearch Australia 18 86% 10




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In this call we calculated the marginal cost and cash cost of production for non-OEPC producers based on a previously published methodology (Bernstein Energy: The Non-OPEC Supply Curve; The Rising

Marginal Cost of Oil Production From America To Asia and Bernstein Energy: The Global Non-

OPEC Supply Curve; Why North American Micro E&Ps Set the Marginal Cost).While OPEC plays a key role in influencing price through production quotas, in the long run we believethat it is the marginal cost of non-OPEC production which sets the oil price. As global demand has surgedover the past decade the marginal cost of production and oil prices have increased, as the industry hasventure to increasingly higher cost (smaller, deeper fields) and more marginal regions (deep water, higharctic) to produce the incremental barrel of oil.

The summary of our global marginal cost analysis is shown in Exhibit 7. Taking the top 50 Non-OPEC producing companies, we have seen the marginal cost of production increase from US$25/bbl to US$92/bblwhich represents a CAGR growth of 14%. At the same time, cash costs of production have increased fromUS$10/bbl to around US$40/bbl, which represents a CAGR growth of 15%.

Exhibit 7The Marginal cost of oil production for the Upstream G50 reached US$92/bbl in 2012

Source: Corporate Reports , Bernstein analysis and estimates

We have assembled the 2011non-OPEC supply curve, which shows that the 90th percentile marginal cost ofoil was US$92/bbl. The lowest cost companies were ECA, Reliance, BG and INPEX. The highest costcompanies were Nexen, Pengrowth, Anadarko, and Enerplus (Exhibit 8).

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Esti mated Pric e of Demand Destruction

Estimated Cash Cost


































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Exhibit 82011 Global non-OPEC ex FSU marginal cost of supply curve for oil

Source: Corporate Reports , Bernstein analysis

We compared 2002 global marginal cost and production curves with 2011and found the companies withlow costs tend to remain low-cost which the high cost companies have remained high cost (Exhibit 9).

Exhibit 92011 vs 2002 global non-OPEC ex FU marginal cost of supply curves for oil


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0 3,000 6,000 9,000 12,000 15,000 18,000 21,000 24,000 27,000

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ECA,RIL,BGINPEX

WPL,PTTEP

X O M

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OSH

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Using the same companies, we looked at how the non-OPEC marginal cost of supply has changed overtime. We found that the marginal cost increased dramatically between 2002 and 2005, and then rose slightlyin 2006 and 2007, peaked in 2008, dropped in 2009 and rose again in 2010 and 2011. The 90 th percentile formarginal costs increased with 14% compound annual growth rate while the median marginal costs

increased with 9% compound annual growth rate (Exhibit 10).

Exhibit 10Non-OPEC ex FSU marginal costs (90th percentile ofproduction) and median marginal costs, 2002-2011

Exhibit 11Non-OPEC ex FSU cash costs (90th percentile ofproduction) and median cash costs, 2002-2011

Source: Corporate Reports, Bernstein analysis Source: Corporate Reports, Bernstein analysis

The 2011 Non-OPEC ex FSU Cash Cost Curve

In addition to calculating the marginal cost required to replace production with new reserves, we alsocalculated the variable cash costs based on production costs (operating expenses and production taxes). Thisindicates at what point it becomes uneconomic to produce oil, which would lead to production shut-ins.Given the variability within each company's portfolio, there presumably is some production that would beshut in even at higher levels than the overall cash costs, but the cash cost gives an indication of the range.

The large companies with the highest cash costs were PEMEX, Penn West, Imperial and Sinopec. Thecompanies with the lowest cash costs were TOTAL, Reliance, ECA and Statoil (Exhibit 12)

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Exhibit 122011 global non-OPEC ex FSU cash cost of supply curve for oil


We compared 2002 global cash cost and production curves with 2011 and found the companies with lowcosts tend to remain low-cost, and vice-versa (Exhibit 13).

Exhibit 132011 vs 2002 global non-OPEC ex FSU cash cost of supply curves for oil


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Where Have Global Costs Been Trending

Unit costs are comprised of production cost, DD&A, exploration expense, SG&A and other expenses.

Analysis of the 50 largest non-OPEC ex FSU oil and gas producers shows that production weighted averageunit costs (group total costs/group total production) in the industry increased from 7.3 US$/boe in 2001 to

35.9 US$/boe in 2011 with 10 year CAGR of 17% (Exhibit 14). Unit costs plus realization spreadincreased from 17.4 US$/boe in 2001 to 81.3US$/boe in 2011 (Exhibit 15).

Exhibit 14Global unit costs increased to a record high of 35.9 US$/boe


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Production Costs DD&A Exploration Exp ense SG&A & Other Brent




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Exhibit 15Unit costs plus realization spread increased to a record high of 81.3 US$/boe


The ratio between oil price and global unit costs has remained close to a constant ratio of 3.1x (i.e. oil price= 3.1x unit costs) (Exhibit 16). Average revenue is almost two times of unit costs in the past ten years(Exhibit 17).

Exhibit 16Oil price (Brent) / unit costs have remained constant at3x

Exhibit 17Revenue per boe / unit costs has been closer to 2x overthe past decade

Source: Corporate Reports, Bernstein Analysis Source: Corporate Reports, Bernstein Analysis

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3.0

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2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

2 0 0 7

2 0 0 8

2 0 0 9

2 0 1 0

2 0 1 1

Revenue / Unit Cos ts Average

2.0x




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May 2, 2012


13

Exhibit 18Global cash costs of oil and gas production increased to 24 US$/boe


Exhibit 19Net income increased to 16.4 US$/boe with a margin of 25% in 2011.


Organic finding and development (F&D) is one of the best measures of costs within the oil and gasindustr y. F&D cost per barrel is simply the capital expenditure spent in finding and developing a bar rel ofoil organically (ex acquisition). Analysis of the 50 largest non-OPEC ex FSU oil and gas producers shows

0

20

40

60

80

100

120

0

5

10

15

20

25

30

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

B r e n t ( $ / b b l )

C a s h C o s t s ( $ / b o e )

Pro duction Costs SG&A & Othe r Brent

0%

5%

10%

15%

20%

25%

30%

35%

0

2

4

6

8

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14

16

18

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

N e t I n c o m e M a r g i n

N e t I n c o m e ( $ / b o e )




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May 2, 2012


14

that average organic F&D costs in the industry increased from US5.1/bbl in 2001 to US17.5/bbl in 2011with 10 year CAGR of 13% (Exhibit 20).

Exhibit 20Organic F&D costs increased from US$5.1/bbl in 2001 to US$17.5/bbl in 2011 with 10 year CAGR of 13%.


Given that development costs are the single most important driver of the economics of oil and gas projects(as capital is spent up front), it should not come as a surprise that F&D costs have moved lock step with oil prices over the past 10 years. As a result, the ratio between oil prices and global organic F&D costs has

remained close to a constant ratio of 4.8x (i.e. oil price = 4.8 x organic F&D costs) (Exhibit 21).The ratio between total revenue and global organic F&D costs has remained close to a constant ratio of 3.1x(i.e. total revenue = 3.1x organic F&D costs) (Exhibit 22), which indicates average blended oil and gasrevenue as percentage of oil price was about 65% during last ten years.

0

20

40

60

80

100

120

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

B r e n t ( $ / b b ; )

O r g a

n i c F & D C o s t s ( $ / b o e )




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May 2, 2012


15

Exhibit 21Oil price (Brent) / organic F&D ratio remained stablearound 5x in the last 10 years.

Exhibit 22Revenue / organic F&D remained stable around 3x over the last 10 years.


Exhibit 23Global 3-year average reserve replacement ratioexceeded 10 year average and came in at c. 130% in2011.

Exhibit 24Global R/P ratio for the Upstream G50 remains stable ataround 13x


Summary

Long term oil prices remain fundamentally linked to the marginal cost of production – and the key message for investors from our 2011 survey of companies is that costs continue to relentlessly march higher. Ten

-

1.0

2.0

3.0

4.0

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6.0

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2 0 0 1

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2 0 1 0

2 0 1 1

Brent / Organic F &D Average

4.8x

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2.0

3.0

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5.0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

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2 0 0 8

2 0 0 9

2 0 1 0

2 0 1 1

Revenue / Organic F &D Average

3.1x

0%

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40%

60%

80%

100%

120%

140%

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

2 0 0 7

2 0 0 8

2 0 0 9

2 0 1 0

2 0 1 1

3 yr avg RRR Average

114%

-

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

2 0 0 7

2 0 0 8

2 0 0 9

2 0 1 0

2 0 1 1

R/P Average

13.0x




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May 2, 2012


16

years ago production costs were less than US4/bbl and F&D costs US$5/bbl. Last year production costswere over US$20/bbl and F&D cost US$18/bbl. While we see near term downside to oil prices on weakerdemand growth, the longer term outlook for higher oil prices continues to be supported by the rising costsof production.

Appendix -- Costs by company and cost inflation

Exhibit 25Marginal cost by company in 2011


0

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40

50

60

70

80

90

100

N X Y

P E M E X

E R F

A P C

C N Q

H S E

P G F

M U R

P W T

T L M

H E S

M R O

B R Y

R E P

S N P

E O G

D N R

P X P

N B L

N F X

O N G C

T L W B P

C E O

C O P

P T R

P B R E N I

I M O A P A

O X Y

P X D

D V N

S T O F S T

S T L

T O T

C V X

O S H

R D S A

P T T

W P L

X O M

I N P E X B G R I L

C H K

E C A

M a r g i n a l C o s t $ / b

b l




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May 2, 2012


17

Exhibit 26Cash cost by company in 2011


Exhibit 27Unit costs by company in 2011


0

5

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20

25

30

35

40

45

P E M E X

P W T I M O S N P P B R P G F B P

O N G C

C N Q

C E O R E P

D N R P T R

I N P E X E R F B R Y H S E N X Y

X O M

T L W N F X H E S P X P

C O P

R D S A A P C O X Y P X D

M U R T L M

M R O S T O C V X D V N

O S H A P A

W P L P T T N B L E N I

E O G F S T C H K S T L B G E C A T O T R I L

C a s h C o s t $ / b b l

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10

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40

50

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70

P E

M E X N X Y

A P C E R F

P G F

S N P

D N R H E S

C E O

P W T

M U R

P B R

M R O B R Y

T L W T L M H S E

P T R

I N

P E X

O S H

C O P

S T O

C N Q

W P L B P

E O G N F X

R

D S A I M O P X P N B O X Y

O

N G C

C V X P T T

A P A

X O M P X D

R E P S T L E N I B G T O T

E C A

D V N F S T R I C H K

U n i t C o s t , U S $ / b o e




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May 2, 2012


18

Exhibit 28Unit costs inflation by company 2011 over 2010. Chinese oil majors highlighted in grey.


Exhibit 29Unit cost 5 yr CAGR by company


-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

A P C F S T

N X Y S T L

N B L B P

C E O

M U R S N P

C N Q

M R O S T O P T R N F X

D N R H E S P B R H S E

X O M T O T

O X Y

C V X

W P L

I N P E X A P A P T T

E O G

P E M E X B G

C O P

R D S A B R Y T L M

P W T

O N G C P X P

D V N

P X D P G F I M O

C H K

T L W O S H

E C A R E P R I L E N I

E R F

U n i t C o s t s Y - o - Y I n f l a t i o n

-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

P E M E

X

P T

R

R E

P

I M

O

E R

F

C E

O

M R

O

B

P

P B

R

S N

P

A P

C

D N

R

H E

S

P W

T

B

G

R D S

A

P G

F

W P

L

N X

Y

C V

X

T O

T

S T

O

C O

P

E O

G

H S

E

N B B R

Y

O S

H

P T

T

I N P E

X

O N G

C

S T L

M U

R

X O

M

P X

P

N F

X

A P

A

E N I

T L W E C

A

T L

M

O X

Y

C N

Q

D V

N

F S

T

P X

D

C H

K

R I L

U n i t C o s t s C A G R




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May 2, 2012


19

Exhibit 30Production cost by company in 2011


Exhibit 31Production cost 5 yr CAGR by company


-

10

20

30

40

50

60

P E M E X S N P

P B R

I N P E X

C E O P G F

P T R

D N R

P W T I M O B P

B R Y E R F

R D S A N X Y

X O M

O N G C

C N Q

T L W C O P

S T O H E S

M R O

O S H

T L M

W P L

H S E

M U R N F X P X P

C V X

O X Y

A P C

P X D P T T

R E P

A P A

D V N

E O G S T L

N B L E N I

F S T B G

C H K

E C A R I L

T O T

P r o d u c t i o n C o s t , U S $ / b o e

-10%

-5%

0%

5%

10%

15%

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30%

P E M

E X

C

E O I M O B P

R D

S A

R

E P

P W T

E

R F

N

X Y

P

G F

S

T O

S

N P

M

R O

C

V X

P

B R

P

T R

O

S H S T L

N

F X

H

E S

D

N R

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P L B G

T

L W

C

O P

M

U R

X

O M

I N P

E X

B

R Y E N I

H

S E

A

P C

O N

G C P T T

T

O T

P

X D

O

X Y

E O G

A

P A

T

L M

P

X P

N

B L

C

N Q

D

V N

C

H K

E

C A F S T R I L

P r o d u c t i o n C o s t C A G R




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20

Exhibit 32DD&A by company in 2011


Exhibit 33Exploration expense by company in 2011


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N X Y

H S E

P W T

M R O P G F

P X P

C N Q

T L W H E S

D N R T L M

M U R E R F

B R Y

E C A

E O G N F X

A P A

C E O A P C

S N P

S T O P X D

C O P R I L S T L

N B L P T T

O X Y

O N G C

C V X F S T E N I

W P L

P T R

R D S A

D V N

C H K P B R B P B G

X O M R E P

O S H

T O T I M O

D D & A , U S $ / b o e

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O S

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W P H E

S

M U

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A P

C

T L W S T S T

O

N B

L

P B

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G

P T

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C E

O

P T

T

E N I

R E

P

R D S

A

C O

P

I N P E

X

E O

G

P E M E

X

B

P

X O

M

T O

T

C V

X

I M

O

O X

Y

R

I L

A P

A

B R

Y

C H

K

C N

Q

D N

R

D V

N

E C

A

E R

F

F S

T

N F

X

O N G

C

P G

F

P W

T

P X

D

P X

P

E x p l o r a t i o n e x p e n s e , U S $ / b o e




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May 2, 2012


21

Exhibit 343yr avg F&D costs by company in 2011


Exhibit 353yr avg F&D costs 5 yr CAGR by company


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5

10

15

20

25

30

35

40

I N P E X R I L

T L W W P L

C N Q

N X Y

M R O E R F

B R Y T O T

S T L

S N P

A P A

P G F

O N G C E N I

X O M

O X Y

M U R

P W T

C E O H E S P X P N F X B G T L M P T R P T T

P B R

A P C F S T

D N R

E O G

P E M E X B P

P X D N B R E P H S E

O S H

C O P

E C A C V X

D V N

3 y r a v g F & D C o s t , U S $ / b o e

-30.0%

-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

R

I L

T L W W P C N

Q

X O

M

M R

O

B R

Y

T O

T

S N

P

P T

R

N X

Y

O N G

C

E R

F

O X

Y

A P

A

B

G

E N I

C E

O

S T L

P B

R

E O

G

N B

L

M U

R

D N

R

E C

A

H E

S

D V

N

P G

F

N F

X

P X

P

B

P

T L

M

H S

E

F S

T

A P

C

P E M E

X

C O

P

C H

K

C V

X

P T

T

I M

O

S T

O

I N P E

X

O S

H

R D S

A

P X

D

P W

T

R E

P

F & D C o s t C A G R




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May 2, 2012


22

Exhibit 363yr avg RRR by company in 2011


0%

50%

100%

150%

200%

250%

300%

O S H I M O S T O

C H K

R D S A P X P

E O G H S E

D N R N F X N B L

D V N

E C A B G P X D P T T

T L M

M U R P B R F S T

A P C H E S

C O P

P T R

C V X

C E O

X O M

P W T

N X Y

B R Y R E P

A P A

S N P E N I B P

O X Y P G F

M R O S T L

O N G C

W P L

T O T

P E M E X E R F

T L W C N Q R I L

I N P E X

3 y r a v g R R R




a s

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23

Disclosure Appendix

Ticker Table

Ticker Rat ing CUR

30 Apr 2012Closing

Price

Target

Price

TTMRel.

Perf.

EPS P/E

2011A 2012E 2013E 2011A 2012E 2013E Yield

857.HK (PetroChina) M HKD 11.76 12.00 19.0% 0.89 1.03 1.11 13.2 11.4 10.6 3.4%

883.HK (CNOOC) O HKD 16.54 21.00 -0.1% 1.88 1.89 2.18 8.8 8.8 7.6 2.7%

386.HK (SinoPec) M HKD 8.36 9.50 20.5% 0.98 1.10 1.26 8.5 7.6 6.6 2.9%

PTTEP.TB M THB 175.00 200.00 9.8% 13.44 14.78 18.90 13.0 11.8 9.3 2.9%

ONGC.IN M INR 264.20 290.00 0.2% 33.90 31.80 33.07 7.8 8.3 8.0 3.4%

RIL.IN O INR 739.95 900.00 -10.8% 62.00 61.20 71.30 11.9 12.1 10.4 1.5%

STO.AU M AUD 14.02 14.30 6.4% 0.51 0.68 0.77 27.5 20.6 18.2 2.6%

OSH.AU O AUD 7.35 8.70 17.9% 0.17 0.15 0.15 43.2 49.0 49.0 0.5%

WPL.AU M AUD 34.92 41.50 -11.8% 2.03 2.36 2.57 17.2 14.8 13.6 3.3%

2883.HK (COSL) O HKD 12.58 15.00 -4.5% 1.08 1.34 1.62 11.6 9.4 7.8 1.3%

REP.SM O EUR 14.45 20.50 -42.6% 1.80 1.56 1.68 8.0 9.3 8.6 8.0%

RDSA.LN M GBp 2193.00 2410.00 -11.0% 247.57 293.67 339.49 8.9 7.5 6.5 5.0%

RDSA.NA M EUR 26.87 28.00 -8.1% 3.31 3.47 4.01 8.1 7.7 6.7 4.8%

RDSB.LN M GBp 2246.50 2410.00 -12.0% 247.57 293.67 339.49 9.1 7.6 6.6 4.9%

RDSB.NA M EUR 27.60 28.00 -9.0% 3.31 3.47 4.01 8.3 8.0 6.9 4.7%RDS/A M USD 71.54 76.00 -13.3% 7.94 9.22 10.66 9.0 7.8 6.7 4.8%

RDS/B M USD 73.36 76.00 -14.6% 7.94 9.22 10.66 9.2 8.0 6.9 4.7%

TOT O USD 48.11 68.00 -17.0% 7.57 8.12 8.76 6.4 5.9 5.5 6.3%

E M USD 44.56 52.00 -3.2% 5.35 5.52 6.41 8.3 8.1 7.0 6.2%

BP M USD 43.41 50.00 -9.6% 7.49 6.18 7.38 5.8 7.0 5.9 4.4%

STO U USD 26.91 24.00 -6.1% 2.89 2.88 2.84 9.3 9.3 9.5 4.3%

STL.NO U NOK 152.80 135.00 -4.0% 16.50 16.20 15.99 9.3 9.4 9.6 4.3%

GALP.PL O EUR 11.89 19.00 1.0% 0.30 0.61 0.82 39.6 19.5 14.5 1.7%

BG/.LN O GBp 1450.50 2020.00 1.9% 86.57 94.74 110.60 16.8 15.3 13.1 1.0%

ENI.IM M EUR 16.77 20.00 1.2% 1.92 2.08 2.41 8.7 8.1 7.0 6.2%

BP/.LN M GBp 445.00 530.00 -6.9% 77.88 65.55 78.36 5.7 6.8 5.7 4.6%

FP.FP O EUR 36.07 51.00 -12.2% 5.44 6.10 6.59 6.6 5.9 5.5 6.3%

ECA M USD 20.94 18.00 -40.1% 1.62 0.98 0.27 12.9 21.4 77.6 3.8%

ECA.CN M CAD 20.18 18.00 -37.4% 1.60 0.98 0.27 12.6 20.6 74.8 3.8%

EOG O USD 109.81 127.00 -5.4% 3.79 5.17 7.66 29.0 21.2 14.3 0.6%TLM M USD 13.06 14.00 -48.3% 0.58 1.06 1.39 22.5 12.3 9.4 2.1%

CHK U USD 18.44 17.00 -47.8% 2.80 1.84 2.83 6.6 10.0 6.5 1.9%

APA O USD 95.94 129.00 -30.6% 11.83 10.93 13.39 8.1 8.8 7.2 0.7%

TLM.CN M CAD 13.08 14.00 -46.0% 0.57 1.06 1.39 22.8 12.3 9.4 2.1%

NBL O USD 99.32 125.00 0.7% 5.31 6.38 9.52 18.7 15.6 10.4 0.9%

DVN M USD 69.85 81.00 -25.8% 6.00 6.73 7.20 11.6 10.4 9.7 1.2%

APC M USD 73.21 92.00 -9.8% 3.37 3.76 4.34 21.7 19.5 16.9 0.5%

TLW.LN O GBp 1534.00 2150.00 5.9% 48.00 51.00 76.00 32.0 30.1 20.2 0.4%

OGZD.LI O USD 11.54 17.00 -3.0% 3.55 3.20 3.27 3.3 3.6 3.5 2.2%

MXAPJ 441.15 33.19 37.30 42.25 13.3 11.8 10.4 3.1%

MSDLE15 1062.69 95.95 100.63 112.47 11.1 10.6 9.4 4.1%

SPX 1397.91 95.92 105.00 118.09 14.6 13.3 11.8 2.0%

O – Outperform, M – Market-Perform, U – Underperform, N – Not Rated

* ONGC.IN, OGZD.LI estimates are financial year ended in March of FY2011A/FY2012E/FY2013E;RIL.IN estimates are financial year ended in March of

FY2011A/FY2012A/FY2013E.

Valuation Methodology

Asia-Pacific Oil & Gas

We value large cap oil and gas companies by identifying the forward price to book multiples they shouldtrade at based on returns on equity, long term earnings growth expectations, dividend payout ratio and cost




a s

May 2, 2012


24

of equity. Our starting point is that Fwd P/B = (ROE x PO) / (Ke – g), where is our estimates of ROE for2012, PO is the dividend payout ratio, Ke is the cost of equity, and g is the long term growth rates.

For Santos, Oil Search and Woodside, we believe an NAV approach is appropriate given a significant portion of their values are attached to future LNG projects. In calculating the NAV, we have assumed a

long term oil price of $90 (real).

We value RIL using a sum of the parts methodology at INR 990.

We value COSL using a sum of the parts method. We value COSL's drilling segment by NAV calculated based on the liquidation value of COSL's drilling rigs according to their Bernstein Complexity score. Wellservices, marine services and transportation and geophysical segments are valued using peers 2013EV/EBITDA multiples. On a SOTP basis, COSL is valued at HK$15/sh.

Our target prices for the European Integrated Oils are calculated by applying our estimates for 2012cashflow per share (CFPS) to a forward price-to-cashflow (P/CF) multiple. This P/CF multiple is generatedthrough the relationship, and historically strong correlation, between 12 month forward P/CF multiples andReturn on Average Capital Employed (ROACE) within the Integrated Oils group. Our calculation utilizesthis relationship and an estimated long term, through the cycle ROACE to generate the target P/CFmultiple. The price calculations for the Integrateds are summarized below. We use $90/bbl Brent and$3.75/mcf for US gas in 2012 and $115/bbl Brent and $4.25/mcf for US gas in 2013.

European Oil & Gas

Our target prices for the European Integrated Oils are calculated by applying our estimates for 2012cashflow per share (CFPS) to a forward price-to-cashflow (P/CF) multiple. This P/CF multiple is generatedthrough the relationship, and historically strong correlation, between 12 month forward P/CF multiples andReturn on Average Capital Employed (ROACE) within the Integrated Oils group. Our calculation utilizesthis relationship and an estimated long term, through the cycle ROACE to generate the target P/CFmultiple. The price calculations for the Integrateds are summarized below. We use $90/bbl Brent and$3.75/mcf for US gas in 2012 and $115/bbl Brent and $4.25/mcf for US gas in 2013.

North American Oil & Gas Exploration/ProductionOur valuation framework for our coverage of North American E&P oil & gas stocks is based on the strongcorrelation of P/CF multiple and the recycle ratio (cash flow per barrel divided by F&D costs). The recycleratio-implied target multiples are supplemented by company-specific catalysts, which are valuedindependently under a full-life cycle NPV methodology and applied in the form of incremental (positive ornegative) change. We adjust our target multiples to include the effects of growth, capitalization, capitalefficiency, and risk.

Our target price methodology for the US Oil Services is based upon P/E multiples applied to our 2013 EPSestimates. Our P/E multiples are determined by the relationship between relative P/E multiples and returnsrelative to the market for each Service stock. We then adjust the multiples for forecast earnings revisions.

Our target price for NOV is based upon a P/E multiple of 11.8x applied to our 2013 EPS estimate of $7.67.The P/E multiple is derived from our crude price and company backlog forecasts, and their historicalinfluence on the stock's multiple. Next we add the net cash balance of $7.12/share to arrive at our $98 target price.

Our valuation methodology for the Offshore Drillers combines an EV/EBITDA based approach and NetAsset Value. Our EV/EBITDA based target prices utilize 2013 forecasted EBITDA, as long duration




a s

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contracts cause the group to trade on forecasted cash generation further into the future. We apply a modeledgroup EV/EBITDA multiple, utilizing the year over year change in crude prices and the ratio of newbuildorders to working rigs, discounted by 10%. Next, we adjust the company specific multiple based upon fleetcomplexity. We tweak the multiple upward for Diamond (dividend), Ensco (operational quality) and

Seadrill (dividend), and tweak down for Transocean (Macondo liability). Our NAV incorporates both recentrig orders and transactions, and utilizes our rig complexity index to benchmark the global fleet. For Seadrill,we apply a 3x NAV multiple given fleet quality and growth, as justified by DCF. Given robust contract backlogs and rising rig rates, we also add the discounted free cash flow that each Driller will generate in2012 and 2013 to account for the potential growth in assets. Finally, we apply a 2:1 weighting to ourEV/EBITDA and NAV target prices, respectively, to calculate our published target price for each Driller.

Our Land Driller target price methodology combines two approaches. First, we calculate an appropriateEV/EBITDA multiple based upon a prediction model incorporating the year-over-year change incommodity prices, weighted by the US active rig count split and the Land Driller reinvestment rate. Themodel inputs are leading indicators for changes in land rig supply and demand. Second, we calculate the NAV including asset additions in 2011. To the NAV, we add the forecast free cash flow to be generatedduring 2012. Free cash flow is defined as operating cash flow less maintenance capex, which captures thecash available for asset growth and/or shareholder return. Finally, we take a simple average of the twomethodologies.

Risks

Asian Oils & Gas

CNOOC: Risks to our CNOOC price target include a decline in oil prices given the high correlation and

beta with oil and production problems which cause CNOOC to under deliver on their production targets.The change in strategy to become an integrated oil company through the purchase of parent company assetssuch as refineries and downstream assets could is also a potential risk.

PetroChina: downside risks to our PetroChina price target include a decline in oil prices given the highcorrelation and beta with oil, accelerated production decline at Daqing oil field and larger than expectedlosses in their refining division as a result of government fuel price subsidies. The introduction of resourcestax is a further downside risk. Better than expected refining margins and domestic gas prices as a result of policy changes represent an upside risk to our price target.

Sinopec: Risks to our Sinopec price target include an increase in oil prices given the large contributions oftheir downstream refining business to earnings. Other risks include accelerated production decline atShengli oil field, overseas M&A transaction with their parent company which results in value leakage fromthe company and the introduction of resource tax. Better than expected refining margins as a result of policychanges represent an upside risk to our price target.

COSL: Risks to our COSL price target include a decline in oil prices which could impact CNOOC's capex budget. International sanctions against Iran which limits the ability to CNOOC to operate in country orresults in the expropriation of assets. An equity rights issue to fund the purchase of deep water drillingequipment significantly in excess of 5billion shares currently expected in the market.

Reliance: Risks to our Reliance price target include a decline in oil prices given the high correlation and beta with oil and operational problems relating to Reliance as it ramps up Dhirubhai which result in asignificantly lower than expected production output. Sustained weakness in refining and petrochemicalmargins could be a further downside risk if economic recovery is slower than expected and demand growthremains weak.




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ONGC: Risks to our ONGC price target include delays in the deregulation of fuel prices in India whichwill increase crude oil under-recoveries as fuel demand continues to surge which will be negative for thestock. Other potential risks could be a major acquisition which transforms ONGC's international portfolioand will be positive for the stock.

Oil Search: Risks to our Oil Search price target include a decline in oil prices given the high correlationand beta with oil, or failure to progress their PNG LNG project in a timely way due to political or socialunrest, for which a significant amount of value is already embedded within the share price. Given the position of XOM in the project we believe that cost overruns and delays will be avoided.

Santos: Risks to our Santos price target include a significant change in oil prices given the high correlationand beta with oil. The possibility of cost overruns on this project also represents a possible risk.

Woodside: Risks to our Woodside price target include a decline in oil price as given the high correlationand beta with oil or delays in the construction of Pluto 1. Upside risk will be a major discovery in theCarnarvon basin over the next 6 months which transforms their ability to deliver the Pluto 2 LNG project.

PTTEP: Risks to our PTTEP price target include a negative outcome from the Australian enquiry into theuncontrolled release on the Montara project, which could result in reputational damage and financial penalties and further environmental claims if PTTEP are found to be at fault, and domestic unrest inThailand which results in an economic slowdown and a drop in demand for natural gas. Other potentialrisks include sanctions imposed in Myanmar by US or EU governments which impact operations or supplyof equipment in the country and delay to the start up of international projects which are key to underpinninggrowth over the next 3 years.

European Oil & Gas

For the European Majors, the greatest risk to our target prices is a significant decline in crude oil prices, asthe Majors commonly trade in line with commodity prices. Additionally, downward revisions to productionvolume targets could adversely impact share prices.

North American Oil & Gas Exploration/Production

The primary risk to our target prices for the North American E&Ps is lower than expected commodity prices over the next few years. For instance, oil prices could be negatively affected by slower than expectedeconomic growth, higher global supply, or faster switching to alternative fuel sources, which could depress product demand and drive oil prices below the marginal cost of supply. For natural gas, prices could benegatively affected by warm weather, continued healthy supply growth, lower coal-to-gas power switching,or higher LNG/pipeline net imports. Additionally, government policy and administration, including but notlimited to the BOEM/BSEE's pace of permitting or leasing, or changes to various countries' tax rates/fiscalterms, have the potential to positively or negatively affect the commodities and companies.

The primary risk to our target prices on the US Oil Services is a renewed economic recession, which woulddepress product demand and drive commodity prices below the marginal cost of supply. Should this occur,

the oilfield services market would likely become oversupplied, especially given healthy servicereinvestment today. Under this scenario, margins would remain depressed for the foreseeable future, likelydriving underperformance by the group. For Halliburton specifically, their involvement in providing cementfor the Macondo well may expose them to significant fines and penalties, which if levied, could yieldunderperformance for the stock.

The primary risk to our target prices on the Drillers is a cessation of global economic growth, which would precipitate crude prices trading below the marginal cost of supply. Should this occur, utilization in the rig




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market would fall meaningfully, as the drop off in demand would be compounded by capacity additions.This would drive spot rates toward cash costs and cause the group to underperform the market.Alternatively for the Offshore Drillers, an elongated deepwater drilling moratorium in the US Gulf ofMexico would also spur a sharp drop in deepwater rig rates as well as earnings power for most of the

Offshore Drillers under coverage given their earnings exposure to this market.



SRO REQUIRED DISCLOSURES

∑ References to "Bernstein" relate to Sanford C. Bernstein & Co., LLC, Sanford C. Bernstein Limited, Sanford C. Bernstein (Hong Kong)Limited, and Sanford C. Bernstein (business registration number 53193989L), a unit of AllianceBernstein (Singapore) Ltd. which is alicensed entity under the Securities and Futures Act and registered with Company Registration No. 199703364C, collectively.

∑ Bernstein analysts are compensated based on aggregate contributions to the research franchise as measured by account penetration,productivity and proactivity of investment ideas. No analysts are compensated based on performance in, or contributions to, generatinginvestment banking revenues.

∑ Bernstein rates stocks based on forecasts of relative performance for the next 6-12 months versus the S&P 500 for stocks listed on theU.S. and Canadian exchanges, versus the MSCI Pan Europe Index for stocks listed on the European exchanges (except for Russiancompanies), versus the MSCI Emerging Markets Index for Russian companies and stocks listed on emerging markets exchanges outsideof the Asia Pacific region, and versus the MSCI Asia Pacific ex-Japan Index for stocks listed on the Asian (ex-Japan) exchanges - unlessotherwise specified. We have three categories of ratings:

Outperform: Stock will outpace the market index by more than 15 pp in the year ahead.

Market-Perform: Stock will perform in line with the market index to within +/-15 pp in the year ahead.

Underperform: Stock will trail the performance of the market index by more than 15 pp in the year ahead.

Not Rated: The stock Rating, Target Price and estimates (if any) have been suspended temporarily.

∑ As of 04/30/2012, Bernstein's ratings were distributed as follows: Outperform - 41.1% (1.5% banking clients) ; Market-Perform - 49.3%(0.4% banking clients); Underperform - 9.6% (0.0% banking clients); Not Rated - 0.0% (0.0% banking clients). The numbers in parenthesesrepresent the percentage of companies in each category to whom Bernstein provided investment banking services within the last twelve

(12) months.

∑ Neil Beveridge maintains a long position in BP PLC (BP).

∑ Accounts over which Bernstein and/or their affiliates exercise investment discretion own more than 1% of the outstanding common stock ofthe following companies RDSB.LN / Royal Dutch Shell PLC, RDSB.NA / Royal Dutch Shell PLC, BG/.LN / BG Group PLC, BP/.LN / BPPLC.

∑ The following companies are or during the past twelve (12) months were clients of Bernstein, which provided non-investment banking-securities related services and received compensation for such services BP / BP PLC, BP/.LN / BP PLC.

∑ An affiliate of Bernstein received compensation for non-investment banking-securities related services from the following companies BP /BP PLC, BP/.LN / BP PLC.

∑ This research publication covers six or more companies. For price chart disclosures, please visit www.bernsteinresearch.com, you canalso write to ei ther: Sanford C. Bernstein & Co. LLC, Director of Compliance, 1345 Avenue of the Americas, New York, N.Y. 10105 orSanford C. Bernstein Limited, Director of Compliance, 50 Berkeley Street, London W1J 8SB, United Kingdom; or Sanford C. Bernstein(Hong Kong) Limited, Director of Compliance, Suites 3206-11, 32/F, One International Finance Centre, 1 Harbour View Street, Central,

Hong Kong, or Sanford C. Bernstein (business registration number 53193989L) , a unit of AllianceBernstein (Singapore) Ltd. which is alicensed entity under the Securities and Futures Act and registered with Company Registration No. 199703364C, Director of Compliance,30 Cecil Street, #28-01 Prudential Tower, Singapore 049712.

12-Month Rating History as of 04/30/2012

Ticker Rating Changes

2883.HK O (RC) 04/17/12 M (IC) 11/29/11

386.HK M (RC) 03/09/12 O (RC) 08/23/11 M (IC) 06/29/09

857.HK M (RC) 04/20/11

883.HK O (RC) 12/01/11 M (RC) 08/23/11 O (IC) 06/29/09

APA O (IC) 05/13/11 O (DC) 08/02/10

APC M (IC) 05/13/11 O (DC) 08/02/10

BG/.LN O (IC) 01/22/09

BP M (IC) 08/03/10

BP/.LN M (IC) 08/03/10

CHK U (IC) 05/13/11 O (DC) 08/02/10

DVN M (IC) 05/13/11 M (DC) 08/02/10

E M (RC) 03/09/12 O (IC) 08/03/10

ECA M (IC) 05/13/11 O (DC) 08/02/10

ECA.CN M (IC) 05/13/11 O (DC) 08/02/10

ENI.IM M (RC) 03/09/12 O (IC) 08/03/10

EOG O (RC) 11/02/11 M (IC) 05/13/11 O (DC) 08/02/10

FP.FP O (IC) 08/03/10

GALP.PL O (RC) 05/26/10

NBL O (IC) 05/13/11

OGZD.LI O (RC) 07/16/09



ONGC.IN M (RC) 11/17/09

OSH.AU O (IC) 06/29/09

PTTEP.TB M (IC) 06/11/10

RDS/A M (RC) 03/09/12 O (IC) 08/03/10

RDS/B M (RC) 03/09/12 O (IC) 08/03/10

RDSA.LN M (RC) 03/09/12 O (IC) 08/03/10

RDSA.NA M (RC) 03/09/12 O (IC) 08/03/10

RDSB.LN M (RC) 03/09/12 O (IC) 08/03/10

RDSB.NA M (RC) 03/09/12 O (IC) 08/03/10

REP.SM O (IC) 03/19/12

RIL.IN O (RC) 01/19/11

STL.NO U (RC) 04/20/11

STO U (RC) 04/20/11

STO.AU M (RC) 04/20/11

TLM M (RC) 08/02/11 U (IC) 05/13/11 O (DC) 08/02/10

TLM.CN M (RC) 08/02/11 U (IC) 05/13/11 O (DC) 08/02/10

TLW.LN O (IC) 01/22/09

TOT O (IC) 08/03/10

WPL.AU M (RC) 08/23/11 O (RC) 11/17/09

Rating Guide: O - Outperform, M - Market-Perform, U - Underperform, N - Not Rated

Rating Actions: IC - Initiated Coverage, DC - Dropped Coverage, RC - Rating Change

OTHER DISCLOSURES

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CERTIFICATIONS

∑ I/(we), Neil Beveridge, Ph.D., Bob Brackett, Ph.D., Oswald Clint, Ph.D., ACA, Scott Gruber, CFA, Senior Analyst(s)/Analyst(s), certify thatall of the views expressed in this publication accurately reflect my/(our) personal views about any and all of the subject securities or issuersand that no part of my/(our) compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views in thispublication.

Approved By: CDK

Copyright 2012, Sanford C. Bernstein & Co., LLC, Sanford C. Bernstein Limited, Sanford C. Bernstein (Hong Kong) Limited, and AllianceBernstein (Singapore) Ltd., subsidiariesAllianceBernstein L.P. ~1345 Avenue of the Americas ~ NY, NY 10105 ~212/756-4400. All rights reserved.

his publication is not directed to, or intended for distribution to or use by, any person or entity who is a citizen or resident of, or located in any locality, state, country or other jurisdiction where such distribution, pubvailability or use would be contrary to law or regulation or which would subject Bernstein or any of their subsidiaries or affiliates to any registration or licensing requirement within such jurisdic tion. This publication is basublic sources we believe to be reliable, but no representation is made by us that the publication is accurate or complete. We do not undertake to advise you of any change in the reported information or in the opinionshis publication was prepared and issued by Bernstein for distribution to eligible counterparties or professional clients. This publication is not an offer to buy or sell any security, and it does not constitute investment, legdvice. The investments referred to herein may not be suitable for you. Investors must make their own investment decisions in consultation with their professional advisors in light of their specific circumstances. The vestments may fluctuate and investments that are denominated in foreign currencies may fluctuate in value as a result of exposure to exchange rate movements Information about past performance of an investmen

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