DB European Majors Upstream Cost Structure

8/2/2019 DB European Majors Upstream Cost Structure

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Europe United KingdomOil & Gas

24 February 2009

European

Integrated Oils

The cost of producing oil

Lucas Herrmann, ACAResearch Analyst

(44) 20 754 73636

[email protected]

Elaine Dunphy, ACAResearch Analyst

(44) 207 545 9138

[email protected]

Adam Sieminski, CFAStrategist

(1) 202 662 1624

[email protected]

Deutsche Bank AG/London

All prices are those current at the end of the previous trading session unless otherwise indicated. Prices are sourced from local

exchanges via Reuters, Bloomberg and other vendors. Data is sourced from Deutsche Bank and subject companies. Deutsche

Bank does and seeks to do business with companies covered in its research reports. Thus, investors should be aware that the firm

may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single

factor in making their investment decision. Independent, third-party research (IR) on certain companies covered by DBSI's researchis available to customers of DBSI in the United States at no cost. Customers can access IR at

http://gm.db.com/IndependentResearch or by calling 1-877-208-6300. DISCLOSURES AND ANALYST CERTIFICATIONS ARE

LOCATED IN APPENDIX 1.

FITT Research

Fundamental, Industry, Thematic,Thought LeadingDeutsche Bank Company Research'sResearch Committee has deemed thiswork F.I.T.T for investors seeking

differentiated ideas. Here our Europeanintegrated oil team provides insights intothe cash and marginal costs of oilproduction. It concludes that against thebackdrop of a faltering oil price it is notjust demand that is at risk of significantdisappointment; at current oil pricesproject deferrals and an acceleration inthe 4-6% underlying pace of naturaldecline stand to drive a more rapid thanexpected correction in the supply/demandbalance for crude oil.

Fundamental: The risks around future oilsupply have risen sharply

Industry: Breaking down the global cost

curveThematic: Cash economics work; fullcycle economics dont

Thought leading: Oil is a wasting asset

In the short term, there is no magicbullet; non-OPEC keeps producing

Company

GlobalMarketsResea

rch

Cash production costs 2009 (opex plus royalties) across major production

regions ($/bbl)

0

5

10

15

20

25

30

0 2922 5844 8766 11688 14610 17532 20454 23376 26298 29220 32142 35064 37986 40908 43830 46752 49674 52596 55518 58440 61362

Cumulative 2009 oil production kb/d

OPEX plus royalties $/bbl

UAESaudi Arabia

Russia

Iraq

Nigeria

AlgeriaMexico

LibyaAngola

Iran

KuwaitCanadaSands

Alaska

China

UK

Kazakhstan

Norway

Azerbaijan

USGoM

Venezuela

Brazil

Average cas h costs among top producers $7.70/bbl

(or $12.50/bbl excluding OPEC countries)

Source: Wood Mackenzie; Deutsche Bank


2/39


3/39

Europe United KingdomOil & Gas

24 February 2009

European Integrated Oils

The cost of producing oil

Lucas Herrmann, ACAResearch Analyst

(44) 20 754 73636

[email protected]

Elaine Dunphy, ACAResearch Analyst

(44) 207 545 9138

[email protected]

Adam Sieminski, CFAStrategist

(1) 202 662 1624

[email protected]

Fundamental, Industry, Thematic, Thought LeadingDeutsche Bank Company Research's Research Committee has deemed this workF.I.T.T for investors seeking differentiated ideas. Here our European integrated oilteam provides insights into the cash and marginal costs of oil production. Itconcludes that against the backdrop of a faltering oil price it is not just demandthat is at risk of significant disappointment; at current oil prices project deferralsand an acceleration in the 4-6% underlying pace of natural decline stand to drive amore rapid than expected correction in the supply/demand balance for crude oil.

Deutsche Bank AG/London

All prices are those current at the end of the previous trading session unless otherwise indicated. Prices are sourced from local

exchanges via Reuters, Bloomberg and other vendors. Data is sourced from Deutsche Bank and subject companies. Deutsche

Bank does and seeks to do business with companies covered in its research reports. Thus, investors should be aware that the firm

may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single

factor in making their investment decision. Independent, third-party research (IR) on certain companies covered by DBSI's researchis available to customers of DBSI in the United States at no cost. Customers can access IR at

http://gm.db.com/IndependentResearch or by calling 1-877-208-6300. DISCLOSURES AND ANALYST CERTIFICATIONS ARE

LOCATED IN APPENDIX 1.

FITT Research

Top picksTotal SA (TOTF.PA),EUR37.75 Buy

Royal Dutch Shell Plc (RDSb.L),GBP1,597.00 Buy

Demand collapses

84.5

85.0

85.5

86.0

86.5

87.0

87.5

88.0

88.5

89.0

Aug-07

Sep-07

Oct-07

Nov-07

Dec-07

Jan-08

Feb-08

Mar-08

Apr-08

May-08

Jun-08

Jul-08

Aug-08

Sep-08

Oct-08

Nov-08

Dec-08

Jan-09

Feb-09

mb/d 2008 Fo recast 2009 Fo recast

Source: IEA

Oil is a declining asset (mb/d)

60

65

70

75

80

85

90

95

2008 2009 2010 2011 2012 2013 2014 2015

mb/d Onstream Reserves growth Under development

Probable Other discoveries Yet-to-find

Source: Wood Mackenzie

UK cost curve ($/bbl)

0

10

20

30

40

50

60

70

80

90

100

3 73

242

457

989

1078

1321

1558

1604

1769

1821

1903

2198

2376

2622

2813

2926

3333

3368

3492

3767

3968

4117

4194

4331

4380

4693

4810

4851

5007

5112

5324

5376

5414

5459

5592

5642

5721

5778

$/bbl

132kb/d and413mb

uneconomicbelow $30/bbl

70kb/d and

272mb

uneconomic

below $40/bbl

Cumulative resource mbbls

Buzzard ($6.1/bbl)

Schiehallion ($12.2/bbl)

Forties ($22.2)

UK- Average OPEX cost $14.19/bbl

132kb/d and 413mb uneconomic below $30/bbl


Source: Wood Mackenzie: Deutsche Bank estimates

Non-OPEC decline rates 2000-8E

0% 5% 10% 15% 20% 25%

FSU

China

Latin America

US Onshore

Canada

Other Asia

Africa

Middle East

Non-OPEC average

Norway

Australia

US Offshore

UK

Source: IEA

Fundamental: The risks around future oil supply have risen sharplyThe abject collapse in world economies has seen the markets previous obsessionwith supply quickly switch to one which at times seems similarly myopic arounddemand. Yet in markets where the surge in costs and taxes in recent years havemeant that the price required to extract crude oil has dramatically risen, our senseis that it is not just global demand estimates that are at risk of reduction.

Industry: Breaking down the global cost curveUsing Wood Mackenzies extensive database we have sought to obtain a betterunderstanding of todays cash costs of oil production as well as the oil price nowrequired for growth investments to prove economic. In doing so we have lookednot just at average cash costs by country but also the cost curves within the moremature, higher cost oil producing regions themselves. We also assess the full-cycle economics of investing in todays growth regions.

Thematic: Cash economics work; full cycle economics dont

Our analysis suggests that the current cash-breakeven cost for non-OPEC supplyis c.$12/bbl rising to c.$15/bbl in the higher cost, more mature basins of the UK,Norway, Alaska and (because of extraction taxes) Russia. Unsurprisingly, Canadasoil sands represent the high cost barrel requiring an average WTI oil price of atleast $28/bbl for cash-breakeven. We estimate that, excluding the US onshore forwhich granular data is limited, under 1mb/d of production would be operating at acash loss given an oil price of c.$30/bbl. Short term oil prices can fall further.

Thought leading: Oil is a wasting assetOil is, however, a wasting asset and from examination of growth provinces andindeed the impact of past cycles on production from mature basins, a supplyresponse seems patently apparent. We estimate current costs dictate a price of atleast $60/bbl is now necessary to justify growth investment in Angola, the GoM,Brazil and Nigerias deepwater. Moreover, at least 1mb/d of existing supply nowappears at risk as decline rates accelerate over the next 1-2 years.

In the short term, there is no magic bullet; non-OPEC keeps producing

Overall, our conclusion is that in the short term oil prices would likely have to fallto $20/bbl and below before non-OPEC was at risk of shutting-in material supply.However, with investment now falling, not least as the financial crisis impacts a farmore significant independent sector, the downside risks to supply forecasts areincreasing; and not just in the medium term. Whilst this analysis is notconcentrated on the corporates against the weak oil price backcloth it is clearly thelower-cost producers whose earnings should prove better protected. Amongst themajors Total and BG Group look by far the best placed.


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24 February 2009 Oil & Gas European Integrated Oils

Page 2 Deutsche Bank AG/London

Table of Contents

Executive Summary........................................................................... 3Oil is an asset in decline.............................................................. .............................................. 3Recommendations ................................................... .......................................................... ....... 4

Valuation .............................................. ....................................................... .............................. 4Risks ..................................................... ...................................................... .............................. 4Oil is a wasting asset ........................................................................ 5Not only demand is pressured in falling price environment ...................................................... 5Raiding the database.... ....................................................... ...................................................... 7The high level view on OPEX by country ............................................................. ..................... 8Where is cash breakeven? .............................................................. 11Unsurprisingly, the more mature the higher the cost ............................................................. 11The UK - We see limited risk of shut-ins at prices above $30/bbl ...........................................11Norway less vulnerable than the UK but ........................................................... ........... 12Alaska Economics comfortable at a price down to $20/bbl .................................................13Russia Domestic no problem; exports a different story ....................................................... 14Canada oil sands simply high cost (but gas matters a lot)....................................................14US Onshore History says 1mb/d at risk already .......................................................... ......... 15Mature basins: Decline rates to accelerate? ................................. 16The impact on growth in mature regions is likely negative .....................................................16The implications for growth regions ............................................. 19Investment is about costs as much as price...........................................................................19What drops out at least $60/bbl is needed for a growth barrel ............................................20Brazil avg. breakeven $42/bbl (but new projects different story) ......................................... 21Gulf of Mexico low cash cost but growth vulnerable...........................................................22Nigeria high costs and riskier operating environment ..........................................................23Angola it simply doesnt work at current costs and prices...................................................24Where to from here for costs?........................................................ 26Are we seeing light on the horizon?......................................................... ............................... 26Cost and the companies ................................................................. 30The pressure is on................................................... ...................................................... ...... 30


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Deutsche Bank AG/London Page 3

Executive Summary

Oil is an asset in decline

Faced by a collapse in global growth the focus in world oil markets has rapidly shifted fromconstraints on supply to the diminution of demand, with all its implications for the crude oil

price. Yet in an industry which needs constant investment if underlying production declines of

5-7% p.a. are to be averted and in which costs and taxes have surged, our sense is that the

risks to supply estimates both in the short and medium term have increased meaningfully as

project economics have further faltered.

With the oil price collapsing and the economics of future production deteriorating, in this note

we have used our research partner Wood Mackenzies country-by-country database to gain a

better understanding of the potential impact of the current global turmoil on oil supply in both

the short and medium term. In an effort to assess the volume of current production that may

be vulnerable to falling oil prices, our analysis starts with a review of the cash costs (opex

plus royalties) of extracting oil within the main producing regions before reviewing the risks

to current production in mature basins. With the costs of developing new fields substantially

increased and new investment decisions sharply reduced we also look at what oil price

would be required for projects in todays growth markets, not least Angola, Brazil, the US

Gulf of Mexico and Nigerias deepwater to deliver an economic return. Finally we consider

the composition and likely direction of costs going forward and which European companies

look best placed to cope against a backcloth of sharply lower oil prices.

Some simple observations

Clearly in reading this report investors need to recognize that costs are dynamic. As such,

data that is valid today may well prove materially different tomorrow. Nevertheless, having

said this we believe that four simple observations can be made from our analysis:

On average the cash cost of extracting a barrel of oil in the mature and higher cost non-

OPEC markets of Russia, the UK, Norway and Alaska is around $15/bbl. As such it issignificantly below the current oil price. Only in the Canadian oil sands do average cash

costs of circa $28/bbl approach the prevailing $35-40/bbl WTI oil price.

Looking at the marginal cash cost curves within these mature regions we estimate that

at an oil price of US$30/bbl a modest 0.7mb/d of production would be cash negative and

this including 0.4mb/d of oil sands production. However, at a $20/bbl WTI oil price this

rises towards a material 3.5mb/d. We see this production as vulnerable to shut-in.

Figure 1: Oil production requires steady investment to

avoid decline

Figure 2: Cash costs of production (opex plus royalties)

in the major oil producing regions ($/bbl)

60

65

70

75

80

85

90

95

2008 2009 2010 2011 2012 2013 2014 2015



0

5

10

15

20

25

30

0 2922 5844 8766 116881461017532 20454 23376 26298 292203214235064 379864090843830 467524967452596 555185844061362



UAESaudi Arabia

Russia

Iraq

Nigeria

AlgeriaMexico

LibyaAngola

Iran

KuwaitCanadaSands

Alaska

China

UK

Kazakhstan

Norway

Azerbaijan

USGoM

Venezuela

Brazil

Average cash costs among top prod ucers $7.70/bbl

(or $12.50/bbl excluding OPEC countries)

Source: Wood Mackenzie GOSS, Deutsche Bank Source: Wood Mackenzie GEM, Deutsche Bank estimates


6/39



Past oil price collapses have been associated with a sharp increase in the decline rates

observed in mature basins. Using past production curves as a proxy we estimate that as

much as 1.5mb/d of supply could be lost to accelerated decline over the next two years

within the US onshore, Alaska, Canada, the UK, Norway and Russia. We believe that little

of this is allowed for in current supply estimates.

Within the growth regions, the rise in costs and taxes in recent years suggests that theaverage oil price necessary to achieve a 15% IRR in Angola is now $68/bbl, $62/bbl in

the US GoM, $60/bbl in deep water Nigeria and around $60/bbl in Brazil (although this

depends heavily on the scale of the development considered). Whilst this is in line with

our estimate of the companies long run planning price, against the current economic

backdrop it comes as little surprise that 2008 saw fewer final investment decisions

(FIDs) taken than in any year since 1989 despite the surge in the oil price.

Recommendations

Whilst this analysis is not concentrated on the corporates, against the weak oil price

backcloth we would highlight that it is the low cost producers whose earnings should be

better protected through this period. Amongst the Europeans, Total SA and BG Group look

especially well placed given production costs that are around 40% below the average. Totalshould also gain given its greater exposure to oil price related production taxes which we

expect to be in decline whilst BG Groups exposure to natural gas markets, many of which

are fixed price, should provide for greater revenue stability. Elsewhere, after several years of

steady production decline Shell is now very much the high cost producer with technical costs

of $23/bbl against a sector average of $18/bbl and production costs that at $8.30/bbl are

some 25% above the average. With an estimated 1mb/d of relatively low cost production

due on-stream over the next 3 years we would, however, expect this trend to reverse.

Valuation

We use a multitude of earnings and cash flow valuation techniques to value the oils. These

include P/E relatives, cash return on capital analysis (CROCI) and discounted cash flowmodels amongst others. On the basis of our current forecasts we believe that we are now

approaching the trough of the current price cycle. Whilst this implies a sharp decline in

profitability it also suggests that the sector should trade towards the top end of its P/E range.

We target a fair sector P/E multiple on average of around 14x prospective 2009 earnings

estimates, our view being that this represents a sensible 10-15% discount to past peak

multiples (c16x) and thereby allowing for some potential further slippage in the crude oil

price. Similarly, on cash return (CROCI) metrics, our analysis suggests that, with the multiple

placed on the sectors capital now trading below 1x invested capital against its long run

average of 1.3x the shares offer significant absolute upside. Importantly, with the sector

offering a secure, dollar oriented 7% plus dividend yield we also believe that at current share

prices downside is limited. All told, on absolute basis we believe we are now at a floor.

Risks

As ever, forecasting for an operationally geared sector through a downturn in the cycle is

fraught with difficulties - not least assessing the impact of rising costs on business

profitability at a time of falling prices and volumes. This challenge aside, the key risk to our

estimates remains the prospect for commodity prices and crude oil in particular. Our

forecasts are consequently vulnerable to a significant move in the price of crude about our

$45/bbl oil price estimate. Other risks include material changes to our expectations for

volume output that could arise as a consequence of a worse than anticipated demand

outlook. As a sector whose functional currency is the US dollar, a sharp fall in that currency

would significantly undermine asset values and dividend payments.


7/39



Oil is a wasting asset

Not only demand is pressured in falling price environment

After five years of at times myopic concern on the ability of oil markets to meet the globaleconomys steadily increasing need for crude oil, the abject collapse in world economic

growth associated with the current financial crisis has understandably driven a complete

reversal in market focus.

As expectations for economic growth within mature and emerging economies have

dramatically deteriorated, so too the seven year bull market in the crude oil price has

unwound. Faced with a surge in excess capacity as demand has weakened, the price of

crude oil has sunk falling by a remarkable 70% in the space of little over five months.

Where is the demand floor?

Given the near total lack of a visible demand floor it is of little surprise that the market should

at times appear as myopic on the downside implications for the crude oil price as it was onthe potential for upside implied by the earlier supply constraints. Glance at the pace of

change in the IEAs forecasts for demand in 2009 or the build in days of forward demand

cover, as depicted in the charts below, and the markets reasoning is all too understandable.

With economies continuing to deteriorate, we quite simply do not know where the demand

floor lies at this time.

OPEC cuts but is doing so in the dark

Typically, at times such as these efforts by OPEC to contain supply would be expected to

bring the market back into balance and help to establish an oil price floor. However, in the

current market we believe that OPECs success at stabilizing the oil price, in the short term at

least, is far from certain. For while the member countries may endeavour to underpin crude

oil markets by espousing their ambitions for the oil price and supporting their statements by

curbing their collective production, in the absence of some firm indication that global demand

is stabilizing and that stock levels are no longer building it remains unclear what level of

supply OPEC actually needs to cut towards before it can bring the market back into balance.

Put simply if the market doesnt know where the demand floor lies, how can it sensibly

regain confidence that OPECs supply-side actions are sufficient?

Figure 3: IEA demand estimates for 2009 have fallen by

2.9mb/d in five months

Figure 4: IEA OECD data suggests 300mb excess

inventory (or 3.5days global supply)

84.5

85.0

85.5

86.0

86.5

87.0

87.5

88.0

88.5

89.0

Aug-07

Sep-07

Oct-07

Nov-07

Dec-07

Jan-0

8

Feb-0

8

Mar-0

8

Apr-0

8

May-0

8

Jun-0

8

Jul-0

8

Aug-0

8

Sep-0

8

Oct-08

Nov-0

8

Dec-0

8

Jan-0

9

Feb-0

9

mb/d 2008 Forecast 2009 Forecast

49

50

51

52

53

54

55

56

57

58

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2003-7 range 2008 2007Days

Source: IEA data; Deutsche Bank Source: IEA data; Deutsche Bank


8/39



With the cuts driving an unnerving rise in spare capacity

In the meantime as idled capacity rises towards past peaks, the apparent build does little to

foster a view that the prospects for crude markets are improving (as illustrated by Figure 5

below). Rather it raises the question of how long it might take for crude markets to move

back into balance once economic recovery commences and provides little confidence that

the spot crude price has reached its near term floor.

Figure 5: OPEC spare capacity excluding that in Venezuela, Iraq, Nigeria and Iran looks

set to move towards 6mb/d on current demand/supply estimates

-1.00

0.00

1.002.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

Sep-00

Mar-01

Sep-01

Mar-02

Sep-02

Mar-03

Sep-03

Mar-04

Sep-04

Mar-05

Sep-05

Mar-06

Sep-06

Mar-07

Sep-07

Mar-08

Sep-08

Mar-09

Sep-09

Spare Spare ex Nig, Iraq, Ven, Iran

On current target of 25.0mb/d, effective spare capacity

ex VINI rises to 5.8mb/d o f w hich 3.5mb/d is in S.Arabia

(or 8mb/d i n total). Ex VINI this suggests 7% worl d

demand is available (or 9% on a gr oss basis)

Spare = 11% world supply

Source: IEA data; Deutsche Bank estimates

Undoubtedly, it is OPEC that plays the key role of balancing oil supply and demand. Yet

whilst substantial, in reality OPECs 36mb/d of crude oil production capacity only represents

40% of the global industrys c.90mb/d of gross production capacity for crude oil and natural

gas liquids (NGLs). As important in determining a potential oil price floor is therefore to

assess what is likely to happen to non-OPEC supply both in the near and medium term i.e.

what is the scope for non-OPEC supply to prove weaker than anticipated.

At what price does non-OPEC move towards cash loss?

Historically, non-OPEC producers have long perceived that it is upon OPEC that the role of

balancing short-term supply and demand imbalances falls. As long as non-OPECs production

is economic on a cash basis, non-OPEC will not cut. Capacity will not be idled. Yet to the

extent that the oil price falls to levels at which its production is no longer economic on a cash

basis, action will most likely be taken.

In the very short term, the key question for non-OPEC supply reductions and with them crude

oil price support this has to be at what oil price is non-OPEC production at risk of shut-ins onthe basis that production is no longer economic on a cash basis?

Oil is a wasting asset

Yet perhaps as importantly, and in contrast with many capital intensive industries, production

of oil faces a natural rate of decline. As illustrated in Figure 7 this is estimated by the IEA to

run at around 5-7% (or 4-6mb/d) per annum, with the decline rates in mature regions such as

the UK and Norway typically running at higher rates. As such, even if production within non-

OPEC is sustained in the short term, if a collapsing oil price (or escalation in costs) prohibits

investment our expectation would be that, in much the same way that supply markets

tightened through the start of this decade, faltering supply would eat into any short term

build in space capacity relatively quickly. This is well illustrated by the below aggregation of


9/39



Wood Mackenzies estimates for global oil production which suggest that, absent

investment, todays global oil production base of 84mb/d will have declined to nearer 75mb/d

by 2015. Indeed, given that in recent years industry production in mature OECD markets has

increasingly been dominated by smaller E&P companies, many of whom are now suffering

from a lack of liquidity given the credit crisis, it would seem reasonable to assume that

decline rates in mature provinces are almost certain to accelerate.

Figure 6: Oil Production is declines naturally over time.

New developments are required for sustenance

Figure 7: Non-OPEC decline rates have averaged 7%

over the 2000-2008 period led by mature regions

60

65

70

75

80

85

90

95

2008 2009 2010 2011 2012 2013 2014 2015



0% 5% 10% 15% 20% 25%

FSU

China

Latin America

US Onshore

Canada

Other Asia

Afri ca

Middl e East

Non-OPEC average

Norway

Austr alia

US Offshore

UK

Source: Wood Mackenzie GOSS; Deutsche Bank Source: IEA data on-stream assets only and excluding ramp up; Deutsche Bank

Raiding the database

With these points in mind we have reviewed Wood Mackenzies database of global oil

projects in an attempt to gain a better understanding of the cost dynamics of the industry on

a country-by-country basis. In doing so we have not only sought to obtain some good idea of

the relative positioning of opex and other cash costs (e.g. royalties) within the different

countries; for the more mature regions we have also attempted to look at the cost curveswithin the countries themselves, our objective being to assess how much production may

prove vulnerable to shut-ins at different oil prices. Looking further out we have then gone on

to use Wood Mackenzies estimates for opex and capex per barrel to assess the economics

of investment in todays growth markets of Brazil, Angola, the US GoM and Nigeria with a

view to assessing whether or not development projects in these regions continue to deliver

sensible economics at current oil prices.

Clearly, given the dynamic nature of costs in this industry, most particularly at this time, it

need be appreciated that costs are something of a moving feast. Assuming that the oil price

remains at its current subdued level for some time and that the limited availability of credit

persists we have little doubt that both capital and operating costs will fall materially. Similarly,

against a backcloth of lower oil prices we expect taxation to decline as host nations look toencourage investment. Indeed, there are already signs of this, be it the reduction of export

taxes in Kazakhstan or proposed changes to mineral extraction taxes in Russia.

Equally, as is evident from the summary charts depicted on pages 9 & 10, Wood Mackenzie

does not have data on all sources of crude oil production. In particular, the disparate nature of

the 1-2mb/d or so that is produced by small ma & pa type operators in the US Onshore

together with that for other typically mature provinces (for example, Romania) is not available.

Because much of this is known to break-even at a higher cash cost (a significant proportion of

US onshore requires prices of over $50/bbl) this suggests that the vulnerability of supply to a

falling oil price is probably greater than our analysis suggests. Either way, as discussed over

the following pages what is clear to us at this time is that globally, at an oil price below


10/39



US$30/bbl at least 1mb/d becomes cash negative given current industry costs. This is to say

nothing of the acceleration in decline rates that seems increasingly inevitable given that many

supply projects are quite clearly uneconomic in todays price and cost environment not to

mention the additional challenge that the credit crisis has presented for an industry that

through the boom years has become increasingly dependent upon cash strapped smaller

companies and NOCs for its production.

The high level view on OPEX by country

So what are the higher cash cost regions? Over the following two pages we depict our

summary analysis of Wood Mackenzies country-by-country database showing both an

estimate of the weighted average cash operating cost by country and the barrels of 2009

crude production that each country represents. Using our understanding of tax and fiscal

terms we then present the same data but with the operating cash cost grossed up for any

royalties, severance or extraction taxes. Note that, because of the volume of data we have

also split the countries by scale of production, the charts thereby representing the cash

opex and cash opex plus taxes for major and then smaller producers.

Building a cost curve for 75mb/d of world productionIn total, our analysis can be seen to capture approximately 75mb/d of the worlds current

86mb/d of oil production capacity. Given that Wood Mackenzies database captures around

82mb/d of current oil production in part this difference reflects our decision not to incorporate

data for a large number of the smaller oil producing nations, the production and operating

costs of which are often relatively small, or our exclusion of gas dominated projects and their

associated NGL production. About 30-40% or 4m/d of the shortfall is, however, reflective of

production in countries or from producers that are not captured by the Wood Mackenzie data

set. As we have mentioned not least amongst these are the significant number of ma & pa

type producers in North America which whilst individually small, collectively account for close

to 1mb/d of price sensitive oil production.

Globally average cash costs in non-OPEC are around $11-12/bbl ($8/bbl cum OPEC)

As to the high level results, from the data that is available what is immediately clear is that,

even including the Canadian oil sands, no single region suffers average cash production costs

that would suggest that it is uneconomic at the current $40/bbl oil price. Indeed, it is of note

that on average cash costs excluding OPEC territories average around $12.50/bbl or closer to

$7.70/bbl if OPEC members are included. In other words industry production would appear to

be robust down to much lower crude oil prices than may at first be presumed and only at an

oil price of $15/bbl and below does a very significant proportion of production move into loss

on a cash basis. As such, one simple conclusion from this analysis is that, with the possible

exception of the oil sands, there is no silver bullet or single source of material oil production,

the shut-in of which might support the current $35-40/bbl crude oil price. Indeed the charts

suggest that on average, cash opex costs per country are relatively modest.

UK, Norway, US, Alaska, Russia the high cost provincesThis point aside, in our opinion our analysis also highlights that, on a cash basis including

royalty and severance taxes, the high cost production regions with material (over 1.0mb/d)

production include Canadas oil sands, Russia, the US-lower 48, Alaska, the North Sea (UK

and Norway) and Kazakhstan. On average, median production costs in these areas including

taxes would appear to run at around $15/bbl. To the extent that production in these areas

arises from a multitude of fields (which obviates Kazakhstan), it is these countries whose cost

curves are probably worthy of further analysis. With this in mind over the following section

we have used Wood Mackenzies field-by-field production and cost database to build intra-

country cost curves, our expectation being that this should afford us some better insight into

the number of barrels of oil production that are vulnerable to shut-in as the price of oil falls

towards the $20/bbl level.


11/39



Figure 8: Estimated OPEX cost of production ($/bbl) across major territories (where OPEX is predominantly lifting

and transport)

0

5

10

15

20

25

30

0 2922 5844 8766 11688 14610 17532 20454 23376 26298 29220 32142 35064 37986 40908 43830 46752 49674 52596 55518 58440 61362

Cumulative2009 oil roduction kb/d

OPEX $/bbl

Average OPEX among top producers o f on ly $6.20/bbl

(or $11.10/bbl excluding OPEC producers

Kuwait

Mexico

AlgeriaAngolaIran

Saudi Arabia

UAE

Libya

Nigeria

CanadaSands

UK

Alaska

China

Kazakhstan

Russia

Azerbaijan

orway

USGoM

Brazil

raq

Venezuela

Source: Wood Mackenzie GEM, Deutsche Bank estimates

Figure 9: Estimated $/bbl cash cost of production across major territories (OPEX plus royalties/severance taxes)

0

5

10

15

20

25

30

0 2922 5844 8766 11688 14610 17532 20454 23376 26298 29220 32142 35064 37986 40908 43830 46752 49674 52596 55518 58440 61362



UAESaudi Arabia

Russia

Iraq

Nigeria

AlgeriaMexico

LibyaAngola

Iran

KuwaitCanadaSands

Alaska

China

UK

Kazakhstan

Norway

Azerbaijan

USGoM

Venezuela

Brazil

Average cash costs among top producers $7.70/bbl

(or $12.50/bbl excluding OPEC countr ies)

Source: Wood Mackenzie GEM, Deutsche Bank esimates


12/39



Figure 10: Estimated OPEX cost of production ($/bbl) across minor territories (where OPEX is predominantly lifting

and transport)

0

5

10

15

20

25

30

0 517 1035 1552 2070 2588 3104 3622 4138 4657 5173 5691 6210 6726 7244 7761 8279 8797 9313 9831 10348 10866 11382 11901 12419 12935 13454Cumulative 2009 oil production kb/d

OPEX $/bbl

US(ex-GoM)

Denmark

Australia

India

Ecuador

Argentina

Colombia

Canada

(exOilSands)

Indonesia

Gabon

Sudan

Congo-

BrazzavilleEquatorial

Guinea

ThailandBrunei

MalaysiaQatarOmanEgypt

Average cash costs am ong top pro ducer s $8.30/bbl

(or $8.90/bbl excludin g OPEC countries)

Source: Wood Mackenzie GEM, Deutsche Bank estimates Note US-excludes Alaska, GoM and c1.5mb/d unaccounted for lower 48 production

Figure 11: Estimated $/bbl cash cost of production across minor territories (OPEX plus royalties/severance taxes)

0

5

10

15

20

25

30

0 517 1035 1552 2070 2588 3104 3622 4138 4657 5173 5691 6210 6726 7244 7761 8279 8797 9313 9831 10348 10866 11382 11901 12419 12935 13454Cumulative 2009 oil production kb/d


US(ex-GoM)

Denmark

Australia

India

Ecuador

Argentina

Colombia

Canada

(exOilSands)

Indonesia

Gabon

Sudan

Congo-

Brazzaville

Equatorial

Guinea

Thailand

Brunei

MalaysiaQatarOmanEgypt

Average cash co sts among top pro ducer s $9.55/bbl

(or $10.20/bbl excludin g OPEC countries)

Source: Wood Mackenzie GEM, Deutsche Bank estimates Note US-excludes Alaska, GoM and c1.5mb/d unaccounted for lower 48 production


13/39



Where is cash breakeven?

Unsurprisingly, the more mature the higher the cost

Our high level analysis of the cash costs for the major producing regions clearly suggeststhat, with the exception of known high cost provinces such as Canadas oil sands, it is

typically (and unsurprisingly) the more mature oil provinces that tend to have the highest cash

breakeven levels. Undoubtedly there will be producing fields in other geographic areas

whose cash costs are such that their economic viability is threatened as oil prices move

towards $30/bbl. However, given an average cash cost including production taxes of around

$15/bbl in the UK, Russia, Alaska and the US onshore it is in these markets that we would

expect a potentially significant number of production barrels to be shut-in through any

sustained downturn in the oil price. For most other markets, any price-induced loss in existing

production is very likely to be at the margin.

With this in mind we have sought to look at the marginal cost curves of these areas in some

more detail. Shown below, we have used Wood Mackenzies field by field analysis and our

understanding of fiscal terms to build marginal cash cost curves for these separate areas.

Oil needs to fall well below $30/bbl before material cuts are threatened

Interestingly, whilst our analysis suggests that some significant number of barrels would

likely become uneconomic at a price of say $20/bbl, at a WTI oil price of $30/bbl and above

very little outside Canadas oil sands is, we believe, truly threatened. This is illustrated by the

below table which summarizes the number of barrels that we believe would be at risk across

the different regions at oil prices down to $20/bbl (c3mb/d) and 30/bbl (a modest 700kb/d).

Figure 12: What might be at risk in mature provinces excluding US-lower 48?

Oil prices below $20/bbl Oil prices below $30/bbl Oil prices below $40/bbl

UK 471kb/d 132kb/d 70kb/d

Norway 228kb/d 47kb/d 20kb/d

Canada oil sands 1610kb/d 460/kb/d NIL

Alaska 18kb/d 15kb/d NIL

Russian export 1033kb/d NIL NIL

Source: Deutsche Bank

The UK - We see limited risk of shut-ins at prices above $30/bbl

Given the mature, high cost profile of the UK North Sea and the relatively high proportion of

smaller, riskier E&P companies now driving that production, the UK would appear at first

glance to be one of the more vulnerable regions in terms of potential shut-ins. However, our

analysis suggests that a modest 132kb/d of 09 production could be at risk of shut-ins at oil

prices around $30/bbl and under 70kb/d at $40/bbl. Indeed, it is only if the price of crude oilwere to fall to under $20/bbl and stay there for some extended period of time, thereby

threatening the economics of larger plays such as Forties and Ninian, that we believe the UK

would see a truly material threat to its immediate production outlook.

Having said this, it should be appreciated that our estimates of the UKs economics are

limited to opex costs alone. Most likely, for a region such as the UK with its aging

infrastructure which operates in a hostile environment, maintaining production is almost

certain to require some notable degree of capital investment. To what extent this may

encourage operators to shut down facilities for extended maintenance is obviously unclear.

Likely as not, however, it suggests to us that the actual costs of keeping plant going at lower

oil prices will be higher than figure 13 implies. As such the temptation to shut-in given an

extended fall in the oil price would also inevitably be higher.


14/39



Figure 13: UK cash cost curve: our analysis suggests that at prices of around $40/bbl

only modest production faces an economic threat

0

10

20

30

40

50

60

70

80

90

100

3 73

242

457

989

107

8

1321

1558

1604

17

69

1821

1903

21

98

237

6

2622

281

3

292

6

3333

3368

34

92

37

67

3968

4117

41

94

4331

4380

4693

481

0

4851

5007

5112

5324

537

6

5414

54

59

5592

5642

5721

577

8

$/bbl

132kb/d and

413mb

uneconomic

below $30/bbl

70kb/d and

272mb

uneconomic

below $40/bbl

Cumulative resource mb bls

Buzzard ($6.1/bbl)

Schiehallion ($12.2/bbl)

Forties ($22.2)

UK - Average OPEX cost $14.19/bbl




Norway less vulnerable than the UK but .

While similar to the UK in terms of infrastructure, a number of key differences mean that we

see less risk of shut-ins in Norway. Firstly, Norways lower maturity means that average

OPEX/bbl at c.$10.85/bbl is below the average $14.20/bbl in the UK a feature which in large

part is a function of production being concentrated amongst a far lower number

Figure 14: Norway cash cost curve: Our analysis suggests that prices would need to

drop below $30/bbl before any material volumes of production would be at risk

0

5

10

15

20

25

30

35

40

45

50

155

180

482

502

788

912

1115

1211

2089

2369

2473

3049

3088

3455

4803

5238

5308

5605

6191

6368

6561

6791

7019

7035

7109

7288

7354

7473

7913

7962

8018

8109

8131

Cumulative resource mboes

$/bbl

Ekofisk ($9.50/bbl)

47kb/d and

169mb

uneconomic

below $30/bbl

20kb/d and 43mb

uneconomic below

$40/bbl

Snorre $11.45/bbl

Asgar d $8.80/bbl

Norw ay - average OPEX cost $10.85/bbl,



Grane $20.61/bbl



15/39



of facilities than it is of structurally lower costs (forecast oil production in 2009 is 1.9mb/d in

the UK from over 300 facilities vs. 2.5mb/d from around 70 in Norway). Secondly, Norway

has a higher proportion of large cap major oil companies operating projects, companies

which are likely to suffer less financial stress at this time than the smaller E&P companies in

the UK. Finally the fiscal regime in Norway is such that it encourages exploration (78% tax

relief on exploration) and development (generous capital allowances) on projects. This should

ensure that the pace of decline in a deteriorating price environment is more modest than thatlikely in the UK.

As a consequence our analysis suggests that whilst the economics of almost 228kb/d or

10% of Norwegian production would be challenged at an oil price of $20/bbl, at $30/bbl only

47kb/d looks uneconomic. This compares with the aforementioned UK exposure of nearer

471kb/d or (25% of total UK output) at $20/bbl and 132kb/d at $30/bbl. Relative to the UK

Norway thus certainly looks better placed.

Alaska Economics comfortable at a price down to $20/bbl

Despite its reputation as a high cost, harsh operating environment our analysis suggests that

even if oil prices were to fall below $30/bbl all but one field remains economic (and this fieldis forecast to produce only 15kb/d of oil in 2009). This is despite the existence of high transit

costs, a 12.5% royalty which we include in our calculations and some modest expected

charges for petroleum production tax or PPT (we assume between 0-4% depending upon

opex costs).

Figure 15: Alaskan cost curve suggests that nearly all fields have a cash breakeven

excluding capex of around US$18/bbl

0

5

10

15

20

25

30

35

40

23

24

260

295

436

2138

2257

3149

3256

3546

3693

4054

4192

4268

Cumulative resources mbbls

$/bbl OPEX Royalty 12.5% PPT

Major fields Prudoe Bay and

Kuparuk both appear to have a

cash break-even of $17/bbl


Having said this, also apparent from our analysis of Wood Mackenzies database is that

nearly all fields are expected to incur capex costs of around $2-3/bbl through the course of

2009. Given the consistency with which this seems to be applied it is debatable whether

such charges should not be treated as cash costs of continuing production. In reality,

however, even if we were to do so the cash breakeven level would be unlikely to move much

beyond the $20/bbl level suggesting that, whilst Alaska may be a relatively high cost and

mature region, oil prices would need to fall some considerable way before production would

truly be at risk of material shut ins.


16/39



Russia Domestic no problem; exports a different story

Given the scale of the fields and the resource base it seems a little ironic to label Russia a

high cost producer. Indeed, if we were to solely consider OPEX costs it would also be wholly

untrue we estimate that stand-alone opex and transit costs are little more than $7-8/bbl.

However, largely as a consequence of the countrys punitive levels of taxation, Russia is now

almost certainly one of the most expensive provinces in the world in which to produce crudeoil. This is particularly true for crude oil exports given that, since 2004, the authorities have

levied tax at a rate of 65% on the difference between the realized export price and $25/bbl.

Figure 16: Russian cost curve suggests that cash breakeven for OPEX and transport

averages $7.45/bbl but adding taxes/Urals discount this rises to $18.45/bbl

0

5

10

15

20

25

30

544

1488

4584

5153

6070

6778

7815

9183

10044

10390

10775

12101

12646

15428

17211

18002

21722

25892

26682

29980

33331

37448

38510

43426

44883

46128

48665

56681

58039

62920

64839

67128


$/bbl

Export Tax 65%

MET

Urals discount

OPEX

1033kb/d ' 09 oil

production and 12.8bn

bbls resources

uneconomic if price

falls to $20/bbl

Vankorskoye $20.44/bbl

Samotlor $18.5/bbl

Russia - average OPEX $7.45/bbl,

average cash cost inc M ET on a

WTI basis $18.45/bbl

Source: Wood Mackenzie GEM, Deutsche Bank estiamtes

Allowing for MET of around $8/bbl currently (our estimate) and encompassing a normalized

urals discount to Brent of about $3/bbl we estimate that Russian producers need a Brent oil

price of around US$18.50/bbl to remain in profit. This suggests that at a current domestic

price of $20/bbl Russian production remains in profit albeit not by much. Sales into export

markets do attract higher prices and even allowing for export tax should contribute more

significantly to profits (although the absolute profit per barrel is less than compelling). None

of this is, however, conducive for investment and in many ways it comes as little surprise

that with investment in the industry falling away Russian production should now be in decline

(see later). Moves to reduce the level of MET should provide some near term support for

profits and investment. At this time, however, our impression is that more will need to be

ceded by the tax authorities if Russian companies are to invest meaningfully for growth.

Canada oil sands simply high cost (but gas matters a lot)

Clearly to describe the oils sands as mature would be inaccurate. The sheer scale of

Athabascas reserves suggests substantial growth potential. The cost of extracting the

bitumen and converting it to synthetic crude does, however, mean that Canadas oil sands sit

very much towards the top of the oil cost curve. We estimate that the cash costs of

operating a mining and upgrading facility akin to Suncor, AOSP or Syncrude in 2008 were

around US$28/bbl. Admittedly, production of bitumen from SAGD is considerably lower at

nearer $13-15/bbl. However, to the extent that the bitumen extracted is not upgraded, the


17/39



discount to WTI of say $20-25/bbl means that production economics are quickly destroyed.

No surprise then that the 1.2mb/d of bitumen based oil that Canada now produces is seen as

a key to determining the marginal cash cost of oil. Push the oil price below $25-30/bbl for any

extended period of time and the theory is that Canadas sands will ultimately shut-in.

Figure 17: Estimated operating costs for both synthetic oil and bitumen oil sands

projects on a WTI equivalent basis (i.e. adding back bitumen discount)

0

5

10

15

20

25

30

35

40

4043

8041

11041

17596

20936

22484

22554

22874

23094

22404

23264

23344

25244

26644

26944

27294

27789

27977

28877

29886

30501

31502

31542

33392

Bitumen discount

Production cost

$/bbl

Joslyn

Suncor, Syncrude

and AOSP

Cumu lative reserves (mb)


Having said this it should be appreciated that in recent years at least $10-12/bbl of cash cost

has represented expenditure on energy, namely natural gas. As such, with gas prices now in

reverse in North American markets, cash costs should be retreating and fairly significantly.

Equally, as recently stated by RDS it is not easy to shut down and then restart an oil sands

operation. Companies would almost certainly be prepared to continue to run production even

if the contribution achieved became modestly cash negative, not least because that way they

are immediately positioned to take advantage of any up-tick in price once it comes.

US Onshore History says 1mb/d at risk already

We should emphasise that where Wood Macs database covers a very substantial proportion

of global oil supply, on-shore US production is a major region for which material data is not

available. This in large part reflects the very fragmented nature of a substantial portion of US

onshore production. Our understanding of US onshore stripper well production is that it is

high cost (estimates range between $55/bbl - $70/bbl cash costs including royalties) not leastdue to the modest number of barrels produced per day (c2kb/d) and the very high water cut.

If past cycles are anything to go by, we see US stripper well production as being one of the

most vulnerable to shut-ins, not least due to the fact that during the oil price crash of the

1990s US oil production fell by some 500kb/d as, amongst others, these high-cost, low

productivity wells were shut in. Moreover, given the strength of the oil price in recent years,

production from stripper wells in the US at around c.17% of total US oil production is

significantly higher than it has been for much of the past two decades.

Given limited data it is obviously not possible for us to sensibly create or analyze a cost curve

for this region. The lower-48s production history is, however, observed at some further

length when considering supply growth over the following pages.


18/39



Mature basins: Decline ratesto accelerate?

The impact on growth in mature regions is likely negative

Evidently, our analysis of the threat to non-OPEC supply from current low oil prices suggests

that in aggregate any lost production will most likely be modest and at the margin. However,

as emphasized in our introductory comments oil is a wasting asset and the oil supply industry

one which requires consistent investment if production levels are to be maintained. Referring

again to Wood Mackenzies estimate of the components of supply growth over the next six

years suggests that total production on-stream as at the end of 2008 will suffer an annual

decline in the region of 2%. This does, however, assume the continued steady investment in

existing facilities, something which past experience suggests can certainly not be taken for

granted at this time. And whilst the below chart depicts a far more modest production

decline of an annual 1% or so if we include reserves growth and resources under

development, the pace of delivery here must also be under question given the economics

which prevail today.

Figure 18: Contribution of future elements of supply without investment on-stream

production suffers a CAGR decline of 2% 2008-2015.

60

65

70

75

80

85

90

95

2008 2009 2010 2011 2012 2013 2014 2015



Source: Wood Mackenzie GOSS, Deutsche Bank

Production risks increasingly appear to be to the downside

Indeed, given recent company announcements indicating that capital and exploration spend

will be reined back and portfolios high-graded with projects deferred where companies have

the flexibility to do so, we believe the risk to this production profile is now very much to the

downside. This seems particularly true given what we know of regions like Canada, the UK,

Alaska and the US where production growth has slowed dramatically in past cycles following

cuts in investment spend. Russia serves perhaps as a more recent example of what could

potentially happen to growth in mature regions should investment in the maintenance and

development of existing and new opportunities stagnate to decline. It is of note that the


19/39



Russian Oil Ministry have recently suggested that Russian oil production will decline from

around 9.8mb/d at present to an expected 9mb/d by 2015 i.e. by an average of c.1-2% p.a.

with that risk augmented in mature basins by its corporate source

Perhaps more striking through this downturn is also the increased dependence of the future

growth of the industry on smaller to mid-sized companies. This seems particularly relevant in

light of the very difficult credit markets that persist at present and that look likely to continueto do so over the course of 2009 and, perhaps, 2010. With an increasing proportion of

production from mature basins now concentrated in the hands of smaller companies rather

than the majors (something that we believe is well illustrated by the shift in UK production

towards the independents since 2000 or the increased proportion of US production arising

from stripper wells) our simple impression is that growth in these regions is likely to suffer

especially significantly over the coming years.

Figure 19: High cost US stripper wells now account for

almost 20% of US oil production

Figure 20: Make up of UK production: The share of the

majors in the UK has near halved since 2000

0.00

0.50

1.00

1.50

2.00

2.50

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

10.0%

11.0%

12.0%

13.0%

14.0%

15.0%

16.0%

17.0%

18.0%

19.0%Average production per well (bbl/d) % stripper production

bbl/d % US production

40%

45%

50%

55%

60%

65%

70%

75%

80%

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

% UK production delivered by the majors

Source: US EIA/DOE data, Deutsche Bank estimates Source: Wood Mackenzie, Deutsche Bank

Past history suggests that mature regions will see decline rates accelerate to c10%Clearly sitting here today our strong impression is that the stage is now set for an

acceleration in the pace of decline in mature basins. Quite simply, with drilling activity in

mature provinces already slowing sharply this is now inevitable. Nowhere is this more

obvious than in the US where in recent months rig activity has plummeted (see figure 44).

Quite how sharp this decline might be is, however, difficult to determine. Yet, one look at the

charts overleaf which depict production profiles for the UK, Canada, Alaska and the US

onshore through past downturns in the crude oil price and the trends are all too apparent.

Whether it is the UK, US or modern day Russia, if returns come under pressure the supply

response would appear to be relatively consistent. In short, decline rates appear set to

accelerate with production falling on average by at least 10%. Given that these regions alone

account for around 7mb/d of annual production the implication must be the loss of around0.7-1mb/d of existing production. Assume decline rates in Russia hold at the recent rate of

around 2-3% and a further 300kb/d of production looks vulnerable.

From our perspective what this suggests is that although the loss in supply in the very short

term from mature production centers due to shut-ins may be relatively modest, absent an

improvement in the investment climate there will be a supply response in the longer term.

Assuming that this arises at a time when demand for crude oil starts to stabilize, if not

improve, and the impact upon price is likely to be all the more significant.


20/39



Figure 21: UK oil production growth year-on-year 1996-

2002 the impact of underinvestment is clear

Figure 22: Russian oil production is also starting to

show the effect of underinvestment in the industry

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

Jan-96

May-96

Sep-96

Jan-97

May-97

Sep-97

Jan-98

May-98

Sep-98

Jan-99

May-99

Sep-99

Jan-00

May-00

Sep-00

Jan-01

May-01

Sep-01

Jan-02

May-02

Sep-02

Impact of lower investment throughout the price crash of

the late 90's: -9% compound decline in production

-3%

-2%

-1%

0%

1%

2%

3%

4%

5%

Jan-05

Apr-05

Jul-05

Oct-05

Jan-06

Apr-06

Jul-06

Oct-06

Jan-07

Apr-07

Jul-07

Oct-07

Jan-08

Apr-08

Jul-08

Oct-08

Russian declines accelerate

Source: UK BERR data, Deutsche Bank estimates Source: Reuters, Interfax, Deutsche Bank estimates

Figure 23: Alaskan oil production follows a similar trend

with production decline resulting from underinvestment

Figure 24: US lower 48: The decline in prices in the late

1990s drove a short 500kb/d fall in onshore production

-20%

-15%

-10%

-5%

0%

5%

10%

15%

Jan-94

May-94

Sep-94

Jan-9

5

May-9

5

Sep-9

5

Jan-9

6

May-9

6

Sep-9

6

Jan-97

May-97

Sep-97

Jan-9

8

May-9

8

Sep-9

8

Jan-9

9

May-9

9

Sep-9

9

Jan-0

0

May-0

0

Sep-0

0

Jan-01

May-01

Sep-01

Jan-02

May-02

Sep-02

Impact of lower investment leads to period

of negative growth??

-12%

-10%

-8%

-6%

-4%

-2%

0%

2%

4%

6%

8%

Jan-95

May-95

Sep-95

Jan-96

May-96

Sep-96

Jan-97

May-97

Sep-97

Jan-98

May-98

Sep-98

Jan-99

May-99

Sep-99

Jan-00

May-00

Sep-00

Jan-01

May-01

Sep-01

Jan-02

May-02

US shut-ins take down

c500kb/d in 1998/9

Source: EIA/DOE data, Deutsche Bank estimates Source: EIA/DOE data; Deutsche Bank estimates

Figure 25: Canada: Akin to the lower-48, the 1990s price

collapse drove a 15% production decline

Figure 26: with Canadian light oil production

suffering similarly over the same period

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

Jan-9

5

Ma

y-9

5

Se

p-9

5

Jan-9

6

Ma

y-9

6

Se

p-9

6

Jan-97

Ma

y-97

Se

p-97

Jan-9

8

Ma

y-9

8

Se

p-9

8

Jan-9

9

Ma

y-9

9

Se

p-9

9

Jan-0

0

Ma

y-0

0

Se

p-0

0

Jan-01

Ma

y-01

Se

p-01

Jan-02

Ma

y-02

Se

p-02

Akin to ligh t oil , Canadian

heavy declined sharply

during the pr ice crash of

the late 90's . . And turned negative again in

2002 - possibly as a result of

delayed investment in the late 90's

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

Jan-9

5

May-9

5

Sep-9

5

Jan-9

6

May-9

6

Sep-9

6

Jan-97

May-97

Sep-97

Jan-9

8

May-9

8

Sep-9

8

Jan-9

9

May-9

9

Sep-9

9

Jan-0

0

May-0

0

Sep-0

0

Jan-01

May-01

Sep-01

Jan-02

May-02

Sep-02

Production in light crude in Canada

declined sharply during th e price crash

of the late 90's declining by 13% y-o-y at

its peak

Source: Statistics Canada data, Deutsche Bank estimates Source: Statistics Canada data, Deutsche Bank estimates


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The implications for growthregions

Investment is about costs as much as price

Turning now to growth regions and what the current environment means for future

developments, we should first highlight that fundamentally, it is not solely the oil price which

determines whether or not a project will be sanctioned. As the figure below highlights, even

before oil prices collapsed through the second half of last year, the number of final

investment decisions (FIDs) taken in the first six months of 2008 was a very modest

eighteen. This is despite the fact that most projects would have been more than economic

should the oil price experienced through to the middle of the year have prevailed. In our

opinion, the very simple reason for the dearth of FID in 2008 was costs. At the typical

planning price for crude oil of $60-$80/bbl that we believe is used by the major oil companies,

costs were simply too prohibitive to guarantee a return. Companies thus began to postpone

sanctioning projects until such a time as costs cooled so rendering projects economic at

these planning price levels.

Figure 27: Average no. FID has fallen in every other downturn which has resulted in

falling or flattening of F&D costs

0

20

40

60

80

100

120

1970 1974 1978 1982 1986 1990 1994 1998 2002 2006

0

5

10

15

20

25

30$/bbl F&D

No. FID taken H2 08 FID

F&D costs Oil Price (nominal)

$/bbl oil pri ce & No. FID

Source: Wood Mackenzie Pathfinder, Bloomberg, Deutsche Bank

Using our understanding of costs and Wood Mackenzies forecasts for OPEX and CAPEX we

have calculated the average breakeven oil price required for development of future projects in

four key growth regions (Brazil, US GoM, Angola and Nigeria). Our analysis unsurprisingly

suggests that the growth regions are much more vulnerable to project delays and/or

cancellations, than mature regions are to production shut-ins. This is particularly true in ultra-

deepwater and complex developments which are inherently more costly to develop and for

which a tight deepwater (5000metres plus) rig market suggests that, even in the face of a fall

in crude prices, costs are unlikely to come back quickly.


22/39



Indeed we are already seeing this profile of poor project economics translate to the real

world, with an ever increasing number of companies (both IOCs and NOCs) announcing

project postponements, cut backs in CAPEX and canceling bid rounds for rigs. A number of

Canadian oil sands projects (Totals Northern Lights, Shells Jackpine development at AOSP,

StatoilHydros Leismer up-grader project, Petro-Canadas Fort Hills) have delayed FID, whilst

elsewhere Saudi Aramcos cancellation of a $10bn service contract for the development of

the Manifa project, Hesss recent guidance that is intends to spend 33% less in 2009 onexploration than in 2008 and 26% less on production and development spend, are just some

of the headlines were seen over the last few months.

Using Wood Mackenzies database to assess project economics

In order to build regional cost curves and gain a stronger understanding of how the full cycle

economics for growth regions have shifted in recent years we have again fallen back on

Wood Mackenzies database of capital and operating costs. Taking Wood Mackenzies

generally well informed cost estimate for full cycle CAPEX per barrel, we have assumed that

the industry requires a 15% return and grossed up to give us a required cash flow per barrel

number for the project to wash its face. Back-calculating further we have then used our

understanding of the different regions fiscal regimes and Wood Mackenzies estimates for

per barrel operating costs to estimate the oil price required to justify investment. Finally, soas to state everything on a WTI equivalent basis we have adjusted this price for to ensure

any price discount or premium is captured.

Figure 28: Methodology by which we calculated our estimated breakeven oil prices

within the growth regions

Roncador $/bbl Comments

Capex 7.3 Taken from Wood Mackenzie GEM database

15% return 1.1 Reflects our use of 15% as minimum return sought on project

CAPEX plus return 8.3

Corporation Tax 4.5 Corporate Tax rate in Brazil of 35% applied to CAPEX plus return

Special Participation

TaxT

4.3 Whilst SPT rates varies between 10-40% we have used 25% for this

example. In reality the rate will vary dependent upon field size

OPEX 7.0 Taken from Wood Mackenzie GEM database

Royalty 2.7 Royalty of 10% applied to CAPEX plus return plus taxes plus OPEX plus

discount to Brent

WTI discount 9.8 Reflects an estimated 25% discount to Brent give API in the high 20s

Total Cost 37.6

Source: Deutsche Bank

Clearly we recognize that this method fails to take into account the time value of money and

certain other fiscal elements such as capital allowances. Sense checking our breakeven

estimates against the outputs from Wood Mackenzies sophisticated fiscal models to

calculate NPVs suggests however that, barring a few exceptions, the breakeven oil price for

projects to achieve company investment objectives is in line.

What drops out at least $60/bbl is needed for a growth barrel

As to the findings our analysis suggests that, in the absence of a very significant shift in

taxation or capital and operating costs, very few of the development projects mooted would

deliver an economic return at current oil prices. More importantly, given an average

breakeven on new projects in Angola of around $68/bbl, GoM $62/bbl, Nigeria DW $60/bbl

and Brazil around $60/bbl (although this depends upon the size of the field and special

petroleum tax) most projects in the growth regions fail to wash their face at the lower end of

companies price planning ranges.


23/39



Brazil avg. breakeven $42/bbl (but new projects different story)

While the overall average breakeven oil price required in Brazil is a modest $42/bbl, this figure

includes a number of existing fields such as Roncador ($38/bbl) or Albacora ($20/bbl) for

which FID was taken in a lower cost environment and which have significantly lower

breakeven points. The projects that underpin future production growth in Brazil are in ultra-

deepwater and are technologically complex, requiring significant capital outlay. However,unlike future developments in growth PSC regimes in Africa which require oil prices nearer

$70/bbl, under the existing fiscal regime in Brazil our analysis would suggest that the average

breakeven oil price required for new developments is a more modest $51/bbl. Even Tupi, the

giant oil field in Brazils sub-salt Santos basin, only requires an oil price of $60/bbl (compared

with the $40/bbl breakeven oil price indicated by BG Group) to break even on our estimates

(we suspect the difference reflects BG commenting on TUPI as a single 100kb/d

development rather than the first in a series thereby driving up special production tax (SPT)

rates).

Overall we estimate that at oil prices below $40/bbl some 8.6mbbls of reserves are no longer

economic and this increases to 13.5mbbls (or 74% of total resources included within the

Wood Mackenzie database) at oil prices below $30/bbl. However, we note that other factors

are also likely to impact the development of projects such as the fact that the governmentcould initially favor developing gas fields in order to reduce the countrys gas imports from

Bolivia. Another factor which could impact development is the requirement for c.30-40%

local content in the development of projects; the local market (particularly the rig market) is

not sufficiently developed as yet to be able to cope with the potential demand from the

development of all Brazils recent sub-salt discoveries.

Figure 29: Brazil Concession we estimate that an average oil price of $42/bbl is

required

0

10

20

30

40

50

60

70

342

463

903

1362

2003

3591

3899

4021

4195

4447

4834

4892

5324

7888

8686

9097

9792

11715

12415

12416

12824

13469

18371

Cumulative resources mboes

$/bbl

Capex Opex Return Tax Royalty SPT Discount to WTI

Tupi $60/bbl

Averag e beakeven oi l pr ice requ ired in Br azil of $42/bb lMarlim Sul $43/bbl

Roncador 38/bbl

Parque das Conchas $55/bbl


What do the Wood Mac models say?

Below we present a number of key future developments in Brazil which highlights our

calculated breakeven oil price compared to Wood Mackenzies calculated NPV10 at both

$40/bbl and at $60/bbl. This would imply a breakeven oil price of near $60/bbl for Tupi in the

current cost environment (again on the basis of a development that will ultimately produce

1mb/d and thus attract SPT at 40%).


24/39



Figure 30: Brazil key development projects

Project Operator Reservesmbbls

Peak prodnkb/d

DB B/E oilprice $/bbl

WM NPV10$40/bbl

WM NPV10$60/bbl

Baleia Franca Petrobras 298 65 39.05 157 988

Peregrino StatoilHydro 450 95 43.25 295 1908

Parque das Conchas Shell 382 98 55.45 -344 1618

Papa Terra Petrobras 609 160 56.16 -2202 140

Tupi Petrobras 4654 868 59.59 -12768 444

Source: Deutsche Bank, Wood Mackenzie GEM

Gulf of Mexico low cash cost but growth vulnerable

With its concessionary fiscal regime, low geopolitical risk profile and a modest average

breakeven oil price of only $46/bbl, the US GoM has been one of the key growth regions for

major IOCs over the last decade. However, that future developments in US GoM could suffer

in the current environment was also highlighted in a recent Wood Mackenzie Insight article

(Probables in deepwater Gulf of Mexico 2008, published December 2008) which estimated

that as a consequence of the surge in development costs, only three relatively small fields

with aggregate 2P reserves of just 42mboe received project sanction in 2008 compared withnearer 10 projects containing 600mboe in 2007. Secondly, additions to the list of probable

reserves for development slowed sharply with reserve adds of just 214mboe compared with

over 1500mboe in 2007. Thus where the relatively modest operating (we estimate $7/bbl)

and royalty (we estimate $4/bbl) costs in the GoM suggest that the region should remain

cash positive on existing production at oil prices down to $11/bbl, the outlook for medium

term growth should oil prices remain at current levels looks certain to continue to deteriorate.

Figure 31: Deepwater Gulf of Mexico we estimate that an average oil price of $46/bbl

is required to breakeven

0

10

20

30

40

50

60

70

80

90

100

010

199

589

819

906

974

1040

1195

1261

1293

1447

1522

1708

1787

1906

2014

2682

3002

3181

3246

4177

4324

5060

5501

5639

6411

7165

7534

8772

9010


$/bbl

Capex Opex Return Tax 35% Royalty Mars Differential

Averag e breakeven oil pri ce requ ired i n US Deepw ater GoM of $46/b bl

Tahiti $53/bbl

Shenzi $46/bbl

Thunderhorse $41/bbl

Atlan tis $36/bb l

Source: Wood Mackenzie GEM, Deutsche Bank

Indeed, looking at projects where production has not yet started the average breakeven oil

price required increases to $52/bbl. Projects such as Shenzi or Tahiti which have taken FID

and are nearing production start-up have breakeven oil prices of $46/bbl and $53/bbl

respectively, however this increases again for projects that are less far along the

development path such as Jack ($67/bbl) or Knotty Head ($70/bbl). In total our analysis

indicates that at oil prices below $40/bbl some 6bn bbls (64% of total cumulative resources

considered) would potentially become uneconomic, increasing to 7.5bn bbls at oil prices

below $30/bbl. This correlates well with the below Wood Mac NPV estimates.


25/39



Figure 32: US Gulf of Mexico key development projects


Peak prodnkb/d

DB B/E oilprice $/bbl

Wood MacNPV $40/bbl

WoodMacNPV $60/bbl

Shenzi BHP 345 86 46.27 -323 1566

Great White Shell 435 72 50.10 -1140 895

Tahiti (GC 640) Chevron 450 106 53.42 -708 1642

St Malo (WR 678) Chevron 400 85 63.35 -2028 -460

Jack (WR 759) Chevron 375 64 67.29 -2379 -838

Knotty Head (GC 512) Nexen 300 80 69.51 -1761 -487

Tubular Bells (MC 725) BP 274 77 59.67 -1190 351


Nigeria high costs and riskier operating environment

Our cost-build analysis of Nigerian PSCs indicates that akin to Angola, at $60/bbl Nigeria has

one of the highest breakeven oil prices for new projects in the growth regions that we have

considered. Digging a little deeper our analysis indicates that the breakeven oil price required

for future deepwater developments, such as Bolia-Chota, Nsiko, Aparo and Usan, increases

to near $70/bbl. In other words, circa 69% of cumulative deepwater reserves in Nigeriaconsidered in our analysis are not economically viable in the current high cost environment at

$40/bbl. Add to this Nigerias riskier operating environment (given military and social unrest)

and Nigeria would appear to lend itself to potential delays in project development.

Figure 33: Nigeria PSC we estimate that an average oil price of $46/bbl is required to

breakeven

0

10

20

30

40

50

60

70

80

90

36

344

917

17

38

2559

314

9

31

88

432

5

4935

5005

5085

52

85

542

5

5680


$/bblCapex Return Government OPEX Royalty

Erha $43/bbl

Bonga $46/bbl

Agb ami $30/bbl

Akpo $44/bbl

Usan $60/bbl

Bolia-Chota $71/bblAver age br eakeven o il p rice o f $46/bb l requir ed fo r Nigeri a PSC devel opm ents

Source: Wood Mackenzie GEM, Deutsche Bank

Below we present a number of key future developments in Nigeria which highlights our

calculated breakeven oil price compared to Wood Mackenzies calculated NPV10 at both

$40/bbl and at $60/bbl. The more sophisticated Wood Mackenzie model indicates breakeven

oil prices somewhat lower than we calculate, mainly due in our opinion to the generous

capital allowances and other tax offsets available on deepwater PSCs in Nigeria which our

simple calculation does not attempt to account for. Having said this, however, none appear

economic at $40/bbl with most requisite of an oil price comfortably north of $50/bbl to

achieve breakeven.


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Figure 34: Nigeria key development projects


Peak prodnkb/d

B/E oil price$/bbl

NPV $40/bbl NPV $60/bbl

Usan Total 610 180 57.65 -1809 1580

Aparo Chevron 70 20 61.75 -295 158

Oyo Eni 80 30 69.69 -333 521

Bolia-Chota COP/Shell 340 102 70.91 -308 376

Nsiko & Aparo Chevron 255 83 83.44 -1454 -426


Angola it simply doesnt work at current costs and prices

The chart below paints a none too rosy picture in a region that was once mooted as being a

new growth engine for IOCs, with our analysis suggesting an average breakeven oil price for

new developments in Angola of $69/bbl (compared to the average breakeven of $41/bbl for

all projects in the region). Within this we note that key growth projects such as BPs Block

31, Totals Block 32 or BPs Block 18 West require something nearer $80/bbl suggesting FID

on these projects will not be forthcoming in the current environment. Furthermore, as

highlighted in a recent Wood Mackenzie publication, at lower oil prices it is the governmentthat absorbs most of the impact (at a LT oil price of $150/bbl the government would have

taken 54% of revenues, at a LT oil price of $100/bbl this falls to 42%). Consequently, with

costs running high and eating heavily into the governments share of cash flows it is possible

that obtaining project sanction will prove increasingly difficult in the current environment.

Figure 35: Angola PSC we estimate that an average oil price of $41/bbl is required to

breakeven

0

10

20

30

40

50

60

70

80

90

100

1254

1274

1324

1329

1390

1419

1419

1430

1918

1947

2305

2889

3251

3254

3254

4123

4124

5047

5653

5669

5735

6320

6475

7696

7900

8754

9754

1

0455


$/bbl

Capex Opex Return Government Discount to Brent

Averag e breakeven o il p rice r equi red in Ang ola PSC regi me i s $41/bbl

Block 31 c.$70/bbl

Total's Pazflor c.$53/bb

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