The Fundamentals of Global Oil Supply

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The Fundamentals of Global Oil Supply

Bengt Söderbergh, Senior Oil and Gas Market Analyst, Fortum

Presentation, Bengt Söderbergh, Kristofer Jakobsson, 2012 Photo: Bengt Söderbergh

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Disclaimer

The content of this presentation is based on research at

Uppsala university by Kristofer Jakobsson and Bengt

Söderbergh. Any views or opinions expressed herein

are solely attributable to Jakobsson & Söderbergh and

does not express any Fortum Corporation views.

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World primary energy supply:

petroleum stands for >50%

IEA, Energy Balances Database

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Abundance Myths

• ”[T]he oil resource base is adequately large and growing, with little prospect that its depletion could cause a supply crisis in any foreseeable future.” (Radetzki, 2010)

•“The world’s already proven reserves of oil – and the process whereby they

evolve – thus totally eliminate any significant up-side restraint on the development of production for the first quarter of the 21st century…” (Odell, 2004)

• “A common characteristic of the doomsday prophecies […] is that none of them has actually occurred” […] “The prophets of Peak Oil rely heavily on Hubbert (1956)” – Radetzki, 2010

• Is it really that simple?

• What are the key supply-side

factors in predicting the future oil

supply?

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World conventional crude production and oil prices

IEA, Energy Balances Database

Crude oil prices have

risen since 2002 due

to increasing demand

growth & absent crude

oil production growth

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World liquids supply by type in the IEA New Policies Scenario

Source: IEA (2011)

Crude oil prices have risen since

2002 due to increasing share of

unconventionals and NGL of world

liquids supply

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Oil Availability – a flow issue

• The economy needs a continuous flow of energy

• ”Availability”: production rate (barrels per day) at a given price

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• Resources in-ground are relevant insofar as they result in flows

• How is the amount of resources related to flows?

Bengt Söderbergh, Kristofer Jakobsson, 2012

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U.S. reserves and production

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000

Prod u c tio n ( Gb / y e a r) Prov e d res e rv e s (1 0 ’s o f Gb )

production proved reserves

Source: EIA

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What is actually meant by

”reserves”?

Definitions:

• Resources: total endowment of oil/gas

• Reserves: fraction of resources that is known and profitable to recover under present circumstances (usually low, medium and high estimates)

• Ultimate recoverable resource (URR): best current estimate of

past production + present reserves

+ future additions to reserves

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What is actually meant by

”reserves”?

• Reserve figures are not meant to enable aggregate production forecasts

• Purpose of reserve estimation is to:

• Account for a company’s physical assets

• Guide the development of the field where the reserve is situated

• Indicates that a field perspective is

more relevant than aggregate perspective

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Why do oil regions peak early?

Source: NPD

Large fields are discovered early and producing early

Norwegian North Sea peak occurred when 27% of

resources was produced

Statfjord

Discovery 1974 Production 1979

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Why do fields plateau and decline?

0%

1%

2%

3%

4%

5%

6%

7%

1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009

P roduct ion (s har e of i ni ti a l re s e rv e s per y e a r)

0%

2%

4%

6%

8%

10%

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

P roduct ion (s har e of i ni ti a l re s e rv e s per y e a r)

Statfjord

Oseberg Maximum

production rate is only a few percent of URR

Decline rate is typically

10-20%

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Thinking of reserves

with the right metaphor

Bucket:

When do we run out?

Sponge:

How hard can we squeeze?

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0 2 4 6 8 10 12

1 2 3 4 5 6 7 8 9 10

Pr o d u cti o n r at e

Year

Immediate Optimal (price = $2) Optimal (price = $1)

Explaining plateau production:

capacity investment

14 Parameters:

Resource size: 10 Unit capacity cost: $1 Discount rate: 10%

Oil price: $2

In a nutshell:

The producer must weigh a rapid realization of

profits against a low investment cost

Optimal production:

MC = price (by definition) AC = 2.5/10 = $0.25

AC = 1.67/10 = $0.167

NPV = $13.3

Marginal cost differs from average cost

NPV = $8.2

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Explaining field plateau production:

capacity investment insights

• Maximizing profit is not the same thing as maximizing production

• Marginal cost (= the price) is not equal to average cost

• Average cost varies with production rate

• Marginal cost of oil and gas production is unobservable, because of opportunity costs

• Cost structure (CAPEX, variable OPEX, fixed OPEX, etc.) is therefore crucial

• Average cost gives a picture of profitability, but does not say

anything about the reasonable market price of oil and gas

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Explaining gradual decline:

declining productivity in reservoir

Structure of a petroleum reservoir

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Oil and gas fill the pores of porous and permeable rock

Source; C.Gen

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The flow rate

The flow rate is determined by:

• Flow area (the number of wellbores)

• Pressure difference (reservoir vs. wellbore)

• Viscosity of fluid (i.e. its resistance to flow)

• Permeability of reservoir rock

Source: MDM Energy

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Consequence:

Declining reservoir productivity

Pressure decline

Increasing

fraction of

unwanted

fluids

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Why produce at different costs simultaneously

IEA, World Energy Outlook 2009

Statoil are producing in the North Sea and Canadian oil sands

Two production types with

different unit costs produce

simultaneously, but at different

rates. Same marginal cost,

different average costs

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Explaining why large fields are discovered and produce early

Lognormal distribution

• Few large fields, many small ones

• The large fields still stand for a major share

of the resource

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Decline in existing global

production, new fields discoveries

• Decline in existing production. The decline rate will vary from year to year depending on the composition of fields in production.

• Average yearly Non-OPEC decline rate estimated at 3-5% per year, OPEC decline rate estimated at 3-4% per year

• In real numbers the global oil production capacity base loses about 3-4 million barrels per day (Mbpd) each year

• Declining new fields discovery trend.

Most of the world's conventional oil was discovered between 1946 to 1980. Discoveries peaked in the 1960s and have fallen steadily since, although with an upturn for the last decade.

• Long lead times for green field developments.

Global average for discovery to start of production non-OPEC giant fields is about 3 years. Large fields (>300Mb) average build up period of 6 years. Small fields (<300Mb) build up over an average of 3 years

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The Importance of Giant Fields

• 70,000 oil fields were in production in 2007

• About 60% of crude oil production derived from 374 fields (54

supergiant and 320 giant). An additional 84 giant fields were either under development or ‘fallow’.

• Approximately half of global production derived from only 110 fields, 25% from only 20 fields and as much as 20% from only 10 fields, with Ghawar accounting for a full 7%

• Most of the 20 largest fields have been in production for several decades and 16 of them are past their

peak of production.

• The world’s second largest oil field, Canterell, peaked in 2003 and its production has since declined by ~70%.

• Around 500 fields account for two thirds of cumulative oil discoveries.

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The Importance of Giant Fields

Production from 333 giant fields Compared with Total World

Producti

Source: Robelius, F. 2008

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Giant Fields Discoveries 1900-

2000

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Backdated Global Oil Discoveries

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Modeling - IEA’s World Energy Outlook

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Own verification of model

• In the IEA 2010 Scenario oil

production increases by 15 Mbpd between 2009 and 2035

• As consequence, there is a need to add 67 Mbpd of gross capacity 2009- 2035 to compensate for the decline at existing conventional oilfields and to meet the incremental growth in demand.

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Modeling- Uncertainty about future production

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Final conclusions

• Availability is about flow rates

• Understanding the relation between reserves and flow rates requires a field level perspective

• Costs and cost structure essential for availability

• Availability may decline early (because of gradually declining productivity in production and exploration)

•Should we be concerned about exhaustion? No.

• Should we be concerned about oil

availability? Yes!

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Thank you for your attention!

Photo: Bengt Söderbergh

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References

Energy Information Administration. Petroleum Navigator (www.eia.doe.gov).

International Energy Agency. World Energy Outlook (various issues). OECD, Paris.

Jakobsson, K., Bentley, R., Söderbergh, B., Aleklett, K., 2012. The end of cheap oil: Bottom- up economic and geologic modeling of aggregate oil production curves. Energy Policy 41, 860-870.

Jakobsson, K., 2012. Petroleum Production and Exploration: Approaching the End of Cheap Oil with Bottom-Up Modeling. Doctoral thesis, Uppsala University.

Norwegian Petroleum Directorate. Fact Pages (www.npd.no).

Odell, P.R., 2004. Why Carbon Fuels Will Dominate the 21st Century’s Global Energy Economy. Multi-Science Publishing, Brentwood.

Radetzki, M., 2010. Peak Oil and other threatening peaks - Chimeras without substance.

Energy Policy 38, 6566–6569.

Söderbergh, B., Jakobsson, K., Aleklett, K., 2009. European energy security: The future of Norwegian natural gas production, Energy Policy 37, 5037-5055.

Söderbergh, B., Jakobsson, K., Aleklett, K., 2010. European energy security: An analysis of future Russian natural gas production and exports. Energy Policy 38, 7827-7843.

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Modeling- Aggregate production result

Combine discovery scenarios with the previous field

production model

Availability declines when only 24-30% of total recoverable

resource is produced

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Modeling - Uncertainty about future rate of discoveries

) 1

( e ^b ^CumExpl URR

CumDisc   ^ ^

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Explaining simultaneous

production at different costs

-0.5 0 0.5 1 1.5 2 2.5 3 3.5 4

1 2 3 4 5 6 7 8 9 10

O pti m a l prod uc tio n rate

Year

unit CAPEX = 1

unit CAPEX = 4 MC = price = $2

AC = 2.51/10 = $0.25 AC = 1.14/10 = $0.44

Same marginal cost, different average costs

Source: Jakobsson, K. and Söderbergh, B., 2012.