Global Oil Demand and Supply Outlook: 2013 to 2015

In a time of considerable economic uncertainty, with modest oil demand but significant new supply coming from North America, opinions vary widely about future price trends.  This report addresses key issues impacting supply by addressing over twenty separate geographic sources of production while using consensus demand estimates for the years 2013 through 2015.  It discusses sources of new production and political uncertainties in specific countries which have the potential to significantly impact available supply.

 

While oil demand is expected to grow an average 1.1%/year to 2015, global capacity should be more than adequate albeit subject to meaningful natural decline, rising marginal costs and aforementioned political uncertainties.  This will create changes in trading patterns with new North American production backing out imports from the Eastern Hemisphere, Mexico and Venezuela as both Canadian and North Dakota crudes reach Midwestern and Gulf Coast refineries.  Such a scenario might logically lead to price weakness when supply of a commodity exceeds demand.  The oil business, however, seldom reflects simple economics.  As this report will imply, prices should exceed those that one might expect in a simple supply/demand scenario due to identifiable political turmoil, social costs in key OPEC producing countries, and rising marginal costs of new production.  Accordingly, given these above-average uncertainties, I continue to use an average $100/ barrel (bbl) for global Brent oil prices and $95 for West Texas Intermediate (WTI).  There can be at least a 10% trading range either side of these forecasts with refinery shutdowns, accidents, weather events and political unrest the usual causes.  This scenario should provide a positive environment for exploration and development of new crude sources, ranging from quality oily shales to deep water prospects.  Accordingly, I remain positive about the investment attraction for specific oilfield service and exploration and production companies.

 

Global oil demand growth (see Table I) will be modest in 2013 to 2015 due to declines in both North America and Europe, offset by increases elsewhere.  I offer little incremental insight into these government estimates beyond the obvious observation that developed economies reflect a slow recovery (if any) from a severe recession while improved automobile mileage is depressing gasoline demand.  Some observers, however, may be surprised at the rapid increase in demand beyond China and India.  It is particularly strong in the Middle East, and certain countries in both Africa and South America.

 

Global oil supply (see Table II), by contrast, is the focus of this report.  It begins with the assumption that natural decline rates exceed estimates of most analysts.  Based on my past experience, dealing with reservoir specialists in almost every major producing basin in the world, I believe average annual global decline approximates 4% or 3.5MM barrels per day (bpd)/year.  It varies from such extremes as 13 to 15% in Iran and Venezuela to much lower levels elsewhere and near zero for Alberta oil sands.  The most important of these assumptions must be for Saudi Arabia where Saudi Aramco has never given precise guidance but years of evidence from American service companies in the Eastern Provinces suggest aging reservoirs are declining at an accelerating rate (possibly in the 4 to 6% range), requiring increased development drilling and pressure maintenance expenditures to keep overall production capacity from declining.

 

The largest increments to supply will come from the United States and Canada where spending has shifted dramatically to unconventional oily shales and Alberta oil sands development while more traditional oilfields are being allowed to decline rapidly.  US crude production should average 10.0MM bpd this year, the highest level since 1992, as the North Dakota Bakken, Colorado Wattenberg and both the Texas Eagle Ford and Permian Basin reach markets through new pipeline completions and railroad connections.  While these developments receive considerable attention, one reads much less about older, traditional oilfields that are being ignored, creating an acceleration of decline rates that are significant in the best of times.  Other key variables are meaningfully greater Natural Gas Liquid volumes from wet gas shales but a moderation of ethanol production, given its questionable economics.  The net result, and subject to further revisions over time, implies sharp gains in US crude oil and liquids production through 2015 at which time total output should be 36% above the levels achieved in 2011. 

 

Some of the predictive uncertainty is attributable to prices and marginal operating costs.  My assumption of $100 Brent and $95 WTI presumes an ending to the Cushing OK inventory glut as new pipeline access to the Gulf Coast brings international equivalent realizations to previously undervalued domestic crude.  It also assumes that any decline in wellhead prices below $85 will have negative implications for further drilling on the periphery of such high potential areas as the Bakken and Permian Basin.

 

Canadian production is rising as new developments reach initial production.  My assumptions include approval of the Keystone XL pipeline with initial volumes reaching the United States in 2Q 2016.  Meanwhile rail and existing pipelines will permit volumes to rise at least 200,000 bpd/year.  If Keystone is not approved, pipelines will be constructed to both British Columbia and New Brunswick ports with similar production delayed only one year beyond those assumed being exported to the United States.  Once again, prices are important.  The discount of Western Canada Select (WCS) crude oil (versus WTI) has narrowed from $25/bbl, at the time of my Calgary visit in May, to a current $15/bbl.  This will reflect current transportation cost and capacity but should decline further if and when Keystone is approved and operating.  Led by new production from the Exxon/Imperial Kearl project plus expansion of Cenovus, Devon and Suncor  operations, overall Canadian production should reach 4.4MM bpd by 2015, up 26% from 2011.  All-in operating costs vary widely from a $40/bbl range for Cenovus  and Kearl to much higher figures for several older open-cut mines.  As a result, any slippage in WCS prices to below $60/bbl could have negative implications for overall production growth.

 

Projecting crude oil supply from outside North America involves a combination of geological/exploration understanding for each country with an overlay of political risk, where appropriate.  I follow drilling actively on a global basis by analyzing the geologic and economic potential on a case-by-case basis.  As an example, one can be incredibly impressed by the oil potential of offshore Kazakhstan but, having spent a week there understanding the complexity of its reservoir, overwhelming downhole pressures and hydrogen sulfide content, and their Byzantine politics, one can conclude that this will never be a world class oil source.  Likewise the Orinoco Province of eastern Venezuela may be the world’s largest accumulation of hydrocarbons but its ultra-complex crude and anti-American policies leads one to avoid dependency on that resource under all circumstances.  On the other hand, the economic geological-political profile of northern Iraq’s Kurdish province appears significantly favorable to warrant inclusion in a 2015 outlook.  Nonetheless, many of the countries in Table II, plus others that don’t even have meaningful oil production, are experiencing sufficient political turmoil to put at risk any forecast of future production with reasonable accuracy.  So let’s discuss seven of these countries:

 

Algeria has significant oil potential in the southern Sahara.  Costs, however, are very high and are compounded by al-Qaeda terrorism that is making it difficult to attract and retain technically trained oilfield workers.  As a result, assuming a continuation of such risks, a flat production outlook could even be optimistic @ 1.2MM bpd.

 

Libya, next door, has the same problem.  With no functioning central government since the removal of Muammar Gaddafi in 2011, drilling activity is being negatively impacted, new contracts remain unsigned, and natural decline may soon impact production which is assumed to fall at least 15% from the pre-revolutionary 1.4MM bpd.

 

Angola is a relative success story given massive deep offshore oil reserves.  While it’s officially communist government remains willing to sign production sharing agreements with international majors, high costs make exploration attractive only when Brent prices exceed $95/bbl.  This remains, however, an active drilling province making my estimate of flat production @ 1.7MM bpd possibly conservative.

 

Iran is a real tragedy where one of the world’s potentially largest producers remains on the United Nations black list – unable to attract exploration spending by other than the Chinese and limited to selling its crude to just a few Asian customers.  Having studied Iran’s geology and visited its oilfields with international service companies, I am well aware that this is one of the two least explored-high potential countries on earth.  Claimed reserves are 137B bbls but, using modern drilling technology, recoverable oil is well over 180B.  From a peak of nearly 6MM bpd in 1977, production fell to 1.5MM, shortly after the 1979 revolution and is now just 2.9MM bpd.  With little access to capital or modern technology, production will be lucky to avoid falling over 10%/year under current international sanctions.

 

Iraq is the source of both enormous potential and total frustration to the world’s oil industry.  As I discussed in a June 2011 report (copies available on request), official reserves of 143B bbls grossly underestimate the country’s potential.  With almost no drilling during the Saddam years, until he was overthrown, estimates of ultimate recoverable reserves have varied widely, but my best estimate remains about 480B bbls, making Iraq the largest potential producer in the world.  Of course “potential” remains elusive, given chaos in the southern oilfields which have led international majors to abandon drilling programs and move to the politically more stable Kurdish province in the north.  As a result, we see southern Iraq production falling again but northern discoveries offering considerable potential once pipeline routes are established through Turkey to the Mediterranean.  While this country could probably produce 10MM bpd, given ten years of peace and reasonable production sharing agreements with IOCs, such targets are unrealistic under current chaotic government arrangements.  I anticipate modest increases from the present 3.0MM bpd by 2015 with wide variability due to political uncertainty.

 

Saudi Arabia has served as the swing producer within OPEC for decades.  This situation should continue despite active development drilling that is helping offset meaningful (but undisclosed) natural decline – particularly in the seventy year old Ghawar field, the world’s largest.  The Kingdom has shifted much of its budget to natural gas development in order to free-up for export about 1MM bpd of crude, currently consumed to generate electricity. This helps maintain exports capacity by offsetting the loss of output from its older oil fields.  Beyond their geological challenges, however, they must address a budget that requires high social spending to maintain political calm in a turbulent world where Sunnis and Shi’a are fighting for supremacy on most of its borders.  I believe $100/bbl is needed to balance their budget while sustaining an active drilling program.  Accordingly, Saudi Arabia has demonstrated, despite rhetoric to the contrary, that it will continue to give up market share within OPEC to keep global oil supply in concert with demand.  As the de-facto swing producer in my Table II model, I have Saudi Arabia holding production near 9.4MM bpd although this could rise or fall about 6% to accommodate anything from higher/lower world demand or a loss of production elsewhere due to weather or political events.

 

Venezuela is another wild card for global oil supply.  While official oil reserves are now 211B bbls, second only to Saudi Arabia, this is due to including 112B of extra-heavy oil from the Orinoco belt.  Traditional reserves of 99B, primarily from the Lake Maracaibo area, are in steep decline exacerbated by an equally sharp drop in development drilling.  This is due to political chaos that finds a majority of the best engineers having fled the country.  Given severe currency restrictions, continued anti-Yankee rhetoric, and high costs of its Orinoco crude, Venezuelan exports may experience a major collapse in the near future.  Once Alberta crude reaches Midwest and Gulf Coast refineries in greater quantities, Venezuela will be the primary loser.  I assume total production, which peaked at 3.5MM bpd in the mid-1990s, will fall to 2.2MM this year and maybe below 2.0MM by 2015.

 

The purpose of discussing these seven major producers is to highlight the impact of marginal costs and political turmoil on the world’s oil supply.  Their combined 22MM bpd represents 72% of OPEC production with varying degrees of predictability.  While I consider Saudi Arabia a relatively “safe” source for the next few years, the other six are much less predictable.  Thus, if we exclude  Saudi Arabia, that implies 13MM bpd (14% of global output) is somewhat at risk.  Then one adds chaos in neighboring countries like Syria or Egypt, neither of which are meaningful oil producers.  There are concerns violence may spread in Egypt, endangering the 2.5MM bpd passing through the Suez Canal.  While I do not share this feeling, much of the recent surge in Brent oil prices (to $109/bbl today) reflects that concern.

 

Conclusion:  In attempting to predict global oil prices for the 2013-2015 time frame, I believe markets will reflect above-average concerns about political instability.  While there remains 2.5MM bpd of theoretical excess capacity in the world, it resides primarily in Saudi Arabia and will remain in reserve for their own budgetary reasons.  Accordingly, an average Brent price of $100/bbl, with possibility it could even be $5 to 10 higher at times, seems appropriate for establishing the basis for evaluating our integrated oil and oilfield service securities.

 

 

 

Table I

GLOBAL CRUDE OIL DEMAND

MM bpd

2011

2012

2013e

2014p

2015f

2015f vs. 2011

North America

24.1

23.7

23.5

23.3

22.8

-5.4%

Europe

15.0

14.5

14.2

14.0

13.8

-8.0%

Latin America

6.3

6.5

6.7

6.9

7.0

11.1%

China

9.2

9.6

10.1

10.5

11.0

19.6%

Asia – ex. China

19.2

19.9

20.1

20.3

20.5

6.8%

Middle East

7.4

7.7

7.9

8.2

8.7

17.6%

Former Soviet Union

4.4

4.5

4.6

4.7

4.8

9.1%

Africa

3.3

3.5

3.7

3.9

4.1

24.2%

Total – MM bpd

88.9

89.8

90.8

91.8

92.7

4.3%

 – % Change

1.0%

1.1%

1.1%

0.9%

Sources:  Energy Information Agency and OPEC Monthly Oil Market Report

 

 

 

 

 

 

 

 

 

 

Table II

GLOBAL CRUDE OIL SUPPLY

MM bpd

2011

2012

2013e

2014p

2015f

2015f vs. 2011

United States

8.3

9.2

10.0

10.8

11.3

36.1%

Canada

3.5

3.8

4.0

4.2

4.4

25.7%

Other North America

2.8

2.8

2.7

2.6

2.5

-10.7%

Europe

3.9

3.6

3.2

3.0

2.9

-25.6%

China

4.2

4.2

4.3

4.3

4.3

2.4%

Asia – Ex China

4.2

4.2

4.1

4.1

4.0

-4.8%

Former Soviet Union

13.6

13.7

13.7

13.7

13.9

2.2%

OPEC:
Algeria

1.3

1.2

1.2

1.2

1.2

-7.7%

Angola

1.7

1.7

1.7

1.7

1.7

0.0%

Ecuador

0.5

0.5

0.5

0.5

0.5

0.0%

Iran

3.6

3.0

2.9

2.7

2.7

-25.0%

Iraq

2.7

3.0

3.0

3.1

3.2

18.5%

Kuwait

2.5

2.8

2.8

2.8

2.8

12.0%

Libya

0.5

1.4

1.2

1.2

1.2

140.0%

Qatar

0.8

0.7

0.7

0.7

0.7

-12.5%

Saudi Arabia

9.3

9.7

9.4

9.3

9.4

1.1%

UAE

2.5

2.6

2.6

2.6

2.6

4.0%

Venezuela

2.4

2.4

2.2

2.1

2.0

-16.7%

OPEC Total

29.9

31.2

30.1

29.7

29.8

-0.3%

OPEC %

33.7%

34.2%

33.0%

32.4%

32.2%

Other Middle East

1.7

1.7

1.7

1.7

1.7

0.0%

Other Latin America

4.3

4.3

4.4

4.4

4.4

2.3%

Other Africa

2.4

2.3

2.2

2.2

2.2

-8.3%

Other Natural Gas Liquids

5.8

6.3

6.6

6.8

7.0

20.7%

Processing Gains

2.1

2.1

2.2

2.2

2.2

4.8%

Biofuels

1.9

1.9

1.9

1.9

2.0

5.3%

TOTAL

88.6

91.3

91.1

91.6

92.6

4.5%

Source:  OPEC Monthly Oil Market Report (for 2011 to 2013)

 

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