Future Look I

Table of Contents

FutureLook Introduction ............................................... 3

Next steps for African national oil companies .......... 4

When will Iraqi production make itself felt in the
global oil market? ......................................................... 11

The impact of territorial disputes on E&P in Asia ... 16

Latin American new horizons: east, west or home’s
best? ................................................................................ 24

The production prediction predicament and Regional
Decline Theory™ ........................................................... 32

This report contains forward looking statements that are subject to risk factors associated with oil and gas businesses. It is believed that the expectations
reflected in these statements are reasonable, but they may be affected by a variety of variables and changes in underlying assumptions which could cause
actual results or trends to differ materially, including but not limited to: price fluctuations, actual demand, currency fluctuations, drilling and production
results, reserve estimates, loss of market, industry competition, environmental risks, physical risks, legislative, fiscal and regulatory developments,
economic and financial market conditions in various countries and regions, political risks, project delay or advancement, approvals and cost estimates.

Copyright © 2010 NewsBase Ltd -2-

FutureLook Introduction
Welcome to NewsBase’s inaugural FutureLook Report.
As you are no doubt aware, NewsBase sells weekly reports on the global oil and gas
industry that aspire to tell the reader what’s going on and why in the energy world. We
do not, sadly, sell crystal balls!
But we believe that our job is to look forwards as well as back, so we have come up
with a new publication, namely a collection of reviews of “What Next” on a selection
of regions and subjects which aims to look at the future and make some firm predic-
tions about what might happen next.
Building on our team’s in-depth knowledge of current affairs, we hope that decision-
makers in the energy industry will benefit from our thoughts. Believing in a “do what it
says on the box” approach, we have christened this new publication “FutureLook.”
FutureLook I seeks to delve into some of the most interesting issues in the industry at
present and to offer some idea how these will play out in the future. FutureLook I has
been put together after months of research, topped by a weekend at a retreat in the
Scottish countryside discussing each region in a series of seminars which were attended
by leading industry experts to add further informed comment and to test and challenge
assumptions and predictions and (we hope) end up with insight which is as useful as it
is accurate.
In FutureLook I we cover:
• The role of the National Oil Company (NOC) in Africa;
• The prospects for production in Iraq (with some interesting thoughts on what will
happen in Kurdistan);
• EEZ roadblocks to exploration and production caused by territorial disputes in
Asia;
• How state oil companies will cope with the problems and opportunities emerging in
Latin America;
• And finally, we table an interesting and challenging new methodology for produc-
tion prediction on a global scale, to which we have given the catchy title “Regional
Decline Theory”TM.

We look forward to your comments and thoughts – Good? Bad? Indifferent? If we
have added some value to your business please let us know, and we will make Future-
Look a permanent feature of our publishing calendar.
And while we can’t promise crystal ball-style predictions, we will do our best to offer
you a look at the trends and developments we believe are emerging in the global energy
industry in the future.


Next steps for African national oil companies
Introduction
National oil companies (NOCs) have come to be recognised as an ever more powerful
force in the world’s oil industry. Controlling a majority of the world’s reserves and
production, a dozen of the largest NOCs influence their respective country’s domestic
and foreign policy as much as its industrial policy, and often act as the main provider
of state spending as well.
NOCs can be broadly divided into two groups. The first set may be loosely described
as the exporters, with extensive reserves and production. These grant – or sometimes
do not – access to foreign operators. The second are importer NOCs, companies
whose agenda is dominated by attempts to secure long-term oil supplies for their
domestic markets, either because their own production is declining, or because they
have none at all.
The most significant of Africa’s NOCs are the exporters, and corruption and
inefficiency are commonplace, though not yet endemic. Africa has one major importer
NOC – PetroSA – which is driven by necessity, history and culture to be more business
-oriented, with a greater emphasis on efficiency and accountability.
Our contention is that exporter NOCs should partner with and so learn from
importer NOCs, by striking deals to access foreign acreage and opportunities. We also
make some FutureLooks on what both types of NOC are likely to do over the next five
years.

Eminent peers
Norway’s acceptance of an inevitable decline in domestic hydrocarbon reserves has
spurred Statoil to invest overseas, and the company now has a global portfolio and is
looking for more. In short, Statoil is in the top rank of the world’s energy companies,
both national and commercial.
The NOC family does, of course, have other respectable and successful leaders. China
National Petroleum Corp. (CNPC), Brazil’s Petrobras, Abu Dhabi’s TAQA and, of
course, Saudi Aramco have all successfully managed their own asset portfolios, built
and reinvested value, and have also expanded beyond their domestic interests, using the
experience gained at home to great effect abroad.

Petrobras, for instance, is deploying its deepwater expertise in the US’ Gulf of
Mexico, in Angola and in Mozambique. Aramco has made various downstream
investments, choosing to lock in more of the value chain opened up by its position as
the world’s pre-eminent oil producer, for example by making refinery investments in
the US, China and Japan.

So, exporter NOCs benefit by exposing themselves to foreign practices and
technologies through pursuing opportunities overseas, and open routes to downstream
margins.


Additionally, foreign involvement teaches exporter NOCs how to overcome the
challenges of working under other legal regimes – Sonangol, for instance, has worked
successfully in the US with local partners, and that lesson will be applied well elsewhere.

A straight comparison between African NOCs and the first rank of the world’s more
successful exporter NOCs is, though, probably unfair. The hurdles African states face
surpass those jumped by the handful of NOCs listed above which grew in countries
with homogeneous, skilled populations who are generally habituated to the rule of law,
and which have generally benefited from decades of peace. The lessons don’t
necessarily travel easily.

A closer peer for Africa’s NOCs is Russia’s Gazprom. The company has obvious
flaws – a profound lack of transparency, for one – but Gazprom has proved to be
effective at sealing deals with foreign companies that provide it with access to foreign
assets and to downstream distribution, and has for the most part been seen to honour
its contracts and work as a good commercial partner. As an example Gazprom – the
world’s largest gas producer – traded stakes in the giant Yuzhno-Russkoye field for
equity in various assets held by E.ON and BASF. The Russian company has struck
similar deals with Eni, thereby gaining access to the Elephant oilfield in Libya.

Downstream strategy
The big four African NOCs – Sonatrach, Sonangol, Libya’s NOC and Nigeria’s NNPC
– share a common problem with Gazprom: while all have some domestic consumers
(at varyingly subsidised prices) all also have a need to secure export consumers and a
desire to keep as much of the downstream margin as they can. Signing deals to acquire
foreign downstream capacity should therefore be a key goal in these four companies’
strategies.
Sonangol and Sonatrach are indeed taking this approach, and have already made some
progress, while Libya’s Oilinvest – via its Tamoil subsidiary – holds stakes in Italian,
German and Swiss refineries, along with a network of fuel stations in Europe and
several African states. Additionally, a subsidiary of the company is working on various
infrastructure deals, including the extension of a pipeline from Kenya to Uganda, and
the Libyan company has talked of building a refinery in Egypt.
Sonangol, Angola’s state-owned NOC, has a share in a terminal planned by Gulf
LNG, near Pascagoula in the US, and a 75% stake in Sonangol-Congo, which works in
the Democratic Republic of Congo (Kinshasa). Sonangol has also branched out
beyond the hydrocarbon sphere with some holdings in Portuguese banks, and has
considered investments such as a bauxite development in Guinea Bissau.
Sonatrach holds stakes in various pipelines transmitting its gas production north to
Europe, including the Medgaz, Galsi and Transmed links. The Algerian company also
struck a deal with Statoil, giving it the right to an amount of regasification capacity at
the Cove Point LNG terminal. Nigeria’s national champion (NNPC) has meanwhile not
only failed to gain toeholds abroad, but has even failed to make much headway in
boosting its domestic refining capability. The country’s four refineries currently run at
around 25% of their nameplate capacity.


NNPC is by far the weakest African significant NOC, hampered by corruption,
government interference, cash extraction for the state budget, and of course, politically
inspired violent disruption as well. Our FutureLook is that NNPC will continue to fail,
while its stronger cousins will carry on looking for new downstream assets to invest in
around the consuming world. We come to some obstacles and opportunities in that
strategy below.
South Africa’s PetroSA is planning a substantial domestic refining project, Project
Mthombo, a 400,000 bpd refinery in Coega, in the Eastern Cape. The project is
ambitious and is intended to support energy security for South Africa. However, in
order to feed this plant, the country will still need to import crude oil as feedstock.
Dependency on foreign supply has merely been shifted up the production chain.

Upstream strategy
It is likely that African NOCs will use their domestic assets as bargaining chips in their
search for downstream deals abroad. What is more interesting is that African NOC
strategy already includes acquisition of acreage and producing assets, not only in Africa
but elsewhere, and seems set to carry on in that vein. Sonangol, for instance, struck a
deal swapping equity in Angolan blocks for shares in areas offshore the US, with Cobalt
International Energy. The Angolan company also has stakes in Gabonese and Nigerian
blocks, for reasons that are not clear.
Algeria’s Sonatrach has also worked to move beyond the country’s border, striking
deals to secure acreage in North Africa – offshore Egypt, Mauritania, Mali, Libya – and
further afield, in Peru. Both Sonangol and Sonatrach have pursued this move overseas
through commercial deals combined with political leverage. Sonatrach, for instance,
struck a deal with Total for acreage in Mauritania’s Taoudeni basin. The Algerian
company holds substantial sway in Nouakchott, while the French company has signed
on to various infrastructure deals in Algeria. So far Libya is the exception to the
upstream internationalisation, perhaps confident of its place as Africa’s top oil reserve
holder in its own right. However, Tripoli has acquired a stake in Italy’s Eni – with the
approval of Rome – with the stated aim of taking 5-10% of the Italian company’s
shares – giving it a kind of interest in overseas reserves, if at one remove.
NNPC, again, has failed to make much progress in acquiring production assets
overseas. The company’s Nigerian Petroleum Development Corporation (NPDC) did
manage to win a block in Equatorial Guinea’s much-delayed bid round, alongside
AFEX Global, but uncertainty over the outcome has led some observers to speculate
that the award will be scrapped and there certainly seems to have been no progress
here. The Nigerian company has plenty to deal with on the domestic front: it is
habitually unable to meet cash calls for its joint venture commitments and is forced to
rely on foreign partners for funds. NNPC’s prospects are muddied further by
uncertainty over the company’s future. The country is discussing various new laws for
the oil and gas sector that include schemes to divide NNPC into perhaps seven
component businesses, the hope being that a partitioned NNPC would function with
greater efficiency and perhaps even bring some of the knowledge accrued over the
country’s long history of production to bear on foreign challenges.
Again, we are sceptical that NNPC will gain traction overseas in securing acreage or
producing assets.

But how much more?
Africa’s three leading NOCs have achieved some traction in the international market,
but we question their ability to scale up these efforts because of a number of obstacles
that stand in the way.
First, the leading African NOCs may correctly be viewed as extensions or branches of
their respective governments. The effect of this status will be to raise apprehensions
about intentions and agendas in the minds of regulators and governors of those
countries in which they would like to operate. Even where Africa’s NOCs pass the local
“sniff test” for deals we expect to see investable cash consistently being extracted and
spent on state budgets. NNPC has been effectively hobbled by such extraction, and we
think that all of the leading three African NOCs are vulnerable to this, and will suffer
accordingly over the next five years.
Secondly, investment by the leading NOCs will be hampered (though not altogether
obstructed) by both the reality and the perception of corrupt practices. Even where
corruption is absent, minor or isolated, foreign regulators and partners still fear that it is
present but unseen, and are likely to resist moves to invest in their jurisdictions by
African NOCs. This resistance will not necessarily be overt, and is actually more likely
to be subtle, and more or less invisible except to its targets. Anti-corruption laws in the
EU and US that punish the partners’ employees will also obstruct deal-making as
individuals hesitate to put themselves in positions where they might have to adopt
questionable practices in future.
Thirdly, Africa’s exporter NOCs are major reserve owners in their own rights. As oil
prices rise they will, we believe, continue on the well trodden path of resetting
production-sharing agreements (PSAs) with foreign oil companies in their own favour.
The industry has come to accept that as prices rise PSAs and other production and
profit-sharing contracts tend to get reset, and such resets by themselves will not cause
great problems (so long as the results are reasonably equitable), but African NOCs will
find it difficult to practice resetting with one hand, while trying to form binding
contracts for investment abroad with the same counterparties with the other. If Africa’s
leading NOCs want to work in the developed world as downstream owners we believe
that the price of access will be the honouring of upstream contracts. We also believe
that the leading NOCs will find this price is too high, and will accept restricted
downstream access as the price to be paid for the ability to reset upstream profit shares.
Fourthly, African NOCs live with the risk that the international policies of their state
owners will occasionally obstruct straightforward commercial deals. For example, Libya
has recently burned much geopolitical capital over its high-profile welcome home to
Abdelbaset al-Megrahi, and on a spat with Switzerland over treatment of Hannibal
Ghadaffi. Geopolitical and security concerns (real or imagined) obstructed the
acquisition of US ports by Dubai Ports World, and the acquisition of Unocal by the
Chinese. While incidents like these are quickly forgotten, if they are sufficiently
frequent then they can severely obstruct NOC access to downstream deals, and we
believe that there will be a pattern of such incidents going into the future.
Hence we conclude that Africa’s Exporter NOCs will complete fewer deals than they
would wish over the next five years.


The odd ball
So far we have paid little attention to Africa’s other major NOC – PetroSA. South
Africa’s state-owned NOC differs from its continental peers in that it has no
production reserves of its own – it is, in short, an importer NOC. PetroSA does have a
larger peer in Sasol, the world’s leader in coal-to-liquids (CTL) technology and
production. The state does have an 8% stake in Sasol but, in any case, the company is a
small producer compared both to the exporter NOCs and to South Africa’s oil
requirements.
In search of supply security PetroSA has therefore acquired exploration interests in
Egypt, Equatorial Guinea, Mozambique, Namibia and Sudan, and is actively seeking
new deals, with a particular focus on Mozambique and Namibia. These countries are
believed to hold some hydrocarbon promise, although they have so far been neglected
in terms of exploration. In its search for reserve assets PetroSA has benefited from its
obvious association with South Africa’s ruling party, the African National Congress
(ANC).
Mozambique hosted a number of ANC activists during their fight against apartheid,
and those relationships will sustain deal access. To the north Namibia was, until 1990,
administered by South Africa. While relations between Namibia and South Africa have
had their ups and downs, the two countries are still closely tied. PetroSA therefore has
special access status throughout Africa, and we believe that PetroSA will continue to
leverage its status and contacts to secure acreage and production across Africa wherever
it can.
More significantly for the exporter NOCs, though, is that we see an opportunity for
PetroSA to gain another level of leverage outside Africa. At present South African
companies are accepted in the commercial world as honest and straightforward
business partners. Europe, the US and Asia have long and reassuring experience of
dealing with South Africans, and do not have a perception that contracts will be
affected either by corrupt practices on one hand, or by state interference on the other.
South Africa is also geopolitically non-confrontational and secular. Hence if PetroSA
were to come calling in either the US, the EU or Asia in search of downstream assets
there would be little if any regulatory or political resistance.
Of course, being an importer NOC means that PetroSA probably has no strategy to
seek downstream assets outside South Africa, but we see an opportunity for PetroSA to
support its more pressing upstream agenda by helping Africa’s exporting NOCs to
complete downstream deals outside Africa. PetroSA could become a key and leading
partner to Africa’s exporter NOCs in downstream work in the EU, US and Asia,
bringing access, credibility, reliability, access to the international debt markets, and
commerciality to the table in exchange for favoured access to new acreage and reserves
in its partners’ upstream African portfolios.
This approach would sit well with South Africa’s position as Africa’s leading economy,
and would, we believe, be sympathetic to the exporter NOCs’ perception of African
unity of approach. We believe that this approach would work particularly well with
Sonangol and (if it were capable of doing deals at all) NNPC. We would not go so far
as to predict that a PetroSA-Sonangol partnership will happen, but we do observe that
it probably ought to.


A producer cartel
One possible strategy for Africa’s NOCs to adopt would be the creation of a new
producer cartel, either loose or tight. While there is superficial appeal for a cartel –
higher prices, Africa getting a satisfying advantage over the colonial West, some
geopolitical clout for poorer nations – we do not see that a cartel will form. First, the
cultural and historical gaps between north and south are too large.
Secondly, a cartel needs strong leadership to survive, and while Muammar Ghadaffi
has clear aspirations to African continental leadership he has never achieved this status,
as there are too many strong competing candidates among the family of African
nations. South Africa, which has a similar self image as a continental leader, has the
same north-south issue, and the same strong competition. Finally, an African cartel
would have significant problems managing its life in parallel or even in competition
with OPEC. In short, we do not think that an African producer cartel will form.

Where will they go?
Africa’s exporter NOCs may not succeed in obtaining as many or as large downstream
assets as they would like, but we have confidence in predicting that deals will indeed be
done. We believe that the majority of these will take place in the EU, rather than the
US.
The North African NOCs have had long relationships with Europe in the supply of
both gas and oil. Gas relationships by their nature nurture more trust and credibility
than oil relationships, and in spite of plentiful political difficulties over the past three
decades Libya and Algeria have been reliable partners for European governments and
consumers. It will therefore be hard to resist if they politely ask to acquire new
downstream assets.
Sonangol has no such track record, and is indeed probably leaning more towards
relationships with American companies and the US as a whole, given Washington DC’s
publicly stated policy of building long-term supply relationships with Angola. But we
believe that Sonangol will find the US reluctant to reciprocate by ceding downstream
ownership access. PetroSA’s cultural links and roots (if a company can be said to have
those) probably lie more towards Europe than the US, but we believe that PetroSA
could make a credible and successful entry into either market if it chose, and hence our
view that PetroSA and Sonangol should (and might) become downstream partners in
the search for deals.
Asia is too complex to call as a single region, but it is worth noting that Sasol is
heavily involved in CTL projects in China, and that Chinese companies are intensely
active all over Africa. But it is probably too early to make any useful predictions about
where African NOCs will end up in Asia, so we will resist the temptation to speculate,
other than to suggest that China is some way from being ready to open up, and that
India should probably be at the top of the shopping list for an African NOC. We
believe that ONGC would welcome African NOCs as partners partly in search of
secure supplies, partly as providers of capital and partly as counterweights to the close
and weighty influence of Chinese companies. Again, while we can see reasons for this
happening, we see no actual evidence of this as yet. Malaysia may also prove interesting
for South African companies, as the two countries have long-standing ties.

Finally, we expect to see Africa’s NOCs, both exporter and importer, looking for and
doing deals in Latin America, though they will be obstructed by resource nationalism.
Argentina is perhaps a prime target for downstream deals, with a growing domestic
demand and a declining indigenous supply, added to relative proximity and some
cultural touch-points.
However, Latin America outwith Brazil and Venezuela (where PetroSA has already
signed a crude processing and blending deal) does not offer great scale or great
exploration potential, so will remain an interesting sideshow to the main events.

Conclusion
In conclusion, we believe that Africa’s leading Exporter NOCs will continue to seek
downstream assets in the developed economies of the world, but that significant
factors will obstruct them. Most deals will take place in the EU, and involve Sonatrach
and NOC more often than Sonangol.

We believe that NNPC will be inactive for many years to come. We think it is possible
that PetroSA might partner with Sonangol, and that if it does then Sonangol will start
to succeed in obtaining assets in both the US and the EU.
Ironically, while deals will be obstructed by concerns around geopolitics, corruption,
contractual reliability and availability of cash, the more that Africa’s NOCs take part in
downstream deals the more reliable and commercial they are likely to become.
We do not believe that Africa’s NOCs will ever reach the status or standards of
Statoil, but we do think that they will become stronger and better than they are today,
and that the wider oil industry will benefit as a result.

Copyright © 2010 NewsBase Ltd - 10 -

When will Iraqi production make itself felt
in the global oil market?
Introduction
Iraq contains large oil and gas reserves, yet its potential as a producer state remains
relatively under-exploited.

With proven crude oil reserves of 115 billion barrels, ranking behind only Saudi Arabia
and Iran, Iraq is a world giant. In terms of production, however, the country is as yet a
relative pygmy, producing around 2.4 million bpd at present. Iraq’s reserves are both
relatively easy and cheap to reach, at least geophysically, and are highly likely to be
significantly understated, as little modern exploration work has been carried out during
the past three decades. Estimates abound, and are little more than guesstimates in
reality, but it seems likely that Iraqi reserves might well be double the published figure,
accounting for about one sixth of world oil reserves.

Even before its current troubles Iraq was effectively difficult, verging on impossible, for
international oil companies to operate in, having been at war with Iran for eight years in
the 1980s, and with Europe and the USA in 1991, and then subject to sanctions for
over a decade after that. On top of the difficulties brought by conflict, until the
removal of the Baath regime Iraq was in effect a state-controlled quasi-command
economy, and suffered all of the ill effects of that status. The culture of state control
and inefficiency persists even today. Hence Iraqi oil was starved of investment and
technology. In spite of these obstacles, until 2003 Iraq produced 3.5 mbpd. What are
the prospects for Iraq to return to, or to exceed, this level within the next ten years?

Geophysically a substantial increase in production is probably a relatively
straightforward task. Iraq has contracted with a number of international oil companies
to have oil lifted from its accessible reserves for as little as US$2 per barrel, giving them
the chance of making a only a tiny margin over lifting costs of perhaps US$1 per
barrel. While some companies have undoubtedly taken on its contract as an exercise in
goodwill and relationship building, these numbers are indicative of how easily Iraqi
production could be increased with only moderate investment, absent other factors (see
below). We believe that the limiting factor in Iraq will be political, not geophysical.

Politics
Iraq is essentially divided into three generally hostile camps: Sunnis (who do not occupy
prospective areas); Shiites (who do, and who are religiously but not culturally affiliated
with Iran) and Kurds (who also do, but who have no love for Sunnis or Shias). These
three groups have shown themselves to be readily willing to fight each other and
amongst themselves, and each has a set of external friends and enemies who are also
willing to supply money, weapons and people with which to fight.


We see no natural unifying force at work beyond a residual secular Iraqi nationalistic
feeling. Baathist Iraq was an essentially secular state in which Sunnis and Shias made no
more of their religious difference than do Protestants and Catholics in the United
Kingdom. In Baathist Iraq the Kurds, meanwhile, were simply suppressed. The invasion
of 2003, however, led inadvertently to a reawakening of an armed and dangerous ethno
-religious awareness, and it ceased to be possible to be a secular Iraqi nationalist (with a
small “n”). While we believe that there is a latent wish to return to a secular and calm
Iraq, particularly on the part of Sunni Iraqis (who have the most to gain from that
goal), the forces for division are probably stronger than the forces for unity.
Hence the Kurdistan Regional Government has been effectively trying to set up and
run its own oil regime (with 40 bn barrels of proven reserves and probably plenty more
as yet undiscovered) for two years, though in the face of opposition from Baghdad.
Exactly what is happening is unclear, but what is certain enough is that the Kurds are
not showing the effects of any secular Iraqi national feeling. Baghdad currently deems
all contracts signed by the KRG with foreign companies illegal, insisting that only the
central government can do business with IOCs. The KRG says that its oil deals are in
line with the principles of the Iraqi constitution, which was left deliberately vague at
birth. In any case, possession is probably nine tenths of the law. Unofficially Baghdad
has effectively blacklisted all firms operating in Kurdistan, preventing them from doing
business in Iraq. Chinese state heavyweight Sinopec is one name on the blacklist,
following its acquisition of Addax.
Our FutureLook on this point is that the Kurds will continue to try and operate as
independently as possible in a loose and weak federation of Iraq. The KRG will
attempt to resolve the question of oil ownership with a partnership structure, in which
revenues are “shared” (we expect the definitions of “revenues” and “shared” to
crystallise once the balance of power has been more clearly defined). In pursuit of this
aim it seems likely that the KRG will not, in the short term at least, work towards large
escalations in production, as these, if they happened, would simply increase the
pressure from Baghdad to bring the Kurds to heel.
At the southeastern end of Iraq’s oil axis the Shias are similarly showing little appetite
for surrendering to Baghdad what the capital thinks is its own. Funded and armed by
Iran, Iraqi Shias will continue to push for greater separation rather than unity. Having
no valid historic claim to an autonomous self-governing status, Iraqi Shias will frustrate
rather than build, and we expect this substantially to hinder production increases
wherever Shias succeed in obstructing. Again, increases in production would actually
play towards Baghdad’s wish to unify and control, and feed Baghdad’s coffers at the
same time.
So, what is our FutureLook for Iraqi output as a whole? At one end of the region the
Kurds will block until they have achieved a federal deal they can live with. At the other
end the Shias will obstruct while Iran’s influence is consolidated and stabilised. In the
middle lies the almost derelict East Baghdad field, where production started in 1980,
but which by 2008 had fallen to only 10,000 bpd. Potential reserves are estimated as
high as 27 billion barrels across five separate structures and formations, with APIs
ranging from 20 to 32.5. Overall, Baghdad seems unwilling to allow IOCs to become
involved as long-term equity partners in major new developments – an example of the
strength of cultural inertia.


These pressures are all essentially negative to production growth, working against the
natural and substantial force of a rise in immediate production potential obtainable
from only minor investment in wells, infrastructure and technology. If equity
ownership does open up it will probably be in East Baghdad, but it may take one or two
more licensing rounds for Baghdad to learn that Big Oil needs an equity upside to make
big long-term investments.
Our FutureLook is that the net effect of Iraq’s centrifugal politics will be that most of
the positive production potential will be stifled by politics for several years to come, but
not all. We do not believe that Iraq will bounce up to 5 or 6 mbpd in 2010, or even in
2011. Indeed, we reckon that it will be a decade before Iraq’s fields begin to reach their
geophysical promise (and we believe that they will only loosely be describable as
“Iraq’s” fields by then too). If pressured to put numbers to the story, we would estimate
that Iraqi output might pause in 2010 for a couple of years, and then rise by perhaps
0.5 mpbd for each of the next five years afterwards.

Who will be the key players?
Looking at a more micro picture, who will be engaged in the business of developing
Mesopotamian oilfields? Large oil companies are present, but not enthused by the idea
of becoming badly paid production contractors. The Chinese are also present (CNPC
in Iraq and Sinopec in Kurdistan), taking their usual long-term and relationship-based
approach to securing positions in production assets. Even if Sinopec itself does not
succeed, the relationship it has created will be inherited by other Chinese operators
down the line.
Finally, the region contains a brave contingent of smaller companies who are hoping
to secure an equity position in substantial fields by accepting large political risk in the
short term. It is probably easier for both Sunnis and Kurds to do deals with smaller and
lower-profile companies, as the balance of power will favour Iraq, and there will be
fewer accusations of “selling birthrights down the river to Big Oil”. Our FutureLook is
that the smaller and very small explorers will be busy doing deals that may not look like
equity deals but are nevertheless equity sharing, and that some of them will grow very
large on the foundations that they are now building.

The Turkish question
By way of rounding up this FutureLook at Iraq, we think it is worth speculating on
what influence Turkey might have on developments.
If Turkey were simply Iraq’s northern neighbour its role would be no more than as a
potential customer and export route. However, the political situation is more complex.
Ethic Kurds occupy a substantial part of southeast Turkey – a left-over from the
division of the Ottoman empire in 1919. Turkey has more or less ruthlessly oppressed
Kurdish autonomous movements since then, as did Baathist Iraq, and as does Iran, also
home to a substantial Kurdish minority in its northwest corner.
Now, though, for the first time in centuries, Kurds have achieved the beginnings of an
autonomous statelet in northern Iraq, and this statelet is likely to be rich in oil
production.

We see the potential (but not yet the realisation) for a substantial rapprochement
between Ankara and its Kurdish minority as the foundation for a degree of co-
operation, and perhaps even active friendship, between Ankara and the KRG. Such a
strategy would offer valuable prizes for both camps.
For the KRG, its prospects as an autonomous government would be enhanced if it
had an active friendship with its largest and most powerful neighbour. Indeed, we see
the potential for the KRG to become an informal client statelet of Turkey, as a way of
keeping Baghdad’s take from Kurdistan’s production low. The KRG’s price for such a
friendship would be a softening of treatment of ethnic Kurds in Turkey.
In return we see the potential for Turkey to become a safe export route for Kurdish
oil, accompanied by preferential rights to acquire what it needs for its own use at a
favourable price. In short, a Turkish/Kurdish rapprochement would give Turkey a high
degree of energy security and neutralise the background fear that the BTC pipeline
might one day be interdicted by Russia. To add to this substantial geopolitical prize,
Ankara would be seen in public as being generous to its Kurds, something it needs to
have recognised if it wishes to join the EU, while simultaneously providing a safety
valve for the more active and vociferous of its Kurds, who would be encouraged to
migrate towards Kurdistan.
Kurdistan, with a strong and friendly patron to its north, an oil export route free of
Baghdad’s control, and a Eurocentric stance (once Turkey is admitted to the EU) would
be a strongly viable candidate for independent statehood (there are precedents – in the
division of Czechoslovakia and the FR Yugoslavia. Creation of a new state is not such
a radical step as it sometimes seems). The strategy would also probably have the
support of the US, a long-term Turkish ally (notwithstanding Turkey’s rejection of
providing basing facilities for the Americans in 2003).
In opposition to this view of a possible outcome one might table the view that there
is too much old hatred between Turk and Kurd for it to happen, but it is interesting to
quote from a letter from Ms Bayan Sami Abdul Rahman (KRG High Representative to
the UK) to the Financial Times on 12th November this year –
“The increasing and multiple connections of trade and culture form a very good basis
for a thriving neighbourly relationship which could do much to boost the mutually
beneficial links between the Kurdistan region, the rest of Iraq and Turkey and thereby
help stabilise Iraq’s vital democratic and federal process.”
Rahman went on to say: “I hope that these positive developments are heeded in the
UK, US and Europe, which have not always understood the subtleties and complexities
of our relations with Turkey.”
If that isn’t a broad hint, then we would eat our hat.
We are not in essence making a FutureLook prediction that Kurdistan will become a
client of Turkey or an independent state, but we are saying that this could happen in
the next decade.


Elections and oil law
Iraq’s free elections in March 2010 will not, we think, influence much. As ever, the real
business of politics will happen behind closed doors inside and outside Iraq, and the
real business of oil will wait until real equity-sharing deals are on the table.

One of the stumbling blocks facing all oil sector developments is simply the lack of a
formal oil law. The question has been in limbo for the past three years and is not
expected to make any notable progress until after the January elections.

Even then, there is no real timescale as to when new legislation would be in place, how
it might look, or how it might be enforced against fractious and centripetal Kurds and
Shias.
In short, we do not think that Iraqi production will flood the market this year, next
year or the year after that. Iraqi oil will, of course, flow to the market eventually, though
much of it possibly in Kurdish or even Iranian barrels, and we would put that
“eventually” out to 2015 and beyond.


The impact of territorial disputes on E&P in Asia
Introduction
Blistering economic growth across Asia over the past few decades has cranked up
anxiety levels amongst governments about energy supplies.
Asia’s state-run national oil companies (NOCs), led by players like PetroChina and
Petronas, have become more confident about searching out new oil and gas assets in
foreign fields. But equally, the deep sense of vulnerability that grips Asian governments
with regard to energy security has led them to push their NOCs to search for easy-to-
access resources closer to home.
Such pressure has proved to be the catalyst for the eruption of tension over offshore
overlapping sovereignty claims in the South China Sea, where maritime borders are not
clearly defined and often overlap. Competing claims of territorial ownership across the
region mean that billions of barrels of oil are stuck underground, with companies
unable to access these resources until such wrangles are resolved.
This chapter will look at where such overlapping claims exist and which countries are
involved. It will show where there has been successful reconciliation of overlapping
claims between governments in the past, and make suggestions as to how there can be
further successful resolution moving forward.
The paper will also look to the future and suggest what the international oil industry
can do to smooth the way towards the settling of overlapping maritime claims in Asia
and the opening up of large reserves that are currently locked-in by fierce resource
nationalism.

Where are the disputes?
Thailand vs Cambodia
There has been no exploration and production activity in a disputed area between these
countries since the 1970s.

Malaysia vs Brunei
Total and Murphy have been awarded rival contracts by the countries’ governments in
the same area.
There are potentially huge oil reserves offshore the island of Borneo, but
development has been blocked by legal wrangles over sovereignty. The dispute escalated
to such a level that in 2003, a Malaysian patrol boat chased a Total exploration vessel
away from the area. Total subsequently halted all offshore work at the disputed Block J
area. A development contract for the block had been awarded to Total, BHP Billiton
and Amerada Hess by the Brunei government in 2002.


Malaysia, which has had territorial disputes with all of its neighbours, argues that
Brunei only has jurisdiction over its continental shelf, in waters up to 200 metres deep.
About three-quarters of Brunei’s claimed Exclusive Economic Zone (EEZ) is in waters
deeper than 200 metres.
Block J is within the EEZ claimed by Brunei. The EEZ stretches 200 nautical miles
out from Brunei’s shoreline, in a north-westerly direction.
On the Malaysian side, the disputed area covers Block L. Adjacent to Block L is Block
K, operated by Murphy Oil and Petronas Carigali, and which has estimated recoverable
reserves of 400-700 million barrels.

Bangladesh vs Myanmar (Bangladesh vs India)
The territorial rivalry between these countries has heated up recently and Bangladesh is
also competing with India for several offshore areas.
Tensions between Bangladesh and Myanmar came to a head in late 2008, when
drilling by South Korean contractor Daewoo in a disputed area led to naval
confrontation between the countries.
The small Bangladeshi navy responded by surrounding an exploratory drilling rig
installed on its eastern offshore boundary by Daewoo, which had received the Burmese
government’s blessing to operate in the area. The rig was withdrawn, but Bangladesh
and Myanmar continue to argue over the site.
Tension in the area is also likely to remain high, given that state-run Petrobangla is
ramping up offshore development and recently granted three offshore blocks to
ConocoPhillips and Ireland’s Tullow Oil, to explore for gas in the Bay of Bengal.
The awards have come after Bangladesh’s interim government divided the country’s
maritime territory into 28 blocks in the Bay of Bengal and invited exploration bids at
the end of last year.
The auction failed to generate much of a response, apparently because of the
lingering fear that more territorial disputes could erupt. Yet the Conoco and Tullow
awards suggest some IOCs are willing to take a punt on Bangladesh’s offshore, despite
the looming spectre of territorial disputes. CNPC is expected to follow soon.
India, Myanmar and Bangladesh have been asked to submit territorial claims to the
United Nations for settlement under the multilateral body’s Convention on the Law of
the Sea.
Speaking exclusively to FutureLook in early 2009, Jamal Ahmed, the former chairman
of Petrobangla, said: “It is true that Bangladesh has a long-running dispute with
Myanmar over its maritime border. This is an issue for the foreign ministry and we are
in ongoing discussions with Myanmar over this.”
“With regard to India, New Delhi has offered two offshore blocks in its NELP bid
round that overlap with our territory. When we tried to offer a block that we believe is
in our in our territory but [which] India claims overlaps [its territory], New Delhi
lodged a formal objection.”

“So the issue of overlapping maritime borders is also being discussed between India
and Bangladesh. Further talks are planned again soon.”
Ahmed has mixed feelings about whether joint development of resources in the area
can be achieved between the competing parties. “It is too early to tell, but other
countries in the world have had success in settling similar disputes, so there is scope for
success to be achieved in this case,” he said.

Indonesia vs. Malaysia
Shell and Chevron are tied up in a wrangle over maritime borders between Indonesia
and Malaysia.
Around five years ago, Malaysia won an International Court of Arbitration ruling over
Indonesia on the ownership of the Sipidan and Ligitan Islands off Sabah, on the other
side of Borneo from the area it disputes with Brunei. Malaysia and Singapore have also
squabbled over the sovereignty of the tiny Pedra Blanca Island, to the northeast of the
city-state.

China vs. Japan
In the East China Sea, Beijing and Tokyo have been bickering over the development of
two gas fields – known as Chunxiao and Longjing to the Chinese and Shirakaba and
Asunaro to the Japanese – for years.
The fields lie in Chinese waters near a median line drawn up by Japan to separate the
two countries’ overlapping EEZs. Disputed islands – Diaoyu to the Chinese, Senkaku
to the Japanese – are also located on the Japanese side of the median line. Critically,
however, the line is not recognised by China.
Despite lying in Chinese waters, Tokyo has argued that any development of the two
gas fields would deplete nearby deposits that lie in Japanese waters and has pushed for a
joint development programme.
But the critical point here, and with all the other cases considered in this paper, is that
oil and gas reserves are no respecter of artificial, man-made boundaries. Where an oil
or gas field straddles waters claimed by more than one nation, operations carried out on
one side of the line may have the effect of “capturing” the resource from that part of
the field on the other side of the border. This can lead to a race to capture the resource
first, which may be inefficient and detrimental to total field recovery. As Daniel
Plainview, the fictional oilman in “There Will Be Blood,” explained to his son:
“Drainage! Drainage, Eli! Drained dry, you boy! If you have a milkshake and I have a
milkshake and I have a straw and my straw reaches across the room and starts to drink
your milkshake. I drink your milkshake! I drink it up!”
Although China and Japan appeared to have reached an accord on how to share their
milkshake, in fact there has been no real progress. Moreover, the Japanese government
has expressed concern over Chinese vessels operating around the disputed gas fields
and Tokyo is worried that China might be attempting to develop the fields in violation
of the countries’ agreement.


China vs. ASEAN
China, Vietnam, Taiwan, the Philippines, Malaysia, Indonesia and Brunei each claim
sovereignty over parts of the South China Sea, including its land features, where
undiscovered reserves might be as large as 220 billion barrels. The size of each party’s
claim varies widely, as does the intensity with which they assert it. The claims primarily
centre on sovereignty over the 200 small islands, rocks and reefs that make up the
Paracel and Spratly Island archipelagos.
China and Vietnam both claim sovereignty over the Paracels, while also arguing over
the Spratlys with Malaysia, Brunei, the Philippines and Taiwan.
While Beijing has been willing to engage in talks with Tokyo on overlapping claims,
even if they have yielded few tangible results, it has taken a much more hard-line
approach with its Southeast Asian neighbours, which form an umbrella organisation
called the Association of Southeast Asian Nations (ASEAN).
When China submitted information to the United Nations to formalise key disputed
boundaries in May 2009, a Chinese Foreign Ministry spokesman asserted: “China has
indisputable sovereignty, sovereign rights and jurisdiction over South China Sea islands
and their adjacent waters.”
This entrenched notion of sovereignty suggests that tensions over the Paracel and
Spratly Island chains will remain high and that joint development of the area is a distant
prospect.

China vs. Vietnam
At a US Senate hearing in early 2009, State Department official Scot Marciel noted that
Washington was concerned about mounting tensions between China and Vietnam and
the steps the former was prepared to take to assert its regional claims.
“Starting in the summer of 2007, China told a number of US and foreign oil and gas
firms to stop exploration work with Vietnamese partners in the South China Sea or
face unspecified consequences in their business dealings with China,” Marciel told the
hearing, without specifying which companies he was referring to.
In June 2007, China’s criticism of a deal between Vietnam and BP over Block 5-2,
which lies near the Spratlys, caused BP to abandon exploration activities.
BP revealed in March last year that it was in talks with Vietnam to pull out of Blocks
5-2 and 5-3, although it declined to confirm whether or not pressure from Beijing had
influenced its decision.
In July 2008, Vietnam and ExxonMobil signed an exploration contract covering
waters off the Vietnamese coast, which China views as part of its historic claim to large
swathes of the South China Sea.
This led Beijing not only to object to Hanoi, but also to warn the US oil giant that if it
proceeded with its exploration plans then it would jeopardise existing and future
investments in the lucrative Chinese mainland market.


US Ambassador to Vietnam Michael Michalak told reporters at the time: “We [the
US] certainly don’t like anybody interfering in the commercial operations of companies
that are trying to carry out commercial contracts.”
Moreover, Marciel said: “We have raised our concerns with China directly,” adding:
“Sovereignty disputes between nations should not be addressed by attempting to
pressure companies that are not party to the dispute.”
Vietnam’s economic growth in recent years has been even more stellar than China’s.
The country’s increased need for energy has driven Petrovietnam’s emergence in recent
years and its move further offshore in the hunt for new resources. But its newfound
vigour in searching for oil and gas close to home could create a potential flashpoint
with China.
That view is shared by Mikkal Herberg, Research Director of the Energy Security
Programme at the National Bureau of Asian Research. He told FutureLook: “We already
have lots of cases of China and Vietnam raising tensions over their maritime border
and potential oil resources there.”
“When I was with ARCO [Atlantic Richfield Company, now part of BP] we signed a
block with Vietnam that straddled the Chinese claim and it was immediately pointed
out by Beijing in no uncertain terms that we should not proceed.”
“And they have literally had a couple of shooting matches out [at] sea in the past. So
as Vietnam moves out further offshore and China continues to build up its naval
capability to reach out further into the South China Sea with some authority, then I do
believe the potential exists for some unpleasant clashes to erupt.”

Resource nationalism
China’s clashes with Vietnam and Japan are typical of the growing resource nationalism
that has been seen around the world in countries like Venezuela, Russia and Libya in
recent years.
The global recession has inflamed geopolitical anxiety as nations seek to take control
of and exploit resources that are close to home. Governments are looking to secure
more oil and gas reserves wherever they can, and it naturally makes far greater financial
sense to look for them at home than to rely on importing them from overseas. Tension
is further fed by rising prices. Herberg comments: “I think if we continue to see oil
prices go up then it will accelerate concerns about the control of natural resources and
it will aggravate this potential problem of overlapping sovereignty claims.”
“The fear of scarcity of resources has not been quite as acute this year as it was last
year, when the crude oil price was running at around the US$140 per barrel mark. And
as the price continues to go up, that will be the primary driver of the scarcity fear that
[ratchets] up tension over disputed areas.”
“It is a chronic underlying issue in Asia, where there is burgeoning resource
nationalism combined with a patchwork of overlapping claims which, taken together,
have the potential to be a real problem.”


Resolution success
The mixture of resource nationalism and competing sovereignty claims is a complex
one and, looking to the future, the resolution of these intertwined problems appears
difficult. The settlement of territorial disputes depends on several key factors.
First, boundaries need to be delineated in a fair and objective way, using a process that
has been agreed upon by all parties that are involved in a dispute. That way, the results
of the process will be less likely to be questioned once they are published. This could
possibly be achieved via the United Nations and revised application of the UN
Convention on the Law of the Sea, but the issue still remains of who owned what
baseline assets when.
Secondly, where disputes are intractable, the concept of joint development must be
embraced by governments that are involved in overlapping sovereignty claims. It is
imperative that policy-makers in the region realise that ongoing disputes render locked-
in reserves worthless to all, as they cannot be exploited. Instead, governments should
learn to work together to exploit resources jointly, thus sharing the benefits of the oil
and gas that is freed up.
Of course, this concept works better in theory than it does in practice, once one takes
into account the geopolitical and historical considerations that permeate territorial
disputes (see China and Japan’s friction over the East China Sea gas deposits as an
example), but it can be done.

FutureLook: Joint development solutions
The joint development concept has proved a success in the overlapping sovereignty
claim between Thailand and Malaysia. The resolution of a dispute between the
neighbours through a joint development accord unlocked some 223 billion cubic
metres of natural gas in the Gulf of Thailand, which is shared by both sides.
Australia and East Timor’s co-operation in the Sunrise Gas Field in the Timor Sea has
historically been cited as evidence of a successful joint development programme.
However, some problems regarding the production of liquefied natural gas (LNG)
from the field have emerged in early 2010, which have cast a shadow over the joint
plans to develop the project.
But smoothing the way to these kinds of successful agreements is frequently an
arduous process that depends on a number of critical elements.
It is essential that there is political will on both sides to achieve a resolution. Excessive
nationalism frequently clouds governments’ judgement when it comes to territorial tit-
for-tats, but, when fiery jingoistic rhetoric is exchanged for cool economic calculation,
positive results are usually attainable.
Furthermore, commercial interests on both sides have to be aligned and a joint
development programme must seek to avoid sensitive sovereignty issues, i.e. it should
not require borders to be remapped, but simply focus on extracting resources and
sharing them appropriately.


Finally, there needs to be some reconciliation of regulatory regimes between all the
parties concerned so that joint development can proceed.

Role of IOCs
It is at this juncture that IOCs can play a role. IOCs tend to sit on the sidelines of
territorial disputes, waiting patiently for a resolution to be implemented so that work
can begin on extracting the resources that are locked in. Sometimes they become
embroiled in disputes themselves, as ExxonMobil has discovered in its dealings with
Vietnam and China, but IOCs are not states, and in general don’t wish to play the role
of states in resolving resource disputes.
But IOCs do have a part to play before the exploration and production phase gets
under way – if, indeed, it ever does.
IOCs can offer technical expertise. They can assess the potential resources in a
disputed area and provide the results to the parties that are contending its sovereignty.
With accurate results in hand, the IOCs would then be in a position to push the
commercial case for a resolution of the dispute and possibly even put forward a joint
development plan that is sensitive to the sovereignty claims of each party. Discretion is
critical at this stage, however, and a wise IOC treats the sovereignty issue extremely
carefully when promoting a joint development solution.
IOCs must also learn to work with regional NOCs, rather than compete with them.
As Asia security expert Herberg notes: “The NOCs are here to stay. They are
becoming more capable every day. The IOCs have to find a way to bring their
technology and project management skills to the table and marry them with the needs
of the NOCs, [who] still tend to be weaker with regard to such skills.”
This factor has been grasped by France’s Total, one of the leading international
players in the Asian market. Bertrand Huillard, Total’s vice president for exploration
and production in Myanmar, Thailand, China and Vietnam, told FutureLook that it was
crucial for international players like Total to establish strong ties with NOCs in today’s
energy industry in order to make significant progress.
“I think it is especially important to build strong ties with Chinese state-run oil
companies. Why? Because they are powerful, they are competent and they are in
desperate need of energy, which means they are active everywhere.”
Huillard suggested that establishing strong ties with China’s NOCs was an important
step for an IOC, because it has dual benefits. Not only does it allow the pairing to
compete together for assets abroad, but it also opens the door for IOCs to invest in
China’s lucrative domestic market.
“We try to have some kind of strategic partnership with the Chinese NOCs so [that]
outside of China we can co-operate together, which in turn helps us with our moves to
get inside China.” “This kind of approach is the same for us as it is with other smaller
state-run Asian NOCs like Petronas [in Malaysia], PTTEP [in Thailand] and INPEX [in
Japan]. We seek to create strong ties with them in order to get things done together,”
the Total official said.


“Chinese companies are good at extracting oil and gas, they can do that bit on their
own, but they need companies like Total to come in and help them in areas where they
are lacking technological experience.”
“So they need our expertise to deal with sour gas and to develop deepwater offshore
areas, these kinds of things. But they do not need us for normal development of
conventional oil and gas reserves, only for developments that carry some form of
technological challenge.”
Huillard recognises that IOCs can smooth the way towards joint development of
resources that are located far offshore by bringing deep and ultra-deepwater technology
and expertise to the table.
As intermediaries, IOCs may therefore be able to bring competing nations collectively
around the negotiating table, and make them realise they can work together and reap
the benefits of joint development of resources.

Conclusion
In conclusion, it is clear that the number of overlapping sovereignty claims in the Asia-
Pacific region has grown in recent years as more countries, gripped by a deep sense of
vulnerability about their energy security, seek to tap into resources closer to home to
fuel their economies.
The high level of latent and overt conflict over rights, particularly in the South China
Sea, is evident and is likely to persist.
As the US armed forces’ Pacific commander, Robert Willard, informed Congress in a
testimony given on January 13, 2010, the Chinese navy has increased its patrols in the
South China Sea and has “shown an increased willingness to confront regional nations
on the high seas and within the contested island chains.”
In the long run, China is likely to use a combination of hard and soft power to secure
a dominant position in the South China Sea. We believe that China will be willing to use
low levels of maritime violence to back up its border claims, and that it has the naval
assets to do so. The phrase “speak softly and carry a big stick” will probably apply.
Being the major power in the region we expect China to carry off most of the prizes,
compromising where it has to by offering joint development projects. We do not see
much in the way of ASEAN assets to face off Chinese maritime power. Australia is
interested, but almost certainly not to the extent of accepting confrontation, and the
US has no real political or physical platform from which to resist Chinese expansion in
this particular area. The Declaration on the Conduct of Parties in the South China Sea
(DOC) that was signed by China and ASEAN in 2003 has not been effective in
mitigating tensions between claimant states. The failure of the DOC to check China’s
rise suggests the South China Sea could become a Chinese fait accompli, though usually
with equity participation from the states whose interests have had to give way.
With regard to the overlapping sovereignty claim between China and Japan, Beijing is
likely to treat Tokyo with more circumspection than ASEAN members, given its status
as a client of the US and a considerable power in its own right. There is, in any case,
less to argue over, and some steps have been made towards doing a deal.


Latin American new horizons: east, west or
home’s best?
Introduction
Latin America has only recently experienced a substantial promotion in the ranks of
global oil reserve holders. Major hydrocarbon discoveries in Brazil’s offshore subsalt
region and Venezuela’s Orinoco Basin mean that a region that was previously seen as in
decline is now front centre stage as a long-term source of maybe 9-12 million barrels
per day of production for perhaps thirty or forty years.
Standing in the way of this future is a regional history of state intervention in
exploration and production, where years of strict government control have led to
inefficiencies and an energy infrastructure that roundly fails to maximise its potential.
Opportunities for future investment within the region’s three largest reserve holders –
Venezuela, Mexico and Brazil – are markedly different over the long term, as the three
countries balance their respective fortunes against the need for private investment, and
apply quite different political paradigms to foreign participation.
All three countries have a long tradition of hydrocarbon production, with commercial
oil industries dating back over a hundred years. While Venezuela and Mexico have been
prolific producers for several decades, Brazil has only recently enjoyed levels of output
similar to those of its regional neighbours.
We propose to look at these three countries in order to make some predictions about
the future of their oil industries in terms of regulation, investment risks and
opportunities, and in terms of openness and attractiveness to the international oil
industry.

Mexico
Mexico has a long history of state control over its oil and gas industry, a state of affairs
many within the country – politicians and voters alike – are loath to change.
Haunted by the aggressive privatisation of state-owned assets in the 1980s, a process
that left much of the electorate disillusioned, politicians now use the people’s aversion
to private ownership to curry favour with voters, especially in respect of Mexico’s
energy “jewel in the crown,” Pemex. Hence Pemex has been denied the ability to seek
private partnerships and has been left to shoulder the cost of developing the country’s
reserves alone.
At the same time the country’s political establishment has used Pemex as a cash cow
to finance the fiscal budget – oil revenues currently account for around 40% of
government expenditure – seriuously undermining Pemex’s ability to invest. This has
led the company to focus on tapping easy-to-access reserves in order to fill state
coffers.


Cantarell was one such source of easy oil. Discovered in 1976, Cantarell was the
mainstay of Pemex production for years. The field’s output peaked in 2004 at around
2.2 mbpd, and with it so too did national production, at 3.4 mbpd. However, since
peaking, production has been declining at an alarming rate, falling to 2.6 mbpd in 2009.
This year that trend has continued unabated, and we are pessimistic about future output
prospects.
In July 2009 alone Mexico’s production slid by 7.8% year-on-year to 2.56 mbpd, while
Cantarell’s output fell by 41.8% during the month to 588,000 bpd. However,
predictions that the field will run dry towards the end of 2010 seem to us too
pessimistic, and we see the field’s output stabilising for a year or so at about 450,000
bpd. A slower decline will then ensue.
In terms of reserves, Pemex has 14 billion barrels of proven oil, but its reserve
replacement ratio (RRR) in 2008 was 72%, far short of the international RRR norm of
100%. In short, Pemex is in trouble.
Mexico City has just cause to be concerned by these figures. The current
administration has also confessed that it expects average production to decline to 2.5
million bpd in 2010, although its forecasts have proved rather too optimistic in the past,
with its 2008 production estimates for 2009 originally put at 2.7 million bpd.

Analysis and FutureLook
Mexico’s problem lies within Pemex. The firm is stretched too thin and is starved of
investable cash, running every aspect of the country’s oil industry without the financial
recourse that private partnerships allow, without modern expertise, and without the
ability to retain and invest the cash it does generate.
The company has relied on the Cantarell field and other easy-to-develop acreages,
such as the Ku-Maloob-Zaap complex, which produced 850,00 bpd in December 2009
but is expected to decline this year, to supply reliable and cheap oil. However, the
majority of this output comes from mature fields and the firm’s prospects of
developing new plays in time to offset losses are bleak to say the least.
Mexico made an attempt in 2008 to reform the oil sector, but the government’s
proposals fell foul of political manoeuvring, being depicted by the opposition as
attempts to privatise the country’s resources. What passed through Congress was a
heavily criticised “reform lite” bill, which continues to prevent private companies from
booking reserves.
Pemex’s harsh reality is that reserves and production are declining, the economy is
suffering its worst recession in decades and 2008’s reform has failed to deliver any
significant results. The government understands this and has announced plans to revisit
the issue of energy reform. Mexican President Felipe Calderon believes that more
market-friendly policies are the only way to turn around the struggling Mexican oil
industry. This industry is not short of places to play. US deepwater Gulf exploration
has been highly successful (BP found the 3bn barrel Tiber field only last year), and both
Pemex and the Mexican government know that deep offshore is where they must go,
but in order for the country to exploit its deepwater reserves effectively it is clear that
political changes will have to be made.


US deepwaters are home to thousands of wells, while Pemex has only managed to
drill 11 holes in water depths of more 500 metres in recent years, none of which are
pumping oil. Mexico has, in essence, already missed a step. Deepwater oil takes years to
bring into production (estimates for Tiber range up to 10 years, and that with world-
class expertise and a fully developed local infrastructure), and even if Pemex did make
discoveries now there would be a painful production and revenue gap for it and its
owners for more than a decade.
President Calderon said in a remarkably frank radio interview recently that Mexico’s
territorial waters in all likelihood held similar reserves but that “we don’t have, whether
or not you want to admit it, the technology or the organisational and operational
capacity to do it by ourselves.” He might have added that Mexico also lacks the finance.
In order to gain that capacity Mexico must, we believe, open its upstream sector to
private investment, and the sooner the better. Once this happens, IOCs will take
interest, but the privatisation implicit in welcoming any commercial partners, whether
they are private or state-owned, will be a bitter and unpopular pill for any Mexican
government to swallow.
There are some more palatable alternatives (for Mexico, at least). At the forefront of
these would be a partnership with Brazil’s Petrobras, which has the technological skills
necessary to exploit potential deepwater reserves. Moreover, the Brazilian state-run
company enjoys a high level of regional recognition and respect that would make it a
more palatable partner, politically speaking, than many others.
From our perspective it is an obvious step for Pemex to look to Petrobras for a leg-up
in deepwater gulf exploration. At present, however, we see no evidence that this logic
has gained much traction in Mexico City (though Pemex has been talking to Petrobras
about this agenda).
Another option would be to seek partnerships with China’s NOCs, possibly seen as a
lesser evil given their state affiliations. China National Petroleum Corp. (CNPC),
Sinopec and China National Offshore Oil Corp. (CNOOC) have consistently sought to
expand their presence in the Americas and enjoy capital reserves to develop deepwater
deposits.
However, this would obviously create tensions with Washington, which would see
such an invitation to Beijing as encroaching upon its interests within the region. As
such, we think it likely that should Mexico encourage a Chinese presence in its
exploration sector then a similar level of participation would be offered to US firms.
A turning point may be the 2012 presidential election. By then it is possible, indeed
likely, that a political consensus will have emerged that private investors must be
admitted to the Mexican oil sector.
If that happens then no deals will be done until 2015, and production will not happen
until 2025. For now Mexico is out of the game.
So, our present FutureLook for Mexico is that, factoring in rising oil demand and
declining output, the country will cease to be an exporter by 2014, and will not return
to the export market for more than a decade.


Brazil
Brazil’s record of state ownership is in a way the inverse of Mexico’s. Having opened
the country’s energy sector to private investment in 1995 Brazil has enjoyed a rise in
production, seeing it roughly double from around 1 million bpd to 2 million bpd.
Progress was crowned by the discovery of the 8 bn barrel Tupi field in Brazil’s subsalt
offshore in 2007 (and subsequent sister discoveries).
Petrobras, meanwhile, has become a global powerhouse – the fourth largest quoted oil
company in the world, with listings in Sao Paulo and New York – even while the
government retains a majority of voting shares. Private participation in Brazil’s oil
sector has been promoted by a stable investment climate and an accommodating
regulatory framework.
However, the discovery of the country’s massive offshore potential led Brasilia to
remove new subsalt blocks from auction. These have been held in reserve until
Congress can approve the government’s new proposals for private sector participation,
and for rearrangement of the ownership of Petrobras.
At the same time Brazilian President Luiz Inacio Lula da Silva has touted Brazil’s new
reserves (currently 14 bn barrels, but maybe rising to as much as 50-150 bn barrels) as
the solution to the country’s endemic poverty, with a stated aim of redistributing the
wealth generated from Brazil’s future oil production throughout the country.
In August 2009, the government finally unveiled its new proposed regulations. While
all original contracts are to be honoured, under the new proposals Brazil will drop its
concession system, with Petrobras assuming sole responsibility for operating the subsalt
region. The state-controlled firm will have a minimum participation of 30% in all new
subsalt blocks and the government will reserve the right to award such areas solely to
Petrobras if it wishes.
The government also plans to recapitalise Petrobras, through a swap of shares for oil
production rights, which will see the company receive 5 billion barrels of subsalt oil.
This should result in the government increasing its minority stake in ordinary stock to
more than 50%.
Finally, a new state-owned oil company, Petro-Sal, will be created to manage the
region’s development.

The move has naturally caused considerable unease among investors, who worry that
Brazil is shifting towards resource nationalism in the wake of such finds as Tupi, Iara,
Guara and Jupiter, and conclude (rightly, we think) that the government is moving
towards a state-controlled deepwater industry.
The physical and financial challenges in developing the subsalt region are immense.
Reserves lie beneath a thick salt layer under several kilometres of rock and water. The
salt layer alone is up to 2 km thick in places and production will be further complicated
by the varying temperature profile found en route to the surface.


The cost of developing the region will be astronomical. Petrobras estimates that
outlays could reach as much as US$400 billion over the next decade, and we have heard
larger figures, up to US$600 billion, mooted.
Yet Petrobras remains undaunted for several reasons. First, the company has
developed a reputation for deepwater drilling expertise and is a leader within the
industry. Secondly, it has managed to complete several multi-billion US dollar financing
agreements with the US and China, whilst also managing to tap the capital markets,
even in these constrained economic times.
For example, in February 2009, China Development Bank (CDB) agreed to lend
Petrobras US$10 billion to develop the subsalt region in return for 200,000 barrels per
day of Brazilian oil. The US’ Export Import Bank, meanwhile, agreed to a US$2 billion
loan in May 2009. Petrobras, it seems, feels confident both about its ability to finance its
deep subsalt reserves and to produce them.
The deal with China comes as part of Beijing’s continued drive to expand its Latin
American energy footprint, whilst offering Brazil the chance to access China’s deep
pockets for deepwater exploration. (China has expressed interest in participating in
deepwater fields once Brasilia’s new subsalt regulations are in place). This would give
Chinese NOCs the opportunity to partner with a world leader in deepwater
development, which would in turn offer invaluable skills to be applied to China’s
deepwater prospects in the South China Sea.
What is more, the recovery in the price of oil has left Petrobras confident of its ability
to meet its future financing load from its own cash flow. With oil prices above US$70
per barrel Petrobras believes it can fund its five-year, US$174.4 billion strategic
investment plan without the need for further external financing. If left to its own
commercial devices our view is that all of this would be true. However, we have a quiet
alarm bell ringing a small warning that Brasilia’s direction is towards a combination of
interference and cash extraction that might fatally undermine Petrobras’ ability to
deliver.
If the Brazilian government treats Petrobras as a cash cow for the budget then
Petrobras will be back to the capital market to borrow the cash that has been extracted.
Petrobras’ past successes would suggest the government understands the need for a
sound business model, in much the same way that Norway has approached the
management of Statoil.
However, the government’s plan to recapitalise the firm is a potential game-changer.
Brasilia intends to acquire a majority of Petrobras’ ordinary stock through the
recapitalisation process and we expected this to change the subtle balance of power
that has existed between state and private shareholders.
The government wants to develop the subsalt deposits quickly, but in ways that are
beneficial to the state. It has a fine example of “how to do it” in Statoil, but public
servants usually show little understanding of how much of a seemingly profitable
cashflow needs to be reinvested in order to maintain healthy corporate growth.


In 2008, Statoil generated some 230 bn kroner (US$38.6 bn) in gross operating cash
flows, and paid only 27 bn kroner (US$4.5 bn) in dividends. We cannot see Brasilia
living with what would look like such a low rate of extraction of cash from Petrobras,
and we therefore fear that Brasilia may slowly make the same mistakes that have been
made by public sector shareholders elsewhere, and thus slowly undermine Petrobras’
abilities to exploit its subsalt reserves in the long term.
On the brighter side, the new regulatory regime, if approved, will give Petrobras only
a minority interest in new subsalt exploration, so Petrobras’ problems with its new
owners may not much affect its commercial partners.

Venezuela
Venezuela’s exact level of oil production is something of a mystery. While government
figures put output at around 3 million bpd, down from 3.2 million bpd in 2008, the
veracity of these figures has consistently been challenged.
OPEC, of which Venezuela is a founding member, estimates that the country’s
production has dropped from around 2.5 million bpd in 2008 to around 2.3 million bpd
in 2009, after the cartel reached a consensus late in 2008 to cut production to support
weak oil prices. The International Energy Agency (IEA), meanwhile, puts Venezuelan
crude production at around 2.2 million bpd.
What seems certain is that Venezuela is producing materially less than it claims. The
source of this fall dates back to a 2002-03 national oil strike, which led to PDVSA
being nationalised and a host of the firm’s managers, engineers and skilled workers
being fired. The company has struggled to recover in the aftermath and production has
no doubt suffered as a result.
PDVSA was not the only company affected. During his time in office Venezuelan
President Hugo Chavez has championed a programme of resource nationalism,
harming Venezuela’s oil and gas sector as foreign investors have pared back investment
while the threat of nationalisation looms.
But now Venezuela is back in the search for partners, having held its first international
tender in a decade for heavy oil projects in the Carabobo area of the Orinoco Basin.
The US Geological Survey (USGS) recently gave a mean estimate of 513bn barrels of
“technically recoverable” extra heavy oil in the Orinoco Basin.
If this figure proves accurate then the South American country will surpass Saudi
Arabia as having the world’s largest oil reserves, though these will be far from being the
world’s most attractive, owing to their tar-like makeup and mercurial owners.
After three delays, the Carabobo auction went ahead at the end of January. While it
attracted bids from two consortia, companies such as Statoil and France’s Total
refrained from participating.
This was owing to several factors, including the global economic downturn, the risks
associated with investing in Venezuela, the government’s intractability over certain
contractual demands made by IOCs and the high royalty rates being demanded by
Caracas.

However, while IOCs may hesitate over investing in the country, Chavez has in the
past found alternative partners in China and Russia . It is this ability to find alternative
streams of capital that will prompt IOCs to join the fray rather than be left out of one
of the world’s last great oil plays.

Chavez’s self-styled socialist revolution appears secure and the populist leader’s hard-
line approach to IOCs will continue.
Popular with his electorate, in February 2009 Chavez won a referendum to remove
presidential term limits, allowing him to run for office indefinitely. Chavez’s populist
social programmes, which engender heated debate as to their value, have created a
strong base of support amongst the country’s poor, and this is reinforced by aggressive
behaviour on the part of the red-shirted “Chavistas,” who have been accused of
political intimidation and attacks. Opponents have found themselves forced to seek
asylum in neighbouring states for fear of persecution by the government and its
proxies. Moreover, Chavez has clamped down on his critics within the media,
rescinding the broadcasting licences of those television and radio stations most vocal in
their criticism of his administration. Short of his own mortality, we do not see Chavez
losing power in the next five years.
But Chavez’s ability to deliver his popular brand of socialism relies almost entirely on
oil revenues – oil accounts for more than 90% of export revenues and most of
government expenditure. The government’s coffers were hit by the collapse in oil prices
towards the end of 2008, but with a return to the mid-US$70s Chavez will be able to
continue funding his chosen programmes, at least for now.
Furthermore, the argument that Chavez’s nationalisation drives have reduced the oil
sector’s ability to find much needed investment has been undermined by Russian and
Chinese state-led firms’ commitment to investing billions of US dollars in the Orinoco
Basin. In September 2009, Russian and Chinese companies agreed to invest a total of
US$36 billion in the region, with the objective of boosting heavy oil production by
900,000 bpd. Caracas’ efforts are part of its strategy to diversify its US-orientated oil
sector, while doing deals with the two countries most calculated to irritate the US’
geopolitical nerves.
Russian interest appears to be mostly motivated by geopolitical considerations in
relation to Caribbean Basin military basing facilities and relationships. Russia intends to
raise its Latin American profile after more than a decade of retrenchment following the
fall of the Soviet Union. Moscow has also been seen courting Cuba and Bolivia, who
share Venezuela’s anti-US ideologies. China’s interest, as a major importer, is more
conventional and economic, and no more welcome to the US.
Nevertheless, both deals serve as a warning to IOCs that the country will have little
trouble in tying up multi-billion US dollar investment agreements with its political allies.
The message to IOCs is clear – accept the terms and the risks or see the deals go
elsewhere; a message many will take onboard.
As Chavez secures and reinforces his autocracy over Venezuela, and as the country’s
proven oil reserves grow to global levels of significance, then so too will state control
of the oil sector.

Nevertheless, while private investment looks risky at best, it seems unlikely that IOCs
will – or can afford to – bypass the opportunity that Venezuela represents. We believe
that they will swallow the pill and invest, even if through gritted teeth.

Conclusion
Public servants are not good at producing oil efficiently, with a couple of notable
exceptions. Venezuela and Brazil, with increasing reserve bases, will seek a greater
degree of state control over their oil sectors.
While Brazil will present a more stable investment climate with lower political risk, it
is also moving towards more state interference. Venezuela, in contrast, presents a
greater political risk but less geological risk.
Both countries will suffer from the effects of state interference, but as we have seen
elsewhere the negatives will take years or decades to make themselves truly felt.
Mexico, in contrast, will eventually undergo a significant liberalisation of its energy
sector, under pressure from the cold reality that reserves and production are in the
doldrums, the state desperately needs the revenue, and that the state-run monopoly is in
no position to provide a solution.
The exact pace of such change remains unpredictable, though we think it will have
become effective within five years from now.
There will be opportunities in the next five years for IOCs in all three countries, with
varying blends of political, geophysical and engineering risks.
The questions, unanswered, are whether Brazil’s government will remain on the
sidelines for long enough for IOCs to recover what will be eye-wateringly large
investments, whether Venezuela’s will be able to resist the much more immediate
temptation to interfere and confiscate, and whether Mexico will actually get around to
opening up its deepwaters to IOCs in the next five years.
Our FutureLooks are respectively “probably, just”, “probably not” and “quite likely”.
Sadly, for major IOCs, the option to do nothing and wait is probably not on the table,
as Chinese and Russian partners will readily fill the gaps if the IOCs are absent.


The production prediction predicament and
Regional Decline Theory™
Introduction
A “holy grail” of the energy business is the ability to predict oil production in the
medium and long term. A miscellany of factors is at work, and as the economist Paul
Ormerod demonstrated in his work “Why Most Things Fail: And How To Avoid It”,
when too many uncertainties intervene prediction becomes impossible. In oil the
number of variables is legion – many thousands of fields, millions of wells, thousands
of companies, a hundred governments, technology, geology, interest rates, the supply
of credit, changing demand among 6 billion people, and so on. Surely the problem is
intractable?
A common reaction to the data overload is to step way back from the picture and
simply note that reserves have been found at a faster rate than they have been produced
for the entire history of the oil business, that production techniques have consistently
improved, that the industry has always found the cash to develop reserves, and that
overall production has steadily increased at a comforting 1-2% per year every year since
even the oldest among us were born, so why worry? Surely this happy combination of
circumstances will carry on?
Enthusiasts for data reject such a “Macro-iste” dismissal of the problem, and instead
dive into as much data as they can find, tracking fields and wells, discoveries, shut-ins,
companies, states and investment flows in the search for the ultimately reliable answer.
Such a search is satisfying, as each piece of data found seems to reduce the risk of
being wrong, but ultimately no amount of “Micro-iste” data can predict what will
happen next year, or next decade, or in thirty years.
As both approaches seem to us unsatisfactory we have sought a middle way, in an
attempt to bring some clarity to our vision of the future, while remaining firmly
grounded in reality. Seek, and ye shall find, they say, and we have indeed found an
approach which seems both simple and analytically powerful. This article sets out the
method and its findings. We have christened this tool with the rather catchy name
“Regional Decline Theory™”. This is its first public airing, and we look forward to
hearing what you think of it.

Regional Decline Theory™
Lesson 1.01 for Oil Newbies is that a single field is discovered, comes into production,
is developed and worked (quickly) up to a natural peak, and then declines steadily at a
compound rate of about 5% per year until its production cash margin falls below its
operating costs, at which point it is plugged and abandoned. In time scales, the
development phase (for a large field) is about three years, the climb phase is another
two or three years, and the decline may run for 30 or 40 years (shorter for smaller
offshore fields with high operating costs, and longer for large onshore fields with low
costs).


As a slight variation on this gentle rise and fall, modern production techniques mean
that a field will enjoy a plateau between its climb and its descent, as technology and
cash allow in-fill production to replace declining production from the older wells. These
days the plateau (which need not be flat – it may undulate up and down a little) lasts for
perhaps ten years.
Microistes seek to track every field and every well and apply a unique decline curve to
each of these in order to try and predict production in detail. We believe that there is
simply too much detail and too much medium-term uncertainty to make this tactic
either viable or, indeed, useful.
However, the approach becomes valid again if, instead of looking at individual fields
and wells, we apply it to whole Regions.
The life cycle of a producing region is an analogue of the life cycle of an individual
field, but with slightly different numbers. A region is discovered. Because the
infrastructure is thin, and the risk high, initial work is focused on the largest targets,
which are also statistically the most likely to be found early. The region enters
production based on its large fields, and this output quickly climbs the curve as such
sizeable discoveries are developed.
Proof that a region is prospective reduces the risk for new drilling, and the
appearance of relevant infrastructure decreases the cost of both further exploration
and development, so new smaller fields are sought and discovered, and in due course
enter production. The time scales applicable (three to four years) mean that the new
fields come onstream as the lead fields reach their plateau phase. So, the flow of
hydrocarbons from the region as a whole continues to rise, with output from the new
fields lying on top of the plateau output of the lead fields.
This process repeats – as the infrastructure grows and geological knowledge of the
region deepens, new (and smaller) fields are discovered, developed and brought online,
and each generation of discoveries adds a new “climb” phase to production, while the
lead fields are plateauing.
After a time, roughly 10 years from production start, the lead fields begin to drop off at
the predictable and normal 5% per year rate. For a while the tail end of the “small
discovery” process fills the gap, so the region’s output as a whole remains plateaued, even
though its lead giants are in decline. However, after a few more years (about five, in fact)
the new small finds are no longer large enough to replace all of the falling-off that older
fields are beginning to experience, and the region as a whole goes into decline.
What is interesting, of course, and key to this paper, is that the process of infill
discovery, supported by enhanced production techniques and ever better seismic
acquisition and analysis, keeps topping up the region’s output from younger and new
fields while the main body of fields is in decline.
If this is a correct analysis of how a region behaves then we would expect to see that
regions as a whole plateau for longer and then decline at a slower rate than the
individual fields within them. We could speculate that if the natural plateau for a field is
seven years, and that the decline rate is 5% per year, then a region should plateau for
twice as long, and then decline at maybe half the rate – say 2.5% per year.


Armed with this theory we went in search of some data to see if it corroborated the
assumption. Here is what we found:

Note: The author is indebted to Ed Reed for sourcing much of the data in the table above and
elsewhere in this paper, and for challenging the logic of RDT and thereby improving it.

To summarise the table, with some caveats it looks as if our Regional Decline
Theory™ works. While individual fields are declining at 5%, regions decline at half that
rate, once they have passed their peaks.
The variation in the rates we found is also revealing. In regions governed by benign,
honest, business-friendly governments and run by commercial or semi-commercial
concerns Regional Decline Rates average 1.9%, while in regions run by less business-
friendly regimes Regional Decline Rates average 3.6%. We will save some blushes by
not revealing here which group we think each country belongs to, but as ever we have
grounded our division in brutal reality.
Incidentally, we accept readily that the USA is not one region but arguably seven, or
even eight, but for simplicity, and for lack of data, may we be forgiven for taking it as
one for the sake of this paper? We have left out Russia, partly because it is in fact also
several regions, and partly because it has been so affected by non-geological factors that
its production record will tell us little useful about Regional Decline Rates.
We hope that we might at this stage also be forgiven for becoming rather excited. If
Regional Decline Theory™ is valid then we have discovered an extraordinarily simple
and powerful tool for forecasting world oil production in the short, medium and long
term.


All we have to do is divide the oil-producing regions of the world into “declining
regions” (the list in the table above), “plateauing regions”, “climbing regions” and “new
regions”, correctly place each region in the time-line, predict a peak for those regions
which have not yet peaked, and predict an entry date for those regions not yet in
production.
Once that task is done we should have a highly robust model that will give us a view
on oil production for some 40 years ahead (we could also add in an assessment of
“competent vs incompetent” regions, or instead we could take the average of 2.7%
across the board).
The beauty of this approach is that it only gives us about 60 data points to worry
about, and 40 time periods, and allows us to make clear and simple predictions about
step-changes, for example when Brazil Subsalt will come onstream, and at what rate.
As you would expect, as soon as we got this far we dived into a spreadsheet and did
exactly that. We shall spare you the data blizzard (though we are happy to share it with
you in another forum if you are interested) but to take some of the highlights, we
assumed that Iraq would increase production to 5 mbpd in 2010 (the Iraq paper in this
FutureLook has a view on that subject), that Brazil Subsalt would come onstream in
2013 with about 1 mbpd, that India would see step changes upwards of 1 mbpd by
2015, Sudan of 1 mbpd in 2011, Angola to 3.5 mbpd in 2012, and so on. The full list
of assumptions would probably drive you to a coffee break, so we will spare you them
at this stage.
And here is the news. Setting aside tar and shale developments (which don’t belong in
Regional Decline Theory™ anyway), no matter how much we tweak the RDT model
and feed it with successes as yet unknown, we have found it pretty much impossible to
get it to yield a world oil production level much above 90 mbpd.
Whatever we feed in as “brand new world” discoveries, like Arctic oil coming
onstream in say 2020 (which seems pretty wildly optimistic to us), Regional Decline
keeps undercutting production and bringing it back to nudging 90 mbpd, with a
nervous downward ticking noise. Note that we have taken a sober view of Saudi
potential production as topping out at 9 mpbd. If the Saudis can go above that then we
simply add the extra production to the peak.
So, if Regional Decline Theory™ is valid, and if we have correctly characterised the
different regions, then it does look to us, at least, as if production flows are going to
top out well south of 100 mbpd (in about seven years, if you’re interested).
We are sure that this paper will generate a fair degree of comment among our readers,
and welcome that comment, as one of our mottos (which your editors grow ever more
tired of hearing me repeat) is “It’s not Who’s right that matters, but What’s right”. We
look forward to your thoughts.


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