Successfully reported this slideshow.
We use your LinkedIn profile and activity data to personalize ads and to show you more relevant ads. You can change your ad preferences anytime.

Future Look I


Published on

A forward looking energy report written by NewsBase predicting enrgy issues 5-10 years into the future

Published in: Business, Economy & Finance
  • Be the first to comment

  • Be the first to like this

Future Look I

  1. 1. FutureLook I March 2010
  2. 2. 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-
  3. 3. 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. Copyright © 2010 NewsBase Ltd -3-
  4. 4. 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. Copyright © 2010 NewsBase Ltd -4-
  5. 5. 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. Copyright © 2010 NewsBase Ltd -5-
  6. 6. 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. Copyright © 2010 NewsBase Ltd -6-
  7. 7. 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. Copyright © 2010 NewsBase Ltd -7-
  8. 8. 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. Copyright © 2010 NewsBase Ltd -8-
  9. 9. 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. Copyright © 2010 NewsBase Ltd -9-
  10. 10. 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 -
  11. 11. 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. Copyright © 2010 NewsBase Ltd - 11 -
  12. 12. 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. Copyright © 2010 NewsBase Ltd - 12 -
  13. 13. 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. Copyright © 2010 NewsBase Ltd - 13 -
  14. 14. 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. Copyright © 2010 NewsBase Ltd - 14 -
  15. 15. 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. Copyright © 2010 NewsBase Ltd - 15 -
  16. 16. 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. Copyright © 2010 NewsBase Ltd - 16 -
  17. 17. 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.” Copyright © 2010 NewsBase Ltd - 17 -
  18. 18. “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. Copyright © 2010 NewsBase Ltd - 18 -
  19. 19. 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. Copyright © 2010 NewsBase Ltd - 19 -
  20. 20. 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.” Copyright © 2010 NewsBase Ltd - 20 -
  21. 21. 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. Copyright © 2010 NewsBase Ltd - 21 -
  22. 22. 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. Copyright © 2010 NewsBase Ltd - 22 -
  23. 23. “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. Copyright © 2010 NewsBase Ltd - 23 -
  24. 24. 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. Copyright © 2010 NewsBase Ltd - 24 -
  25. 25. 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. Copyright © 2010 NewsBase Ltd - 25 -
  26. 26. 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. Copyright © 2010 NewsBase Ltd - 26 -
  27. 27. 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. Analysis and FutureLook 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. Copyright © 2010 NewsBase Ltd - 27 -
  28. 28. 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. Copyright © 2010 NewsBase Ltd - 28 -
  29. 29. 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. Copyright © 2010 NewsBase Ltd - 29 -
  30. 30. 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. Analysis and FutureLook 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. Copyright © 2010 NewsBase Ltd - 30 -
  31. 31. 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. Copyright © 2010 NewsBase Ltd - 31 -
  32. 32. 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). Copyright © 2010 NewsBase Ltd - 32 -
  33. 33. 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. Copyright © 2010 NewsBase Ltd - 33 -
  34. 34. 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. Copyright © 2010 NewsBase Ltd - 34 -
  35. 35. 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. Copyright © 2010 NewsBase Ltd - 35 -