Archive for the ‘africa’ Category

Petroleum Subsidy and The Global Economy: The Nigerian Paradigm

Energy prices, to a great extent influence the global economy. For members of  the Organization of the Petroleum Exporting Countries, OPEC, the higher the prices of crude oil necessary for balancing their budgets, the greater their need to keep the commodity’s prices even higher. Subsidies as well as expenditure items — such as the “Arab Spring” palliatives — add to budgetary breakeven prices. According to reports, countries such as Saudi Arabia (US$80/bbl), Nigeria (US$70/bbl), Iraq (US$100/bbl) and Russia (US$110/bbl) all require certain crude oil price levels to meet budgetary provisions. In Nigeria, the recent unrest arising from gasoline subsidy removal, stirred global crude oil markets and caused a crash in the European 10 ppm gasoline market.  But that country’s subsidy regimes have also raised critical issues of sustainability.

Goldman Sachs includes Nigeria in its Next-11 group of countries which could potentially impact the global economy. The country’s outlook was recently upgraded to positive from stable by Standard and Poor’s Ratings Services. A member of OPEC, Nigeria is Africa’s largest crude oil producer and fifth-largest supplier to the United States. However, due to an abysmally low, refining capacity utilization, it currently imports between 80% and 90% of its petroleum product requirement. Import costs (product, freight, value additions, handling etc) and a rather nebulous pricing formula have led to much higher retail prices than if products were locally refined.

Consumption subsidy regimes aimed at mitigating the retail price burden have been in place for decades. The sudden removal, on the first day of the year, then saw gasoline prices spike from about US$0.41 per liter to about US$0.90 per liter. Ranked the world’s 133rd in terms of income per capita by the International Monetary Fund, 63% of its people live on less than £1 (about US$1.5) per day according to the Department for International Development (DFID).

These subsidies have over the past few years become unrealistically high. Figure 1 for example, shows that between January and September 2011, a staggering 30.1% of total budgetary provisions was expended in subsidizing petroleum product prices alone. This substantially exceeds the combined provisions for education, health, housing and defence in the 2012 budget. According to the central bank governor, in 2011 a total of US$16.2 billion — approximately half the country’s foreign exchange reserves — was spent in foreign exchange sales to petroleum product importers and in subsidizing petroleum product prices. During a recent town hall meeting to discuss petroleum subsidies, the governor also revealed that ship-loads of refined product were often diverted to neighboring countries for sale at higher prices by “importers” who would also pocket subsidy payments from the government for the same diverted cargoes.

Figure 2 illustrates an even more staggering point: in 2011, more money was spent subsidizing petroleum products than was budgeted for capital expenditure. With rising public debt and declining foreign reserves, meaningful development becomes such a monumental task. In addition, recurrent-to-capital expenditure ratios (about 3:1) are often skewed by the bloated bureaucracy and its outsized emoluments.

 According to Punch, a Nigerian national daily, each serving Senator of the Federal Republic of Nigeria takes home about US$1.3 million annually — more than three times the salary of the U.S. president — while each serving member of the Federal House of Representatives takes home about US$840,000. There are also issues of corruption. For example, accounts of a US$16 billion power sector reform project reveal that for all that amount, not a single power plant was built; nor was the said amount accounted for. Worse still, the report of a hearing on the project by the legislature was shamelessly buried in a political cesspool.

 The government correctly argues that excising financial waste would enable the provision of infrastructure necessary for attainment of its Vision 20:2020 goals. It promised palliatives to cushion the impact of product subsidy withdrawal. But if the citizenry has been leery, it may be because previous promises proved futile.

The subsidy withdrawal drama has played out across successive administrations but three issues of denouement are noteworthy:

1. Phased Withdrawal

There is a limit to the “corrective shock” an economy can sustain without compounding problems. If Nigeria’s productivity for example, is adversely impacted by a one-step (immediate and total) subsidy removal, then the country could be burdened with more problems than it initially set out to address. In addition, a government severely challenged by the increasingly daring terror of the Boko Haram sect can ill-afford further conflicts let alone with trade unions and civil society groups.

Beyond withdrawal of subsidies, internal controls which encumber efficient product supply also need to be eradicated and provisions made among the most vulnerable for amelioration of withdrawal effects. Strictly adhered to, a phased withdrawal of subsidies along with structured milestones, would not only make for impact and conflict mitigation, but also lead to better product delivery.

2. Refining Capacity

The lack of adequate domestic refining capacity is a major driver for the high petroleum product prices. To spur investment in domestic refining, part of the withdrawn subsidy may be deployed in the R&M subsector as initial guarantees for refining margins. This would be a shift of subsidy from consumption to production. Such guarantees were successfully applied to the country’s upstream subsector a few years ago when low, global crude oil price regimes discouraged capital expenditure. The Refining and Marketing (R&M) subsector creates by far the most jobs in the oil and gas value chain.

Nigeria has a total installed crude oil refining capacity of 445,000 barrels per day; but at less than 30%, its aggregate refining capacity utilization over the past decade is abysmally low. (See Figure 3 below). 

The country plans to increase that installed refining capacity by 300,000 barrels per day within three years, possibly making it a net exporter of refined products. However, a country that can hardly utilize a third of its 445,000 barrels-per-day installed refining capacity would surely be incapable of utilizing any proportion of an additional capacity. Adequate investment in the country’s R&M subsector will remain elusive unless issues of product pricing, corruption, security as well as adequate supply of refining feedstock are addressed. Of the 18 refining licences issued more than 7 years ago, none has so much as received a final investment decision.

3. Restructuring

Finally, the country’s oil and gas sector is in dire need of total restructuring. Transactions in the sector have been largely opaque. Issues of corruption and the environment (oil spills as well as gas flaring) go begging. Accounting records of the country’s state-controlled oil company (which largely oversees oil and gas activities) are rarely, if ever published and the colossal failure of its refining processes is symptomatic of the sector’s ills. The requisite matériel, personnel and will to carry out effective regulation are clearly absent; subjects of regulation are even relied upon for logistics and critical evaluations.

The Petroleum Industry Bill (PIB) which was supposed to provide an operational framework for that restructuring has been mothballed in the legislature, amid accusations and counteraccusations of bribery; and investment funds have sought more favorable climes.

All said, while the subsidy regimes are clearly unsustainable, the withdrawal process could have been more skillfully handled. There was a perception of insensitivity to it and the palliative measures seemed more of a patronizing afterthought than part of any well-planned process. If the planning and palliatives horse had been placed before the subsidy withdrawal cart, a much greater proportion of civil society groups would probably have been onboard.


Oil and Gas Trends: Decoupling of Refining and Marketing Assets

The transport sector currently accounts for a dominant proportion of the global crude oil consumption with refining throughputs spiking during peak driving seasons. As penetration rates for electric and hybrid vehicles are still at modest levels, that dominance is set to endure for some time to come, albeit in decreasing proportions.

Oil and gas companies have recently seen challenges in the downstream Refining and Marketing (R&M) subsector; but these challenges are different for developed and developing countries.

OECD Countries

Total OECD petroleum consumption peaked at about the year 2005 and has been declining since. Figure 1 shows that while OECD consumption increased by about 20% between 1990 and its inflexion year of 2005, that for non-OECD increased by more than 60% from 1990 through 2010.

Weak motor fuel demand and the consequent decline in refining throughputs (Figure 2) have combined with costly regulatory requirements particularly in the United States to bring about poor refining returns. In the United States for example, figures recently released by the Energy Information Administration show that for the week ended September 23 2011, gasoline demand was 419,000 barrels per day (bpd) less than year-ago levels while the four-week average for gasoline demand was 2.4 million bpd less than the corresponding 2010 period. According to the released figures, both Gulf Coast and Atlantic Coast refinery runs saw declines.

Unforeseen circumstances earlier this year also added to poor refining throughputs. For example, European refineries, which take about 80% of Libya’s light sweet crude production, saw significant decline in runs when unrest knocked off that country’s output. In addition, the Sendai earthquake in Japan still keeps about 500,000 bpd of refining capacity offline.

Faced with increasing difficulty to reserves replacement, resource nationalism as well as the aforementioned challenges, many Integrated Oil Companies (IOCs) embarked on various restructuring processes aimed at improving their profitability.

For ConocoPhillips, — which, among the oil majors had the highest share price gains year-on-year for 2010 — assets divestment was the principal restructuring tool. It was therefore no surprise that downstream R&M assets formed a significant proportion of that divestment. The oil major recently broke up into two companies with R&M operations comprising one of them. It is also in the process of selling off refining assets such as the 185,000 barrel-per-day refinery in Trainer, Pa. in the United States. Total and Shell among others have also been involved in R&M divestment.

It would however be incorrect to assume that R&M operations are loss-making ventures (Figure 3). Falling demand for refining products has meant that the most efficient refiners are the most viable. Niche-focused independent oil and gas companies have proved much more efficient in their respective niches than unwieldy IOCs. For example, independent Exploration and Production (E&P) as well as R&M companies recorded overwhelmingly higher share price gains year-on-year in 2010 than IOCs. The potential alliance between resource-rich National Oil Companies (NOCs) and these niche-focused independents may well add to the viability concerns of IOCs.

An upside to the break-up of integrated companies into smaller independents is that the sum of the market valuation of the smaller units has in many cases exceeded that of the original company. This may lend credence to the position that niche-focused companies boast higher operational efficiencies.


Non-OECD Countries

For developing economies, where demand is largely subsidy-driven, the challenges are somewhat different. Countries such as Saudi Arabia, India, Pakistan, Venezuela, Iran, China and Nigeria among many others have emplaced various forms of petroleum product subsidies. While such subsidy regimes provide for caps in domestic product prices, they often do not allow for adequate refining margins and have on massive scales, entrenched corrupt financial practices as well as natural resources wastage. With such operational climate, many IOCs have either spurned R&M investments or spun them off completely.

In India, due to the large subsidy burden, the government has mandated a series of increases — albeit gradual — in the prices for refined petroleum products.

In Saudi Arabia where crude oil is used for much of its domestic power generation, subsidies often bring electricity prices as unsustainably low as US$0.015 to US$0.04 per kilowatt. The country’s oil consumption increased by 75% over the last 10 years and is set to top an estimated 5.6% increase this year, against the estimated global average of about 1.4%. The head of  Saudi Aramco had earlier this year, warned that by the year 2028, more than 8 million barrels of oil equivalent per day would be internally consumed if the trend is sustained; and that would impose severe restrictions on export proportions, probably impacting global supply.

Nigeria is often considered emblematic of the oil resource curse. In Nigeria, gasoline prices have been fixed for the past few years at about US$0.42 per liter across the country, irrespective of international crude oil prices or transportation costs. A refining company in that country would therefore face very bleak profitability prospects if it were required to purchase crude oil feedstock at the highly volatile international prices. Of the 18 refining licences issued more than 7 years ago, none has received a final investment decision; and that, in a country which imports most of its refined product consumption. 

For most of those licences, there were no proper provisions for supply of feedstock or evacuation and distribution of product. Security issues as well as poor regulatory regimes compounded the case.  

As Nigeria’s oil and gas production is now predominantly offshore, floating refining operations would stand the country in much better stead. They would provide proximity and ease of access to feedstock as well as better security against sabotage or terror threats.

The issue of caps on some product prices would still have to be addressed. A one-step (total) revocation of subsidies would probably throw up much greater and unsavory challenges for leadership and country. However, since the R&M or downstream sector creates far more jobs than the upstream counterpart, part of current product subsidies may be used initially to guarantee refining margins as a first step in the total subsidy revocation exercise. That would spur investment and with positive, multi-sector  knock-on effects.

Such guarantees are not novel. Capital expenditure (Capex) is critical for sustained oil and gas production. When global crude oil prices were at capex-crippling lows, the Nigerian government entered into contracts which guaranteed investors a certain margin on each barrel of oil produced. Even with the contracts’ inherent flaws, the result was that while global upstream activities were at a lull, operators in Nigeria paved the way for the subsequent, timely increases in the country’s oil and gas reserves.

For Nigeria, the burden of petroleum product subsidy is already unbearable. According to the country’s Petroleum Product Pricing Regulatory Agency, PPPRA, about US$13 billion was expended to subsidize refined petroleum products between January 2006 and June 2010. In comparison, about US$6.4 billion was provided for capital expenditure in the country’s 2011 budget.

One single element of data in Nigeria’s refining statistics, tells all the story:  over the past ten years, the country’s refineries have averaged an abysmal aggregate capacity utilization of less than 30%. The values are 10.90% and 21.53% for 2009 and 2010 respectively according to the Nigerian National Petroleum Corporation, NNPC. There has been either a lack of adequate feedstock supply, or a lack of technical maintenance. Without provisions for adequate refining margins and supply of feedstock, the country would be hard-pressed to find worthy investors for that subsector.

As seen in Figure 2, non-OECD refining throughputs have been on the increase (30% between 2000 and 2010), driven principally by the Asia-Pacific region where economic growth over the next few years is expected to be strong. Singapore refining margins are also expected to see significant upticks through the next few quarters.


Rising Crude Oil Prices: Good Time to Buy Oil Stocks?

The current wave of unrest blowing across the Middle East , North Africa (MENA) region and the associated uptick in crude oil prices have raised concerns about another (and possibly sustained) global crude oil price shock — the region currently holds about 60% and 45% of global crude oil and natural gas reserves respectively and accounted for about 45% of global oil exports in 2009.  Current estimates of potential peak oil prices for the year range from US$130 per barrel to US$300 per barrel; recent investment considerations have therefore dwelt on the merits (or otherwise) of buying oil stocks at such times. Three points are noteworthy:

1. Oil Prices and Corporate Earnings

This may sound counterintuitive but rising crude oil prices do not always translate to higher corporate earnings for oil and gas operators and oversupply does not always bring about falling prices. In 2009 for example, crude oil prices doubled between early Q1 and end Q4 but major oil and gas companies recorded steep decline in earnings (for some, as much as 70%); this doubling of prices was in spite of massive, global crude oil inventories —  even floating and other storages were fully oil-laden.

According to a recent report by the energy research firm Evaluate Energy, the six largest IOCs by market capitalization to wit, BP, Chevron, ConocoPhillips, ExxonMobil, Royal Dutch Shell and Total, have, in spite of massive capital expenditure “failed to materially expand either their production or their proved reserve base over the past decade”; acquisitions alone accounted for 28% of their ten-year reserves replacement. The implication then, if these conditions persist, is that rising discovery costs per barrel of oil — which would probably become even steeper given the increasing geological complexities of available acreages — may test the profitability of these companies in due course, even in spite of rising oil prices.

2. Policies of State – royalties and windfall profits taxes

Among major petroleum exporting countries, the steep royalty and tax rates on oil proceeds have been more than an emperor’s ransom to the operating IOCs. In addition to reserves constraints, these have brought them under comparative disadvantages with their state-controlled counterparts, National Oil Companies or NOCs, especially those that have re-organized and have become partially-listed (see Figure 1 below for example).

That said, for some of these countries, these rates are tenured — and therefore stable even if unpalatable — and that significantly reduces investors’ worries about uncertainty. In Nigeria, Africa’s largest crude oil producer, IOCs have decried an “asphyxiating” government take on oil proceeds and some have even threatened to quit the country altogether. The country’s enabling Petroleum Industry Bill however, has been languishing, trophied in the legislature’s dust even as accusations of bribery have been rife.

Surprising and destabilizing however, was the announcement last week by the British Chancellor of the Exchequer in his new budget reading, of a substantial tax hike for oil companies operating in the North Sea; surprising, not just because it was unforeseen, but also because it was made by a Conservative (and presumably more business-friendly) government. The announcement saw dips in the shares of some mid-cap companies. While many companies are currently re-evaluating their North Sea operations, some mature field operators have warned that the hike would amount to an effective tax rate of as much as 81%, possibly a death knell. The government’s response was that higher oil prices would still make them profitable. A windfall profits tax by any other name…?

While there may be strident opposition to high taxes in some political quarters of the United States, one can never discount the degree of shrewd bargaining in those political back rooms. For example, though they may not want to admit it publicly, some oil and gas operators would not mind a little hike in tax if that would mean less restrictive regulatory regimes (such as much faster and more flexible permitting for drilling and exploitation) than are currently in place.

Oil and gas majors  such as Royal Dutch Shell and BP have been divesting North Sea assets for some time but this tax hike may dilute the value of both divested and retained assets, making such assets unattractive and even reconfiguring planned capital expenditure by reducing estimated divestment proceeds. Financial Times reports that companies with the biggest exposure in North Sea include BG Group, Premier Oil and Enquest.

NOCs in comparison, when operating in their domestic acreages are not subject to such asphyxiating operational regimes as IOCs and some have put such advantage to good use. Brazil’s Petrobras for example, has made what is arguably one of the largest ultra deepwater oil discoveries in recent times. Its market capitalization, grew by a 27% compound annual rate between 1999 and 2010 according to PFC Energy, the energy research group and its public offering in 2010 returned a record US$70 billion; also, Columbia’s Ecopetrol which had impressive 2010 results has attracted the investment attention of billionaire investor Carlos Slim.

3. Alternatives

When rising crude oil prices are sustained, investment windows inevitably open for alternative energy or oil sources such as oil sands. Early investors in Canada’s oil sands for example were on better footing than much later ones which had to grapple with spiraling project costs requiring crude oil prices of between US85 per barrel and US$95 per barrel for breakeven. Many of the latter projects were subsequently suspended after oil prices plummeted. Following project reconfigurations however, this breakeven point is now estimated at between US$60 per barrel and US$70 per barrel; and with current crude oil prices at about US$30 above the top of that  range, there is a seemingly comfortable operational window.

Cenovus, Enbridge and Total SA have all signed exploitation agreements with Canada’s First Nations to scale the second oil sands operational hurdle; now, just environmental considerations remain, which in the light of Japan’s recent nuclear reactor problems, may seem middling. Suncor and Husky Energy also have joint venture projects coming on-stream.

According to IHS Cera, three quarters of the projects which were previously set to bring about 2 million barrels of oil per day on-stream have already been restarted. Some may even start coming on-stream by next year.

The impact of technological breakthrough on resource production can be enormous. Hydraulic fracturing and horizontal drilling for example were crucial to the shale gas explosion in the United States and which explosion may be replicated in parts of Europe and Africa. While research into production of renewable petroleum fuels (such as diesel, gasoline and jet fuel among others) from bacteria is not new, a recent process — for which patents are being filed — celebrated a further step towards its actualization. Such a breakthrough if commercialized, could dramatically alter not just the global energy mix, but also the fortunes and even the very structure of oil companies involved in mostly conventional plays.

All said, while buying oil stocks in times of rising oil prices may not be ill-advised, it makes a difference however, what type of oil stocks one buys.


Japan’s Earthquake, MENA Unrest and the Global Energy Market

Japan which imported about 80% of its primary energy requirement in 2008, is the world’s largest importer of both coal and liquefied natural gas (LNG) as well as the third-largest net importer of crude oil. The shallow-focus earthquake (which registered 9.0 on the Moment Magnitude Scale) off the country’s coast last week, generated three-meter high tsunami waves, rendering about 25% of the country’s nuclear power generating capacity offline. Market response ranged from initial stock-selling frenzies through re-evaluation of the nuclear power option but oil and gas supply-demand re-balancing, even if on a regional basis is also expected. While long-term outcomes may be currently unclear, certain trends are indicated:

Oil and Gas

Japan has an interesting energy mix: about 30% of its power needs are met by nuclear capacity, but it also has gas-fired, coal-fired as well as oil-fired power generating installations and is only one of a few countries with the oil-fired variety. With a significant proportion of its nuclear as well as some gas-fired installations offline, it is expected that fuel oil and crude oil will be in greater demand for the short- to medium-term. Increase in LNG demand is also anticipated. Outages at three of the country’s major refineries would mean that an immediate drop in crude oil demand for refining throughput would be offset by an uptick in its demand for power generation. Preliminary estimates of the increase in demand range from 200,000 barrels per day (bpd) to 340,000 bpd, which figures are not likely to strain global supply. According to the Center for Global Energy Studies, CGES, Japan’s dependence on oil as a primary energy source has decreased from 78% in 1973 to its current value of 43%. The country has seen increasing productivity with relatively less use of energy. Figure 1 below for example shows that while Japan’s GDP grew by about 15% between 1999 and 2007, its Energy Use per unit of GDP decreased by about 12%.

The challenge however may be in securing adequate grade fuel oil, specifically, Low Sulfur Fuel Oil (LSFO) which is more suited to its boiler configurations; and prices have already seen anticipatory upticks. Heavy, low-sulfur crude oil grades may therefore be in higher demand.

In 2009, almost 80% of Japan’s 4.4 Mbpd crude oil consumption came from the Middle East while about two thirds of its LNG came from Asian suppliers in 2010. Some European LNG cargoes are set to be diverted to Japan and this has seen higher European LNG prices. Middle East crude oil supplies however, remain a source of global concern especially with regard to the Saudi spare production capacity. The recent arrival of Saudi troops in Bahrain along with brutal crackdown on dissent, ostensibly to protect state installations raised the stakes in the current MENA unrest; for example there are media reports that Saudi Arabia’s main export crude oil facilities may come under intense terrorist retaliatory attacks, a situation — depending of course, on the magnitude — that is certain to put severe, sustained upward pressures on global crude oil prices if not outright shocks.

One of the consequences of the current Libyan unrest has been the disruption of crude oil supplies to Europe. The onset of the Libyan unrest which coincided with a six-year low in European crude oil inventories for that period, exerted upward pressures on the European benchmark Brent. Libya’s light, sweet (low sulfur) crude oil grade is better suited to European refining preferences than the heavy, sour grades produced in many other parts of the world. There are reports which are still unconfirmed, that the exploding civil war in Libya has caused substantial damage to oil and gas installations there. If confirmed, Libya’s production could see protracted outage, further straining the global spare production capacity.

Crude oil grades such as Nigeria’s Bonny Light and Forcados Light among others from the prolific Atlantic petroleum provinces of Africa are expected to bridge that supply gap. Contrary to some media reports however, Nigeria’s crude oil production and not Libya’s, is the largest in Africa. Algeria and Angola also produce more oil than Libya (See Figure 2 below).

Angola, which became a member country of the oil group Organization of the Petroleum Exporting Countries, OPEC, in 2007 has since ramped up its production above Libya’s.

The year 2011 is an election year in Nigeria with increased threats of sabotage attacks on the country’s main oil and gas production facilities in the Niger Delta region; these had led to force majeure declarations on oil cargo deliveries in previous years. There is already a report of explosions at a flow-station operated by a major Integrated International Oil Company, IOC. Production outages in the Niger Delta have correlated with spikes in global crude oil prices; with the Libyan production outage, supply disruptions in the Niger Delta could further tighten Europe’s light crude supply, putting even stronger upward pressures on prices.

Nuclear Energy Swap

A cloud of nuclear uncertainty is gradually swirling around the globe, in the wake of Japan’s nuclear mishaps. In Germany for example, a moratorium on nuclear energy has been quickly emplaced, while many European nations have called for a radical re-evaluation of the nuclear power option. China however, with the highest number (27) of nuclear plants under construction, has vowed to press on, even if with an evaluative pause. Stocks in some major nuclear energy companies such as Areva were down in intra-day trading on Thursday. But if the truth must be told, Japanese nuclear power installations in the main, withstood the Sendai quake. The associated tsunami was the major culprit, knocking off auxiliary generators used for pumping reactor cooling fluids, in the absence of which radiation would spread. In addition, the magnitude of a given earthquake is not the sole determinant of the degree of structural damage; it is possible for lower magnitude quakes to produce higher peak ground acceleration (necessary for structural damage) than higher magnitude quakes. According to records for example, Chile’s 2010 was a magnitude 8.8 and had a peak ground acceleration of 0.78g; the Christchurch (New Zealand) quake earlier this year on the other hand, had a magnitude of just 6.3 but a peak ground acceleration of 2.2g.

Following these global concerns about the safety of nuclear power installations, global demand for natural gas as alternative power generation fuel would likely increase as would pressures for an end to oil-indexation of natural gas prices. This could be added incentive for mega gas projects such as Chevron’s Gorgon works in Australia. Royal Dutch Shell also has significant liquefied gas capability. Japan which holds extensive methane hydrate reserves in its exclusive but undisputed offshore zones may then need to commence exploitation. Strident objections (which cite energy independence issues) to the export-licensing of the increasing U.S natural gas production, would in the short- to medium-term likely see no substantial increase in prices there.

The events may give fillip to renewable energy roles in the global energy mix, as calls grow for more environment-friendly energy.  Renewable energy companies also stand to benefit from some energy re-balancing. For example, due to plant outages in Japan, Asian demand for PVC has turned to the United States where export prices are expected to increase substantially.

Japanese Reconstruction

Japan is not new to reconstruction. The aftermath of Kobe’s massive 1995 earthquake (then listed as “the costliest natural disaster to befall any one country”) is testimony to that. But the current reconstruction efforts may hold added problems. For example, if there is substantial pollution from radiation — and authorities are seemingly at their wits’ end as to management of the nuclear risk — not only would costs escalate steeply, but swathes of the productive eastern part of the country could be shut in for some time. This may translate to lower productivity as well as lower energy demand. Some companies such as General Motors in the U.S. have according to media reports, announced temporary production delays due to unavailability of automotive parts from Japan.

In terms of funding, a massive influx of insurance payouts is expected; in addition, there is reportedly an estimated US$2trln in external holdings which may be repatriated. This pullout could potentially impact some countries. The rapidly-strengthening yen, which recently reached a post world war II high against the U.S. dollar however, may be a disincentive to domestic manufacturers; though the G7 countries have just announced intervention plans, the nature of that planned intervention is still unclear.


Global Crude Oil Prices: The Lingering Uncertainty

There is clearly the possibility of a global crude oil price shock arising from the current unrest in the MENA (Middle East, North Africa) region — and the impact on a sluggishly rebounding global economy could be devastating. The precise outcome of events may be currently unclear but crude oil price projections have been wide-ranging.  For example, while some analysts expect a gradual retreat of crude oil prices for 2011 to an average of US$95 per barrel after the recent peaks, others see a peak of US$300 and an average price of US$200 per barrel for the year. World Oil reports that a company recently slashed odds on a US$200 per barrel crude oil to just 3/1.

Global markets in their aversion to uncertainties have been restive even in spite of ameliorative efforts; and perhaps rightfully so:

Spare Production Capacity

Marginal crude oil supply, crucial to moderation of global crude oil prices, is widely considered to reside with the petroleum grouping, Organization of the Petroleum Exporting Countries, OPEC. OPEC had just prior to the MENA unrest put its spare production capacity at about 5 million barrels per day (Mbpd) though independent estimates had it at between 3 and 4 Mbpd. A report by Financial Times however, indicates that Saudi Arabia’s recently-announced production increase of 700,000 barrels per day may have actually commenced prior to the MENA unrest; and that OPEC, with its rather poor record of quota compliance, may have been producing above its official production figures by as much as 1 Mbpd. The implication then, is that OPEC spare production capacity is  up to 1 Mbpd less than estimated. When this figure is added to the Libyan production outage, the effective spare production capacity may become ominously challenged in the event of further production outages.

Spare production capacity as an absolute number may not always convey a desired level of confidence in the markets. For example, a spare production capacity of say 2 Mbpd in a 100 Mbpd global consumption scenario may carry higher levels of supply concerns than for the same 2 Mbpd spare production capacity when the consumption is only 10 Mbpd. A spare production capacity ratio (See Chart 1 below) is often used as a more realistic measure of supply reliability. The year 2008 is often remembered for that much-reviled oil price shock, but OPEC’s spare production capacity with regard to total global consumption was actually lower in 2005 than in 2008. Such is often cited in arguments absolving crude oil market fundamentals of any significant role in the 2008 crude oil price shock.

The substantial regional variation in crude oil demand currently in place, has further beclouded the issue of spare production capacity. Saudi Arabia recently introduced significant price differentials on its Asian and North American crude oil supplies and price differentials on Nigeria’s Bonny Light have ticked upwards.

The Tunisia Syndrome — still unresolved

In terms of global reserves, the MENA region holds about 60% for crude oil  and about 45% for natural gas; in addition, the region accounted for 45% of global crude oil exports in 2009. The wave of events in Tunisia which led to a swift overthrow of that country’s sit-tight ruler, have blown into countries such as Egypt and Libya, previously-deemed quite “safe” or “tightly-ruled” to be affected; it has now crossed seas and deserts morphing into a tense and still-awaited “Day of Rage” in Saudi Arabia. The concern is not so much about who controls the oil, for whoever does would most likely sustain production and even the Libyan revolutionaries have vowed to honor contracts; but it is more about appreciable damage to oil and gas installations perhaps in the heat of conflict. There have been media reports about some damage to Libyan installations in Ras Lanuf and the port of Sidra but due to restricted access, the extent of damage has not been ascertained. Any substantial damage, especially in a country such as Saudi Arabia would cause production outages far beyond the scope of remediation by any available spare capacity, and that, for the months or years which may be necessary for reconstruction or rehabilitation. Now, that would most likely result in an oil price shock, possibly the “mother of all”.


Current concerns about potential supply shortfalls are driving stakeholders to strategic product storage. In the year 2009, when very weak global demand wreaked havoc on markets, total crude oil volume in floating storages alone reached an estimated 125 million barrels; other estimates were even significantly higher. Some oil storage tank operators are currently reporting rapidly exhausting capacities while others are racing to bring new ones on-stream. According to Business and Economy Digest, the Netherlands-based Vopak for example, reports that its 48 storage tanks in Fujairah on the east coast of the United Arab Emirates are fully engaged while additional capacities expected to come on-stream by year’s end have also been completely leased out.

Finally, the effect of spiraling crude oil prices would probably be different for developed and developing economies. Among the developed economies, the impact would be more severe for the energy-intensive ones such as the United States. Gasoline prices in some states of that country have already reached $4 per gallon.

Member countries of the Organization for Economic Co-operation and Development (OECD) as a group have over the past few years seen marked reduction in energy use per unit of GDP. Chart 2 below shows GDP and energy use values for OECD countries between 1980 and 2009. While GDP for the group doubled between 1980 and 2007 for example, its energy use per unit of GDP reduced by a third for the same period. At such rates, the impact of an energy price increase on productivity for the group would be relatively less.

Emerging economies, while more energy-intensive, have also seen reduced energy use ratios as more efficient industries come on-stream. Energy subsidies as well as price controls would also provide cushion for any short- or medium-term impact, even if inflation worries are kindled. Energy subsidies are politically and socially explosive issues in these economies and are unlikely to be eradicated anytime soon. Among many emerging economies, the last recession was not as deep as in the developed economies and recovery was faster.

An oil price shock however, particularly one that endures, would be quite devastating to just about all economies, but more so where recovery is still inchoate.

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