Archive for March, 2011
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.
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 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.
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.
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.
Integrated International Oil Companies, IOCs, have over the last decade grappled with increased difficulty to reserves addition and profitability. For some, shareholder returns have been worrisomely skewed towards share buy-backs. In comparison for example, the non-Integrated or Independent Oil Companies have delivered much higher capital growth from smaller base: according to the energy consulting firm PFC Energy, the Independents showed an average value growth of 18% (Year-on-Year) in 2010 compared with just 4% for Big Oil. NOVATEK, the Russian Independent for example had a 94% share price increase in 2010.
While the Independents may be asking questions about Big Oil’s business model, the greater threat has come from their state-controlled counterparts, Integrated National Oil Companies, NOCs. According to PFC Energy rankings, of the ten largest Integrated Oil and Gas Companies by market capitalization at the end of 2010, five were NOCs and two of them among the top three. At the end of 2004, only two NOCs were ranked among the top ten. At Petrobras, Brazil’s NOC, for example, market capitalization grew by a 27% compound annual rate to raise the company from 27th position in 1999 to its current 3rd position in PFC’s rankings. In terms of share price gains, figures for the six largest NOCs outstripped those of the six super majors in each of the last five years, except 2008 (Figure 1 below); in 2006 it was by a multiple of about two and half, in 2007 about five, in 2009 about ten and in 2010 that multiple was about two.
In terms of structure, size and scope, NOCs are steadily transforming into super IOCs of sorts, threatening the positions of major IOCs as we know them today. This rising dominance rests in the main, on three planks:
Petroleum reserves are fundamental to any oil and gas company’s operations and such company’s ability to grow reserves often defines its viability. Among petroleum-rich countries, these reserves have seen increasing domiciliation and quite often through their respective NOCs. At the end of the year 2009 for example, the proved reserves (in terms of barrels of oil equivalent) held by just two NOCs, were more than six times the combined value for the six super majors; in addition, the Saudi Arabian NOC, Saudi Aramco, alone in 2009, produced more oil than ExxonMobil, Royal Dutch Shell and BP combined.
For IOCs, access to these reserves has largely been through Production Sharing Contracts (PSCs) and Service Contracts (SCs). Many PSCs on one hand, require the IOCs to bear exploration and production costs (including those for dry wells); when discoveries are made however, proceeds come under very steep, local royalty and tax regimes. In petroleum-rich Nigeria for example, provisions of the Petroleum Industry Bill currently pending in the country’s legislature, left some IOCs threatening to exit the country’s oil and gas sector, if their demands were not met — that may just be good news to the Chinese NOCs which have been angling to get in. SCs on the other hand, provide for a fixed amount payable to the IOCs for a unit of production; in some Middle East countries that value is a little more than US$1 per barrel of oil while in others oil and gas activity is restricted to petrochemicals.
Capital expenditure (capex) is fundamental to the growth of any company in the oil and gas industry. From their onset, most NOCs had easy access to large national treasuries and for many, expenditure was not subject to any legislative oversight nor was any external accounting scrutiny permitted. In addition, such funds were obtained under much more liberal terms than markets could offer; while this bred a lot of corruption, the comparative advantage over IOCs was enormous.
This comparative advantage persists and constitutes a solid plank on which their rising dominance over IOCs rests. While for some NOCs it is still business as usual, a few have undergone remarkable transformation (as discussed below). The latter have been able to attract more public capital investment to fund their massive expansion projects. According to a study by Evaluate Energy, capital expenditure by NOCs increased by a massive 131% between the years 2005 and 2009, compared to just 59% for the seven largest IOCs. Capex by NOCs was more than twice that of Big oil in 2009 and the study expects this trend to continue. In addition, NOCs raised US$108 billion for capex just between June and November of 2010. In Mergers and Acquisitions (M&A), NOCs have also been dominant; according to Platts, NOCs outspent the majors by US$16 billion in 2010 gaining significant entry into the U.S. and Canada. Such capital outlays have enabled them to make quite extensive inroads to projects that were hitherto dominated by IOCs. For example, during many of the oil-block licensing rounds held around the world (particularly Iraq’s second licensing round), NOCs and even Independents have come out winners.
The challenge for Big oil is that even with their capex, return on investment has in the main, been much lower than for example that for the Independents as well as many NOCs.
3. Management and Technology
On the upside, the increasingly tight fiscal regimes in which IOCs have been forced to operate, has led to the development of advanced management and technological systems to optimize and drive their industry-wide processes. But some NOCs are either in step or arguably one step ahead. Petrobras, for example is in the vanguard of cutting edge ultra deep-water production technologies. The company operates some of the world’s largest oil platforms and has successfully drilled wells much deeper than the ill-fated Macondo well. Statoil, Norway’s state-controlled NOC also holds widely acknowledged deep-water technological expertise.
A few years ago, reference to NOCs often conjured images of oil-drenched institutions presided over by rash, despotic kleptomaniacs. Well, yes there are a few left (and no prizes for correct answers), but while many have realized the need for — and are in the process of — restructuring, some have completely restructured. They have undergone significant reorganizations employing total quality management principles among others. Transparency and accountability have been introduced and political environments tweaked to allow for investor friendliness; and these have made for favorable stock listings. Asian NOCs have held significant share offerings, cashing in on the appeal of Asian stocks. KNOC, South Korea’s NOC, for example has planned significant upgrade and expansion. Ecopetrol, Columbia’s state-controlled NOC, has since undergone reorganization and just announced a 4Q10 net profit increase of 47%, Financial Times has reported; its share price gain (Y-o-Y) for 2010 was 77%, the second-highest among the top 50 energy companies, according to PFC Energy rankings. Petrobras also announced a 38% net profit increase to US$6.4bn for 4Q10. Petrobras’ share offering of about US$70bn in September of 2010 was a record.
Much of the technological advancement by NOCs has been by joint ventures, acquisitions and adaptation. Targets have included companies with unconventional and deep-water production expertise among others. The Chinese NOCs armed with a large financial war chest have been at the fore, and often at a premium. Recently in unconventionals for example, Reuters reports that the almost US$11,000 per acre paid by CNOOC for the Chesapeake’s Eagle Ford acreage was higher than Wall Street’s expectation of US$10,000 per acre. Chinese NOCs have also targeted oil sands players such as Suncor Energy and Cenovus as well as Seadrill, the Norway-listed deep-water operator. The fact that production from some of the Chinese acquisitions is sold and not repatriated, strengthens the argument that technology acquisition, increased global profile and economic returns are the main drivers for their positions.
The potential tie-up between Independents and NOCs portends a lethal body blow for Big Oil. Independents have shown much greater efficiency than Big Oil in both upstream Exploration and Production (E&P) and downstream Refining and Marketing (R&M) subsectors. In addition, the planned acquisition by some NOCs, of deep-water operating companies will hasten their complete transformation into super IOCs.
Finally, one of the more powerful operational tools employed by some NOCs, has been the leverage of state which has enabled them to operate in high-risk areas such as Sudan among others.
For Big Oil then, while these challenges are certainly “life-threatening”, there may be some lifelines available and these shall be discussed in a subsequent post.