Crude oil, albeit in decreasing proportions, will likely remain significant in the global energy utilization mix for the next few years. The impact of the commodity’s price on the global economy is therefore palpable. The issue of peak oil is resurgent and there are current concerns — even if somewhat mitigated — about an oil price shock.
Speculations were also rife in 2009 — amid the global economic decline — about an imminent crude oil price shock. The argument then was that the extant, low-price regimes constituted a disincentive to upstream capital expenditure (capex) and that when the global economy began to rebound, oil demand growth would vastly outstrip supply capacity. The International Energy Agency, IEA, even boldly projected a price shock by the year 2012, to wit this year.
Four points then are noteworthy:
First, current crude oil prices though high, do not derive from such fundamental imbalance. In a 2009 post, Oil Price Shocks and Market Fundamentals, l argued that even if there were an oil price shock in 2012, it would most likely hold no fundamental support. The IEA reports that oil stocks rose by about 1.2 million barrels per day, bpd, through 1Q 2012 even as supply by Organization of the Petroleum Exporting Countries, OPEC, went ahead of demand. Oil consumption by member-countries of the Organization for Economic Cooperation and Development, OECD, has been declining since 2005 (Figure 1) and growth is projected to remain largely flat through 2030.
In the United States, the world’s top oil consumer, Department of Energy data show that crude oil stocks have been on an upward trend and for the week of 13 April 2012 stood at a 35-week high, while consumption has been declining. Even in China, a major driver-country for global oil demand, Financial Times reports that consumption for December rose by only about 1% year-on-year, compared with the year-ago level of about 10%. The country’s demand growth for diesel for example has slowed and is projected to remain weak through 2Q as its construction, transportation and manufacturing industries pull back a bit. In addition, recent increases in official diesel prices have not helped demand. The Center for Global Energy Studies, CGES, has reported an increase in the country’s February 2012 oil imports to 5.9 million bpd, from 5.3 million bpd for year-ago levels; however such increase may well reflect a strategic inventory build-up in the light of declining supply from troubled and sanctions-buffeted Iran.
Both the United States and Russia have accounted for a significant proportion of the non-OPEC oil production. Between 2008 and 2011, U.S. total domestic oil production rose by about 19% to about 10.1 million bpd according to data from the country’s Department of Energy. CGES reports show aggregate Russian production at about 160,000 bpd above year-ago levels; the country which has become the world’s largest producer has been upping production levels.
Fiscal Breakeven Levels
Driven largely by higher oil prices, oil-exporting countries in both the Middle East and North Africa (MENA) as well Sub-Saharan Africa regions are projected by the International Monetary Fund (IMF) to grow by 4.8% and 7.3% respectively in 2012. These countries accounted for nearly 60% of global oil exports in 2010. However, such growth has meant increased fiscal expenditure, requiring even higher crude oil prices for fiscal breakeven (Figure 2). Some of these countries for example put out billions of dollars as palliatives during the wave of regional unrest that led to the ouster of leaders such as Muammar Gaddafi of Libya.
High fiscal breakeven prices make major exporters reluctant to boost supply save for a spike in demand. While acknowledging the deleterious effects of, and the necessity for ameliorating very high oil prices, many of these exporters have also emplaced sliding tax scales which provide for higher effective rates at higher oil prices, a plausible disincentive for lowering of prices. However, oil production companies operating in such countries do not seem to do very badly: when oil prices are high, such companies often declare substantial profits even with high tax rates or reduced output. When opprobrium has been raised over oil price volatility, many of these countries have therefore received a significant share.
Spare production Capacity
The issue of spare production capacity has been of greater concern. Saudi Arabia is believed to hold about two-thirds of global, spare oil production capacity and its oil minister has boasted of the country’s capacity to pump an extra 2.5 million bpd into the market within four or so weeks. Over the past few years however, growth rate for global oil production has been largely flat even as many analysts still question that Saudi claim especially in the event of any major supply disruption such as in the Strait of Hormuz; and with Saudi Arabia’s projected rise in domestic oil consumption as well as a reported pull back on the country’s plans for capacity expansion, such sentiments will likely sustain oil price volatility.
Analysts hold different views on the impact of the U.S. quantitative easing on dollar-denominated assets such as crude oil; or the effect of speculative trading on crude oil prices. However, it can be safely said that weaker dollar values can translate to higher oil prices and large market influx of speculative investment can drive up prices. For example, during the oil price shock of 2008, oil prices were spiraling higher even when the market was well-supplied, an argument OPEC adduced in laying the blame for the shock on weak dollar values, rising inflation and a massive influx of speculative investment into the commodities market.
According to Bloomberg Businessweek, speculative trading helped lift crude oil prices 30% in the last six months. It adds:
The amount of speculative money in the oil market hit a record high in mid-March, when money managers held a net long exposure to oil through 642,724 futures contracts. At 1,000 barrels per contract, that’s roughly equivalent to 643 million barrels of oil — more than the entire world uses in a week
Concerns about a major supply disruption — due for example to an armed Israel-Iran conflict or even a unilateral Iranian action in the Strait of Hormuz — may have added to unease in the oil market. Today it is Iran but tomorrow it could be Bahrain or Nigeria or even more nightmarishly, Saudi Arabia. The recent-weeks spikes in premiums for front-month gasoline contracts may well reflect that sentiment; and in the light of current geo-political or other considerations, such sentiments are unlikely to disappear any time soon.
The European sovereign debt and currency crises as well as a very sluggish global economy led many analysts last year to project lower crude oil prices for the year 2012. However, in a seemingly counter-intuitive measure, oil and gas companies substantially increased capital expenditure (capex) provisions for the year (See Figure 1 below).
With increasing geopolitical tensions — especially in the critical Middle East region — and concerns over a precarious global economy, investment prospects in the oil and gas sector have come under greater scrutiny. Three issues then, are noteworthy:
Oil Price levels
High oil prices most often conduce to higher returns for operating companies (and good news for investors). Even when these companies have recorded production declines (as has sometimes been the case with some of the majors), high oil prices have boosted profits.
Oil prices have been on the increase. The price for the global benchmark, Brent for example, has risen by about 15% since the beginning of the year, and just a few days ago reached its highest level since 2008. The increases have been in spite of weak global demand. According to the International Energy Agency (IEA) for example, 4Q 2011 demand fell by 530,000 and 690,000 barrels per day (bbl/d) year-on-year for North America and Europe respectively, in a net global (albeit slight) decline. In the United States, total petroleum product demand measured on a four-week-average basis fell by 6.7% to 18.054 million bbl/d year-on-year the week ending 17 February 2012, the Energy Information Administration (EIA) reports. That value was the lowest since April 1997.
Gasoline prices show fairly high correlation with crude oil prices. In the U.S. for example, even with falling gasoline demand, pump prices have been on the increase (See Figure 2) and will probably remain high for as long as global crude oil supply issues remain. Crude oil prices are internationally set; and so except for an improbable price enforcement by the U.S. government over domestic producers, the idea that increased U.S. domestic oil production will lead to lower domestic petroleum product prices is misplaced.
Global oil prices are unlikely to fall substantially for some time to come even with demand growth among OECD countries projected to be largely flat through 2030. Of course there would be the usual spikes and dips but issues such as a potential Israel-Iran flash point, capex delays in the MENA region (which according to the IEA would account for 90% of the world’s marginal production increase through 2035) as well as countervailing demand growth among emerging markets (particularly the Asia-Pacific Region, see Figure 3 below) would most probably sustain prices. In addition, production among non-members of the Organization of the Petroleum Exporting Countries, OPEC, has often fallen short of forecasts, Iran’s output has been severely curtailed by sanctions, Japan is ramping up imports to replace offline nuclear power capacity and OPEC’s spare production capacity looks set to be critically tested.
Mergers and Acquisitions
When share prices are depressed in equally depressed, cost-of-money regimes, windows inevitably open up for Mergers and Acquisitions (M&A). Last year, Canada’s “unconventionals” for example — relentlessly buffeted by environmental groups and weighed down by low valuations even when largely profitable — looked particularly amenable. Another round of acquisitions since gas-seeking U.S. players took advantage of low Canadian dollar rates about a decade ago, loomed large. Bigger operators such as Encana and Talisman have large natural gas (and oil, in the case of Talisman) assets as well as better financial standing to make them attractive. Mitsubishi Corporation recently acquired a 40% interest in Encana’s Cutbank Ridge Partnership. That however was not a replacement for PetroChina which last year pulled out of a $5.4 billion deal for a 50% interest in Encana’s Montney shale play due to a disagreement on terms.
As the oil and gas majors continue decoupling of Refining and Marketing (R&M) assets, niche-focused independent operators in the U.S. look set to dominate that subsector. These independents have often proved more efficient in their respective niches than the majors. For example, independent Exploration and Production (E&P) as well as R&M companies reported much higher share price gains year-on-year in 2010 than the majors.
Outside North America, deep offshore assets are set to witness a lot of activity, continuing from last year. In Northwest Europe for example, where drilling operations declined 12% in 2011 according to Argus, there were 118 deals as more prone companies sought relief from financial risk.
Natural Gas Production Levels
Technological advances such as hydraulic fracturing and horizontal drilling have opened up access to very large volumes of natural gas in the United States and increasingly in other parts of the world. However, the massive supply overhang and the consequent depression of prices have led to consolidation and refocusing in the industry. Smaller, financially prone producers have been taken over by bigger corporations and liquid-rich plays have become more attractive. Producers are also turning to Liquefied Natural Gas (LNG) production; but such is the rate of capacity expansion, that a global glut may develop by the year 2018, just six years on, according to a PennEnergy report; for the U.S. that would mean another wave of depressed natural gas prices and possibly, further restructuring in the industry.
Beyond the medium term however, natural gas prices would probably rebound with increasing demand (especially for power generation) and prospects of supply constraints. The latest estimate of U.S. recoverable shale gas reserves made by the country’s Department of Energy saw a 42% decline over previous-year levels.
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).
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.
The 17th Session of the Conference of Parties (COP 17) to the United Nations Framework Convention on Climate Change (UNFCCC) is currently holding in Durban, South Africa. It aims to agree on a successor to the Kyoto protocol which expires next year. A recent report by the International Energy Agency (IEA) reinforces the urgent need for that agreement. According to the IEA, if the world is to stand a better chance of keeping the rise in global temperature below 2o C — and therefore avoid the deleterious effects of climate change — it must maintain a (universally-accepted) carbon emission ceiling of less than 450 parts per million, ppm; however, many scientists maintain that significantly lower values are more realistic. With the current, global, carbon-emissions trajectory, that ceiling will be breached by 2017, due principally to fossil fuels. Fossil fuels account for more than 70% of global electricity generation and as a result, electricity accounts for about 40% of energy-related carbon dioxide emissions.
A rapid increase in renewable or “clean” energy’s proportion of the global energy mix therefore becomes imperative. Global investment in clean energy has grown at a compound annual rate of 29% since the year 2004, to more than US$1 trillion, Bloomberg New Energy Finance reports.
China which leads the world, spent US$54.4bn in 2010 according to Pew Charitable Trusts. The country, which currently derives more than 92% of its primary energy consumption from fossil fuels, has set a target of 15% share for clean energy in its energy mix by the year 2020; this is almost quadruple ExxonMobil’s projection of a 4% share for renewable energy in the global energy mix by the year 2040. BusinessGreen, in a recent publication, reports that, “The IEA predicts China’s electricity demand will grow by an average of four per cent per year to reach 9,000 terawatt hours (TWh) by 2035, which represents a tripling of its 2009 demand and equates to 18 times that of France.”
Of the world’s largest wind energy and solar energy companies by capacity, three and seven respectively are Chinese. Chinese entry into the sector has bred steep competition, driving down equipment costs. Bolstered by lower equipment costs as well as vast improvements in technological and operational processes, production economics for some subsectors of the renewable energy industry is already at par with coal, nuclear and natural gas in some locations and will most likely attain global parity in the very near future. According to Bloomberg New Energy Finance for example, wind energy produced by the average wind farm will be at price parity with natural gas by the year 2016, just about five years away.
Growth of the renewable energy industry has not come without challenges which in recent times have stemmed principally from the industry’s own success story: a rapid capacity expansion which, with falling demand — due to the global economic decline — has led to a large supply overhang. The case of Solyndra, a recently-bankrupt manufacturer of solar energy components in the United States is typical. The effects can be collateral. For example, some manufacturers of batteries for electric vehicles also became insolvent when demand for particular vehicle lines slipped due to the global economic decline. There are also concerns that First Solar, one of the world’s largest solar companies may be under viability pressures following the earnings downgrade just a few weeks ago.
Some commentators have derided the state subsidies extended to the renewable energy sector; it is noteworthy however, that in 2007 for example, fossil fuel subsidy in the United States was more than three times that for renewable energy, according to the Energy Information Administration (EIA). Even large corporations such as those in the financial and automotive sectors, have been beneficiaries of massive government financial assistance. In addition, complaints about the whirring of wind turbines in residential areas for example, pale in comparison to outcries over incidents such as the infamous Macondo well explosion or the despicable degradation of the Niger Delta environment, all associated with fossil fuels production.
Growth in renewable energy is expected to be driven by government policies especially among the Organization for Economic Cooperation and Development (OECD) countries. In addition, a global economic rebound is expected to see an uptick in numbers of the more efficient electric and hybrid vehicles at the expense of standard gasoline- or diesel-powered ones.
All said, while fossil fuels will most likely remain the dominant form of energy consumed over the next few years, renewables will take increasing proportions of that consumption.
Third quarter earnings reports for the oil and gas majors were somewhat mixed: while profits were up, driven principally by high crude oil prices, production declined significantly. BP for example announced 3Q ’11 profits of US$5.1 billion, while the values for Shell and ExxonMobil were US$7 billion and US$10.3 billion respectively. Production at BP declined by 12% year-on-year (y-o-y) to 3.32 million barrels of oil equivalent per day (boe/d), the highest in more than a decade; even after exclusion of effects such as assets divestment and Production Sharing Contracts (PSCs), the decline was 8%. In the United States, the company’s production decline was an unsavory 25%, due in the main, to the Macondo well incident. Similarly, for ConocoPhillips, the decline was 10%, Chevron 5% and Shell 2%. For some of these companies, output decline was more than could be attributed to divestment. In comparison, net output for Norway’s state-controlled oil company Statoil, grew by 14% y-o-y.
There are three fundamental issues which challenge the very viability of these majors. While these issues are not new, they are accentuated by the latest quarterly earnings reports.
Reserves are fundamental to the viability of any oil and gas company. In the late 1960s, the oil and gas majors held about 85% of global crude oil reserves. At present, an estimated 80% of global crude oil reserves is domiciled with state-controlled companies or National oil Companies (NOCs). Most oil-exporting countries have domiciled their national resources in these NOCs while the majors have to go through costly bidding and acquisition processes for access to acreages.
Figure 1 shows a comparison between the largest NOCs and super majors by proved reserves.
In terms of barrels of oil equivalent, the top three NOCs hold more than ten times as much oil and gas reserves as the top three majors and there are no majors among the top ten rankings. Among the top twenty rankings, there are only three majors, two of which barely figure. In 2010, Saudi Aramco alone produced more crude oil than the four largest super majors put together.
Cost of Production
For many of these majors, access to state-controlled reserves is via Production Sharing Contracts (PSCs) or Service Contracts (SCs). Most PSCs provide for the majors to bear discovery and development costs while proceeds from sales are shared in agreed proportions. Quite often, these proceeds come under very steep royalty and tax regimes that eat deep into the majors’ take. ExxonMobil and BP, in their latest quarterly reports for example, cited the effect on their books, of increased government take from PSCs.
Service Contracts provide for fixed payments — often far less than the producers would like — for each barrel of production above pre-determined baselines. In the West Qurna 1 fields of Iraq for example, ExxonMobil is set to receive US$1.90 per barrel of new production after deduction for costs.
The majors, in their quest to enhance their viability have also been plumbing and scouring for petroleum reserves in increasingly complex geological formations; and with enhanced technologies to match. This conduces inevitably to higher production costs. According to RIGZONE, cost of discovery and development for the majors more than doubled from US$9 per barrel of oil equivalent (boe) during the period 2000 – 2005 to US$19 per boe during 2008 – 2010. In addition, the International Energy Agency reports that these costs are set to increase significantly over the next two decades compared with crude oil prices, further squeezing profit margins.
NOCs have fast been encroaching on an industrial turf previously controlled by the majors. Now independents are setting their stakes on that same turf: over the past few years, niche-focused, independent oil and gas companies have proved more efficient in their respective niches than the majors. The majors which had hitherto leveraged on the industry’s complete value chain, have become quite unwieldy. Independent Exploration and Production (E&P) as well as Refining and Marketing (R&M) companies recorded overwhelmingly higher share price gains year-on-year in 2010 than the majors.
In their bid to bolster profitability, the majors have embarked on a series of assets divestments. BP recently increased its divestment target by 50% to US$45billion by 2013 while for ConocoPhillips the value is US$10billion by the same year. Such divestments however, substantially curtail the production capacities of these majors. For example, BP’s divestments are expected to reduce the company’s production from about 4 million boe/d to between 2.3 and 2.4 million boe/d according to its chief executive officer. Such output decline would also impact profits, as again in the case of BP, where Q3 upstream profits dipped despite higher crude oil prices.
The independents have been some of the beneficiaries of such assets divested by the majors and as such have been enhancing their portfolios. In addition, the potential alliance between these independents and NOCs bears winning synergies at further expense of the majors — technical expertise and efficiency marrying vast oil and gas reserves as well as state funds which carry less stringent terms.
All said, the majors’ viability will depend on their ability to navigate these issues.