The 2011 oil shock More of a threat to the world economy than investors seem to think
THE price of oil has had an unnerving ability to blow up the world economy, and the Middle East has often provided the spark. The Arab oil embargo of 1973, the Iranian revolution in 1978-79 and Saddam Hussein’s invasion of Kuwait in 1990 are all painful reminders of how the region’s combustible mix of geopolitics and geology can wreak havoc. With protests cascading across Arabia, is the world in for another oil shock?
There are good reasons to worry. The Middle East and north Africa produce more than one-third of the world’s oil. Libya’s turmoil shows that a revolution can quickly disrupt oil supply. Even while Muammar Qaddafi hangs on with delusional determination and Western countries debate whether to enforce a no-fly zone (see article), Libya’s oil output has halved, as foreign workers flee and the country fragments. The spread of unrest across the region threatens wider disruption.
The markets’ reaction has been surprisingly modest. The price of Brent crude jumped 15% as Libya’s violence flared up, reaching $120 a barrel on February 24th. But the promise of more production from Saudi Arabia pushed the price down again. It was $116 on March 2nd—20% higher than the beginning of the year, but well below the peaks of 2008. Most economists are sanguine: global growth might slow by a few tenths of a percentage point, they reckon, but not enough to jeopardise the rich world’s recovery.
That glosses over two big risks. First, a serious supply disruption, or even the fear of it, could send the oil price soaring (see article). Second, dearer oil could fuel inflation—and that might prompt a monetary clampdown that throttles the recovery. A lot will depend on the skill of central bankers.
Of stocks, Saudis and stability
So far, the shocks to supply have been tiny. Libya’s turmoil has reduced global oil output by a mere 1%. In 1973 the figure was around 7.5%. Today’s oil market also has plenty of buffers. Governments have stockpiles, which they didn’t in 1973. Commercial oil stocks are more ample than they were when prices peaked in 2008. Saudi Arabia, the central bank of the oil market, technically has enough spare capacity to replace Libya, Algeria and a clutch of other small producers. And the Saudis have made clear that they are willing to pump.
Yet more disruption cannot be ruled out. The oil industry is extremely complex: getting the right sort of oil to the right place at the right time is crucial. And then there is Saudi Arabia itself (see article). The kingdom has many of the characteristics that have fuelled unrest elsewhere, including an army of disillusioned youths. Despite spending $36 billion so far buying off dissent, a repressive regime faces demands for reform. A whiff of instability would spread panic in the oil market.
Even without a disruption to supply, prices are under pressure from a second source: the gradual dwindling of spare capacity. With the world economy growing strongly, oil demand is far outpacing increases in readily available supply. So any jitters from the Middle East will accelerate and exaggerate a price rise that was already on the way.
What effect would that have? It is some comfort that the world economy is less vulnerable to damage from higher oil prices than it was in the 1970s. Global output is less oil-intensive. Inflation is lower and wages are much less likely to follow energy-induced price rises, so central banks need not respond as forcefully. But less vulnerable does not mean immune.
Dearer oil still implies a transfer from oil consumers to oil producers, and since the latter tend to save more it spells a drop in global demand. A rule of thumb is that a 10% increase in the price of oil will cut a quarter of a percentage point off global growth. With the world economy currently growing at 4.5%, that suggests the oil price would need to leap, probably above its 2008 peak of almost $150 a barrel, to fell the recovery. But even a smaller increase would sap growth and raise inflation.
Shocked into action
In the United States the Federal Reserve will face a relatively easy choice. America’s economy is needlessly vulnerable, thanks to its addiction to oil (and light taxation of it). Yet inflation is extremely low and the economy has plenty of slack. This gives its central bank the latitude to ignore a sudden jump in the oil price. In Europe, where fuel is taxed more heavily, the immediate effect of dearer oil is smaller. But Europe’s central bankers are already more worried about rising prices: hence the fear that they could take pre-emptive action too far, and push Europe’s still-fragile economies back into recession.
By contrast, the biggest risk in the emerging world is inaction. Dearer oil will stoke inflation, especially through higher food prices—and food still accounts for a large part of people’s spending in countries like China, Brazil and India. True, central banks have been raising interest rates, but they have tended to be tardy. Monetary conditions are still too loose, and inflation expectations have risen.
Unfortunately, too many governments in emerging markets have tried to quell inflation and reduce popular anger by subsidising the prices of both food and fuel. Not only does this dull consumers’ sensitivity to rising prices, it could be expensive for the governments concerned. It will stretch India’s optimistic new budget (see article). But the biggest danger lies in the Middle East itself, where subsidies of food and fuel are omnipresent and where politicians are increasing them to quell unrest. Fuel importers, such as Egypt, face a vicious, bankrupting, spiral of higher oil prices and ever bigger subsidies. The answer is to ditch such subsidies and aim help at the poorest, but no Arab ruler is likely to propose such reforms right now.
At its worst, the danger is circular, with dearer oil and political uncertainty feeding each other. Even if that is avoided, the short-term prospects for the world economy are shakier than many realise. But there could be a silver lining: the rest of the world could at long last deal with its vulnerability to oil and the Middle East. The to-do list is well-known, from investing in the infrastructure for electric vehicles to pricing carbon. The 1970s oil shocks transformed the world economy. Perhaps a 2011 oil shock will do the same—at less cost.
The price of fear A complex chain of cause and effect links the Arab world’s turmoil to the health of the world economy Mar 3rd 2011 | BREGA, LONDON AND WASHINGTON, DC | from the print edition
TWO factors determine the price of a barrel of oil: the fundamental laws of supply and demand, and naked fear. Both are being tested by the violence that is tearing through Libya, the world’s 13th-largest oil exporter. The price of a barrel of Brent crude now hovers around $115. On February 24th, however, it rose to almost $120, as traders realised that they might have to do for a while without some or all of Libya’s exports: some 1.4m barrels a day (b/d), or about 2% of the world’s needs.
The situation in Libya is grim, as the rebels and the forces of Muammar Qaddafi battle for control of the country’s only resource. Brega, the seat of the Sirte Oil Company in the east of the country, has changed hands three times in recent days. Most of the oil workers have fled, and production has fallen by two-thirds. The ports of As Sidra, Brega, Ras Lanuf, Tobruk and Zuetina, which together handle almost 80% of Libya’s oil exports, were all seized by the rebels; two have now been retaken by Colonel Qaddafi’s forces. The rebels remain in control of Africa’s largest oilfield, Sarir, pumping some 400,000 barrels on a normal day. But for how long?
The history of oil is marked by Middle Eastern strife, supply shocks and global recession, with the Arab oil embargo in 1972, the Iranian revolution in 1978 and Saddam Hussein’s invasion of Kuwait in 1990. To gauge the risks today you need to answer three questions. How vulnerable is the oil market to an interruption in supply? How sensitive is the world economy to oil-price spikes? And how well can policymakers cope with a shock if the worst happens? Take each in turn.
The troubles in Libya are only the most serious example of the impact of Arab unrest on global oil markets. Prices jumped as Egypt’s citizens took to the streets to oust President Hosni Mubarak. Egypt is an oil importer, but acts as a vital conduit between the huge oilfields in the Persian Gulf and markets in Europe, via the Suez Canal and through the SUMED pipeline. Although it seemed unlikely that protesters would or could disrupt oil shipments, events in Cairo were enough to add more than $5 to a barrel.
The spread of unrest to Bahrain, Oman and the Gulf has created a whole new dimension of anxiety. North Africa produces 5% of the world’s oil, but the Middle East produces 30%. Moreover, Bahrain’s problems are on Saudi Arabia’s doorstep. These bear on the situation in the eastern Saudi provinces, from which a huge quantity of oil is pumped into global markets.
Saudi Arabia is therefore the traders’ chief worry. But it is also, in oil terms, the world’s chief hope. It is the only producer with significant spare capacity that could quickly be released if the oil price rose too high. Although OPEC, in which Saudi Arabia is the biggest force, exists to keep oil prices buoyant, it does not want to see them reach a point where the world economy is damaged and demand for oil falls. When prices spiked in 2008, the Saudis said they had capacity to spare. Terrified oil markets doubted its existence, and prices rose anyway, to reach $145. Yet the subsequent collapse in the oil price in the second half of 2008 was only partly caused by the credit crisis and the rich-world recession that resulted. Saudi Arabia also pumped extra oil: nearly 2.5m b/d on top of the 8.5m it was already providing.
OPEC’s spare capacity now is put at anything between 6m b/d (by OPEC) and 4m-5m b/d (by industry analysts); Saudi Arabia’s share of that excess is perhaps 3m-3.5m b/d. The oil price has retreated from its peak in the past ten days largely because Saudi Arabia says it is pumping up to 600,000 b/d to replace the shortfall in Libyan exports. It has invested heavily in expanding capacity, with plans to spend perhaps $100 billion on wells and infrastructure by 2015. It has also been far more open about letting the world see what it has done. OPEC’s stated aim of stabilising oil prices relies on traders believing that the Saudis really do have the capacity to pump more when prices rise.
Why, then, are traders still so nervous? The answer is that the long-term trends of supply and demand were already unfavourable when the Arab shoe-throwers intervened. Before the uprisings, a barrel of Brent crude was commanding close to $100 a barrel. World demand grew by an extraordinary 2.7m b/d in 2010, according to the International Energy Agency. It will probably keep growing by another 1.5m b/d this year and the same again next, as the rich world recovers and demand surges in China and the rest of Asia. Net expansion of non-OPEC supplies is likely to be negligible in the coming years. Though the rich world’s inventories are high, with cover of around 50 days, it is not clear that Saudi Arabia can pump much more than it did in 2008; and the speed of oil released from government reserves, such as America’s Strategic Petroleum Reserve, also has upper limits.
If disturbances hit Algeria and threaten its oil industry too, the buffer of spare capacity would fall below where it stood in 2008. But demand now is much higher, so spare capacity as a proportion of that demand is much lower (see chart 1).
When oil markets tighten, another set of problems emerges. Saudi oil is generally more dense and sulphurous than the Libyan crude it will replace. Europe’s creaky old refineries will not be able to process the heavier Saudi crude, and fuel regulations there are less tolerant of sulphur content than elsewhere in the world. So the Gulf oil will have to be shipped to Asia’s newer refineries, which are designed to deal with a wide variety of grades of oil. West African oil, a close substitute for Libya’s output which usually goes to Asia, will be sent to Europe instead.
If the supply situation worsens, opportunities for this type of substitution will be fewer, creating supply bottlenecks, shortages of petrol and spikes within price spikes for different crudes and products, even when spare capacity remains. The price differential of about $15 a barrel that has built up between Brent crude, which more closely reflects global trade, and West Texas Intermediate, the benchmark for oil prices in America, is a good example of how oil markets can become distorted by local patterns of supply and demand. If supply gets even more stretched, oil could fetch a far higher price in some parts of the world than others. If supply problems become really grave, oil companies may even declare force majeure, raising the prospect that, as in 1978, oil markets fail altogether.
That is still a remote prospect, and the upward march of the oil price seems to have paused for now. The crucial question is how much oil will be lost, and for how long. When oil markets operate at the limits of supply, even the smallest extra disruption has a disproportionate effect. On February 26th, for example, Iraq’s biggest refinery shut down after a terrorist attack. This and other assaults could knock out another 500,000 b/d from the world’s fuel supplies. And if the raids on oil installations in previous elections in Nigeria are anything to go by, the next one, in April, may threaten another 1m b/d of supplies from west Africa. Meanwhile, Saudi Arabia remains far from secure (see article). On March 1st the country’s stockmarket, jittery about the neighbours, plunged by 7%, a worrying sign that confidence is fading.
Hobbling the world
All this is a dark cloud on an otherwise bright horizon for the global economy. Few things can short-circuit growth like an oil shock, both because of the fuel’s ubiquity and because of the relative insensitivity of demand. When the oil price jumps, consumers have little choice but to accept it, spending less on something else.
So how sensitive is the world economy to oil prices? Thus far the rise, and the likely damage, both look modest, in part because many forecasters had expected an increase this year anyway. Since the end of last year the price of Brent has risen by $23 a barrel, or about 25%, and West Texas Intermediate by $10, or 10%. The IMF reckons that a 10% increase in the price of crude shaves 0.2%-0.3% off global GDP in one year. As it happens, crude oil (using a blend of several grades), is now about 10% more costly than the IMF assumed in late January, when it projected global growth of 4.4% this year. That implies that the Fund would now foresee growth of about 4.2%.
Economists do not expect a repeat of the 1970s, when oil-price rises led to “stagflation” in the rich world. Olivier Blanchard, chief economist of the IMF, and Jordi Galí, of the Centre de Recerca en Economia Internacional in Barcelona, point out that two recent oil-price rises—one beginning in 1999 and another in 2002—were of the same order of magnitude as during those turbulent years. But the effect on both inflation and unemployment in the rich world was much smaller: in America, for example, a rise in inflation of only 0.7 percentage points on average, whereas the 1970s shocks had caused a rise of 4.5 points in the two years after the shocks.
The rich world is less vulnerable now because it has substantially reduced the amount of oil used per unit of output. America’s economy in 2009 was more than twice as large in real terms as in 1980. Yet over that period America’s oil consumption rose only slightly, from 17.4m b/d to 17.8m. Europe actually used less oil in 2009 than in 1980, even though its economy had grown.
Other factors may also have helped. Supply shocks generate larger increases in inflation and bigger falls in output when wages are rigid. So oil shocks have smaller effects today, because labour markets in rich countries have become considerably more flexible since the 1970s.
Emerging economies may be hit harder by a spike, since they use more oil per unit of output than rich countries do (see chart 2). America’s economy, though about three times the size of China’s, uses just over twice the amount of oil that China’s does. But oil intensity in emerging countries has also been falling in recent years, as manufacturing has become more efficient and less energy-intensive service industries have increased their share of the economy. So even these countries are less vulnerable to an oil shock than they used to be.
Among rich economies America tends to suffer the biggest immediate impact, because its economy is relatively energy-intensive and because its low petrol taxes interpose only a small wedge between crude oil and petrol prices. Goldman Sachs estimates that a 10% price increase trims GDP by 0.2% after one year, and 0.4% after two.
In Europe the effect is muted by lower energy intensity and high levels of tax. Excise and value-added tax represents roughly 60% of petrol prices and 52% of diesel prices in the euro area, according to the European Central Bank (ECB).
Emerging Asia is more complicated. Although its economies are more oil-intensive, several also export oil, and many subsidise fuel, limiting the impact on consumers. Thailand has resolved to hold the price of diesel below 30 baht (about $1) a litre until April; without the subsidy, which was raised on February 24th, it would be 34 baht. Citigroup estimates that each $10 increase in the price of oil costs India’s state-owned oil-marketing companies the equivalent of 0.5% of GDP, of which half is absorbed by the budget. An IMF staff study has estimated that emerging and developing countries subsidised fuel by about $250 billion in 2010.
Loosening, or tightening?
What can central banks do to protect the economy? Higher oil prices act as a tax on countries that import the stuff, which would normally call for easier monetary policy. But they also raise inflation, which calls for tightening. A one-off rise in prices would not produce a sustained increase in inflation, unless it boosts firms’ and workers’ expectations of future inflation, which can become self-fulfilling. The oil-price shocks of the 1970s rapidly found their way into broader inflation. Central banks had to clamp down drastically to suppress their inflationary effects.
In recent years, with inflation expectations more stable, central banks have responded more moderately to higher oil prices. But in July 2008 the ECB raised short-term interest rates because it feared that a rise in headline inflation would feed a wage-price spiral. In retrospect, that was a mistake. The global economy was already slowing, and over the next year both headline and core inflation (which excludes energy) fell sharply in the euro zone. Although America’s Federal Reserve did not tighten, it hinted at the possibility, which prompted markets (wrongly) to anticipate a rate increase. These hawkish signals may have compounded the slide in economic activity already under way.
This year their response is likely to be more subdued. Unemployment is higher in America and Europe than in 2008, and underlying inflation, except in Britain, is lower. At a forum on February 25th at the University of Chicago, officials from both the European and American central banks signalled willingness to hold fire unless inflation expectations grow. On March 1st Ben Bernanke, chairman of the Federal Reserve, said the recent rise in commodity prices would probably “lead to, at most, a temporary and relatively modest increase” in inflation.
In many emerging markets the risks are greater. Those economies are already operating at capacity, and both overall inflation and core inflation have risen: China’s January inflation rate was 4.9%, well above its official 4% target, and India’s was more than 9%. An increase in the price of energy can cause a steeper jump in inflation in emerging markets, because in many it has a larger weighting in their consumers’ baskets: 15.2% in Indonesia, 14.2% in India and 13.8% in Malaysia, compared with about 9% in America’s. Moreover, energy is a large input in food production, which has an even bigger weight.
Monetary policy has also been relatively loose in these countries, with real short-term interest rates negative in many of them, including, by some measures, China. Johanna Chua of Citigroup reckons that monetary conditions, including both interest rates and the exchange rate and, in China’s case, credit growth, have tightened already in Asia, but need to tighten further in both China and India.
The reason for a rise in the oil price is as important as how large it is. An increase forced by higher demand is less dangerous than one driven by constricted supply, because it is evidence of a healthy global economy. If rapid growth means that China and India are importing more oil, they are probably importing larger amounts of other things as well, lessening the pain for slower-growing consumers of oil.
Nonetheless, whether driven by demand or supply, a large enough spike in the price of oil can do great damage. Economists call such abrupt responses “non-linearities” and they suggest that when the price rises fast enough, consumers and businesses trim their spending and investment plans. This is often because prices are driven by other factors that hurt confidence, such as wide unrest in the Middle East. If another Arab government were toppled, pushing the oil price over $150, the economic impact would almost certainly be larger than the 0.5% to 1% of GDP that simple extrapolation suggests.
James Hamilton, of the University of California, San Diego, has identified numerous periods since the late 19th century in America when an abrupt rise in the price of oil or petrol coincided with recession. Many of these were caused not by an interrupted supply, but by demand growth colliding with unresponsive supply. That seems to explain the price spike above $140 in mid-2008. Although the financial crisis was the main cause of the recent recession, Mr Hamilton argues that oil explains why the economy had already begun contracting before the worst of the crisis hit that autumn. Robert McNally, of Rapidan Group, a consultancy, concurs, arguing that American consumer confidence fell sharply once petrol went past $3 a gallon (see chart 3). It is now at $3.38, after the biggest one-week increase since Hurricane Katrina in 2005.
Even if the unrest leaves supply unaffected, significantly higher prices may be only a matter of time. The same dynamic that drove the oil price skyward in 2008 is steadily reasserting itself. Supply is not growing substantially, and global demand, which regained its pre-recession peak last year, is expanding briskly again.
Given enough time, the rich countries should be able to adjust to higher prices. Jim Burkhard of IHS Cera, a consultancy, notes that OECD oil demand peaked in 2005 and has been slipping since in response to the upward march of prices. In America a shift in consumer purchases towards more fuel-efficient vehicles, ethanol mandates and higher fuel-economy standards have all capped growth in petrol demand. Meanwhile, the higher world price has unlocked new supply within the United States, and elsewhere, which was previously too expensive to exploit.
Yet it may take years for such trends to dent demand and boost supply by much; and the world may not have a lot of time. “Historians will look back on 2008 as the first time in modern memory that spare capacity ran out without a war in the Persian Gulf, and OPEC failed to cap prices,” says Mr McNally. “Eventually we’ll replay that scenario. If OPEC can’t control the market any more, that means prices will have to swing much more.”
BP Statistical Review of World Energy June 2011 สามารถดาวน์โหลดได้ผ่านทางเว็ปไซต์ของ BP แล้วนะครับ (www.bp.com) สำหรับปีนี้เป็นปีที่ 60 แล้วครับที่ BP ที่พิมพ์รายงานดังกล่าวออกสู่สาธารณะ สำหรับปี 2010 อัตราการบริโภคพลังงานทั้งโลกเพิ่มขึ้น 5.6% โดยมีก๊าซธรรมชาติและถ่านหินเติบโตมากถึงเกือบ 8% และในปี 2010 ประเทศจีนมีอัตราการบริโภคพลังงานแซงหน้าอเมริกาขึ้นเป็นอันดับหนึ่งของโลกครับ (และนั่นก็เป็นเหตุผลหนึ่งที่การใช้ถ่านหินเพิ่มขึ้นค่อนข้างมากนั่นเองครับ)
ผมตัดเอา Press Release จาก BP ซึ่งสรุปเกี่ยวกับภาพรวมของพลังงานโลกในปี 2010 มาให้อ่านกันครับ
China Overtakes USA as Top Energy Consumer as World Demand Grows Strongly, Says BP in 60th Year of Global Energy
Release date: 08 June 2011
China became the world’s largest energy consumer in 2010 overtaking the USA during a year which saw the rebound in the global economy drive consumption higher and at a rate not seen since the aftermath of the 1973 oil price shocks.
Demand for all forms of energy grew strongly in 2010 and increases in fossil fuel consumption suggest that global carbon dioxide (CO2) emissions from energy use rose at their fastest rate since 1969.
The growth in energy consumption was broad-based, with both mature OECD economies and non-OECD countries growing at above-average rates.
The figures come from today’s publication of the 60th annual BP Statistical Review of World Energy, the longest-running, consistent set of objective, global energy data used by business, academics, and governments to inform policy and decision making.
“There were both structural and cyclical factors at work,” said Bob Dudley, BP Chief Executive. “The cyclical factor is reflected in the fact that industrial production rebounded very sharply as the world recovered from the global downturn. Structurally, the increase reflects the continuing rapid economic growth in the developing world.
“I was in China a couple of weeks ago and I came away with a very clear sense of how rigorously China is thinking about these issues. Growth is by no means the only game in town. They want to maintain social cohesion and they want to make their growth more sustainable. In sum, they are worried about energy security and climate change – just as we are.”
To address these concerns, “we can look to the markets, policy tools, technology advances and not least to the growth of renewable energies to allay these worries,” said Dudley.
“This year, we have seen that the global energy markets are resilient. In the face of significant disruptions to the world’s energy system in Japan and Libya, demand continues to be satisfied. Markets work and markets work best when they are open and transparent.”
Overview
The strong rebound of global energy consumption in 2010 followed the recent global recession. Consumption growth reached 5.6%, the highest rate since 1973. It increased strongly for all forms of energy and in all regions. Total consumption of energy in 2010 easily surpassed the pre-recession peak reached in 2008.
“Economic growth was led by the non-OECD economies which had suffered least during the crisis. By year-end, economic activity for the world as a whole exceeded pre-crisis levels driven by the so-called developing world,” said Christof Rühl, BP’s group chief economist.
Globally, energy consumption grew more rapidly than the economy, meaning that the energy intensity of economic activity increased for a second consecutive year. The data imply that global CO2 emissions from fossil fuel consumption will also have grown strongly last year.
“Energy intensity – the amount of energy used for one unit of GDP – grew at the fastest rate since 1970. And so, when all the accounting is done, planet Earth – we all – consumed more energy in 2010 than ever before,” said Rühl.
Demand in OECD countries grew by 3.5%, the strongest growth rate since 1984, although the level of OECD consumption remains roughly in line with that seen 10 years ago. Non-OECD consumption grew by 7.5% and was 63% above the 2000 level. Consumption growth accelerated in 2010 for all regions, and growth was above average in all regions. Chinese energy consumption grew by 11.2%, and China surpassed the US as the world’s largest energy consumer. Oil remains the world’s leading fuel, at 33.6% of global energy consumption, but it continued to lose market share for the 11th consecutive year.
Global oil consumption grew by 2.7 million barrels per day (Mbpd), or 3.1%, the strongest growth since 2004. Rühl said: “The growth rate was more than twice the ten-year average; it featured the first increase in OECD oil consumption since 2005 and the largest volumetric increase outside the OECD ever. China contributed the largest national increment; its consumption rose by 860,000 bpd or 10.4%. The United States, Russia, and Brazil also recorded large increments.”
The strong recovery in oil consumption was accompanied by strong growth in production though the increase was not as large as the increase in consumption. Growth was broadly split between OPEC and non-OPEC producers. In OPEC, Nigeria and Qatar accounted for the largest increases. Among non-OPEC producers, “China saw the largest increase in the country’s history due to rising offshore output. Russia and the US also contributed significantly, while Norway experienced the world’s largest production decline,” said Rühl.
Oil prices remained in the $70-80 range for much of the year before rising in the fourth quarter. With the OPEC production cuts implemented during the global recession in 2008/09 still in place, and despite informal production increases in the face of the strong recovery in consumption, average oil prices for the year as a whole were the second-highest on record. However due to the high prices, oil saw the weakest consumption growth among fossil fuels last year.
Turning to natural gas, Rühl said: “Consumption rose 7.4%, the strongest volumetric gain on record. Non-OECD economies expanded their share to over 51%; China solidified its role as Asia’s largest gas market. But OECD markets grew rapidly too (6.4%, +93 billion cubic metres), with consumption attaining all-time highs. Production rose 7.3%, also a record increment. 31% of this global growth originated in the former Soviet Union, followed by the Middle East.
“The shale gas revolution in the US and massive changes in LNG markets are reshaping the world of natural gas,” said Rühl. Over the last five years, global LNG supply grew by a cumulative 58% - three times faster than total gas production. And last year, the supply of LNG expanded by an unprecedented 22.6% (55 bcm).
Other fuels
Like all other fuels, coal consumption growth was above average in 2010 - rising by 7.6% (250 million tonnes of oil equivalent, mtoe). The shift toward non-OECD consumption continued, with China and India increasing coal use by 10.1% (157 mtoe) and 10.8% (27 mtoe). OECD coal consumption also rose by 5.2% (54.1 mtoe), the fastest rate for 31 years and hard on the heels of a decline of more than 10% in 2009. Among all the fossil fuels, coal consumption grew the fastest.
For the first time this year the Review includes data on renewables other than hydroelectricity. Biofuels production grew by 13.8%, or about 240,00 bpd, largely in the US and Brazil. Renewables in power generation—including wind, solar, geothermal energy and commercial biomass—grew by 15.5%, with OECD countries accounting for most of the growth though China’s output from renewables grew by 75% and accounted for the second-largest increment after the US. Combined, these sources met 1.8% of the world’s energy needs, a market share which has tripled in the past decade. “Over the last five years, their contribution to world primary energy growth was almost 10% – that is, higher than the contribution of petroleum-based products,” said Rühl.
Hydroelectricity, in absolute terms, saw its biggest increase ever. “2010 was actually the wettest year since 1900,” said Rühl. Nuclear output grew by 2%, weaker than other fuels but still an above-average growth rate.
ผมคิดว่า Natural Gas และ ถ่านหิน น่าติดตามมากครับ โดยเฉพาะ Shale Gas Boom ที่อเมริกา
The world gets back to burning
NOT since 1973 has world energy use increased by as much, in percentage terms, as it did in 2010. According to BP’s annual Statistical Review of World Energy, published today, 2010’s energy consumption was up by 5.6% on the year before. In part this is thanks to recovery from the economic crisis; in part it is down to the longer-term shift in economic activity towards emerging economies, which are less efficient in their energy use.
Robust growth was seen in all regions and in almost all types of energy use: the world consumed more of every main fuel bar one than it had in any previous year. Consumption of oil, which accounts for 34% of the world’s primary energy by BP’s calculations, rose by 3.1%. Coal, at 30% the number two fuel, was up by 7.6%, growing faster than at any time since 2003. Consumption of gas, which contributes 24%, was up by 7.4%, the biggest annual growth since 1984.
The growth in fossil fuels was so strong that although non-fossil-fuel energy also had a record year, its share of the world total primary energy decreased a little. Hydro (6.5%) saw its biggest annual increase on record, in part due to more dams and in part due to a lot of rain; Christof Rühl, BP’s chief economist, notes there was more precipitation in 2010 than in any year in the past century. Other renewables grew impressively too, thanks to countries all round the world continuing to pile on new wind capacity. That said, non-hydro renewables still check in at only 1.3% of global energy consumption—1.8% if you include biofuels.
Of all the fuels, only nuclear had seen better years; 2% growth over 2009 still left it a little below its levels in 2005 and 2006. Ten years ago nuclear and hydro were pretty evenly pegged as energy providers; last year hydro provided 20% more electricity. After the disaster at Fukushima, with its attendant closure of a lot of Japanese and German nuclear capacity, nuclear will undoubtedly fall further behind still.
There are other shifts to note. Oil’s share of primary energy has declined every year over the past decade, while coal’s share of the total has increased by four percentage points since 2000. The main reason for this is China. In 2000, China consumed 11% of the world’s energy; in 2010 it consumed 20.3% of a significantly bigger pie, making it the biggest energy consumer on the planet for the first time in BP’s books (other analyses have made China number one in earlier years; BP doesn’t look at biomass burned in stoves and treats Hong Kong separately, which accounts for the discrepancy).
A burning desire for coal
Most of China’s growth came from burning more coal: in 2000 China accounted for just under a third of world coal use; in 2010 a staggering 48.2%. Repeat that sort of expansion on a smaller scale for a number of other countries and you see why coal is going up in the global mix. You also see why the world’s energy-related carbon-dioxide emissions have grown even faster than its energy use—by 5.8% last year, on BP’s figures. That is the fastest growth since 1969.
The shift in production from developed to emerging economies doesn’t just decrease global energy efficiency; it also increases emissions for any given amount of energy use. The less energy-efficient economies also tend to be the heaviest coal users. Mr Rühl points to the intractability this adds to the problem of emissions; even if emerging economies are reducing their carbon intensity (the amount of carbon emitted per unit of output), global carbon intensity can continue to rise if production shifts to those emerging economies fast enough. Hence record growth in emissions despite modest but real commitments to emissions control in both emerging and developed economies.
This is why there is so much interest at the moment in gas, about which the BP statistics paint an encouraging picture. The copious amounts of shale gas now being produced in America—23% of the country's total gas production, up from 4% in 2005—have led to power utilities switching from coal to gas, which emits considerably less carbon dioxide per unit of output. This has kept emissions lower than they would have been. Indeed the unprecedentedly high spread between the costs of energy in the form of oil and in the form of gas is leading to serious discussion of gas as a transport fuel.
At the same time, in part because now-self-sufficient America doesn’t need it, liquefied natural gas (LNG) is becoming ever more available in the rest of the world. Global supply expanded by 22.6% last year, and has grown 58% over the past five years. That liberalised energy markets allow utilities to buy LNG on the spot market has allowed for competition in the liberalised European market, even through the past two severe winters.
A golden age of gas
And there is no reason to think that the gas boom will come to a stop any time soon. In the week’s other big dollop of energy-geekery, the International Energy Agency released a portion of this year’s World Energy Outlook (the whole thing comes out in November) which lays out a new “golden age of gas” scenario for future energy production and consumption. This sees global gas demand rising by more than 50% over the next 25 years, as gas outstrips coal to come close to equalling oil in the energy mix. Meeting that demand would require an increase in production equivalent to three times the amount of gas produced by Russia today, which the agency imagines being handily met by a mixture of conventional gas and shale gas, as well as some other unconventional forms of the fuel such as coal-bed methane. China becomes both a principal producer (its shale-gas resources are reckoned the largest in the world) and perhaps the largest importer.
But all this does not do anything like as much as you might expect in terms of reducing carbon emissions. This is because cheap gas does not just displace dirty coal, as it has been doing in America; it also displaces expensive renewables and nuclear. In its current scenario, which assumes that countries actually pursue the emission-cutting policies they are now espousing, the IEA sees renewables and nuclear growing substantially until 2035; in the new gas scenario they grow a bit less. And because gas is cheap, overall energy use grows a bit faster. The result is that the all-told reduction in emissions in 2035 is remarkably small: 160m tonnes of carbon dioxide, rather less than the Netherlands emits today.
That more energy is being used than ever before is a welcome sign of economic growth after a sharp downturn. That it is being used less efficiently than before, and producing record levels of carbon dioxide, is harder to welcome. A small mercy, though, is that there are numbers like BP’s available with which to perceive such unwelcome truths. Since the Anglo Iranian Oil Company, which would become BP a few years later, first put together its annual review 60 years ago—six typewritten pages, one graph, for internal use only—they have grown into a widely valued tool for economists and energy strategists in a field where reliable compendia of facts are rare, and growing rarer. In April the United States government announced that it would stop gathering the data on which various domestic energy indicators are based, reduce efforts to assure data quality in some others and cease publication of its International Energy Statistics. It is hard to see how, if such numbers have any value at all, that doesn’t represent a false economy.
ขอบคุณมากๆครับ การที่ PTT ลงทุนทำ port สำหรับขนถ่าย NG อย่างเป็นเรื่องเป็นราว ถ้าใช้ในการนำเข้าเป็นหลัก แสดงว่าบ้านเราผลิต NG ได้ไม่พอใช้จึงต้องนำเข้า ดังนั้นราคา NG ยังไงก็ต้องสูงกว่าปัจจุบันแน่ๆ ไม่ทราบผมเข้าใจถูกต้องหรือไม่ ถ้าถูก ( ขอให้ไม่ถูกเถอะ ) ต้นทุนการผลิตและขนส่ง รวมถึงค่าไฟฟ้า บ้านเราคงต้องมีการปรับขึ้นอย่างเลี่ยงไม่ได้ใช่หรือเปล่าครับ ขอขอบคุณอีกครั้ง
Couldn't agree more krub.
In my personal opinions, given current valuation relative to the big caps' cashflows and growth prospect. Downside risks are very limited.
ไหนๆก็เรื่องน้ำมันและพลังงานทดแทนแล้ว เอาเรื่อง aromatic เข้าไปด้วยก็ดีนะครับ ผลิต paraxylene จากน้ำตาล
Virent announced it has successfully made Paraxylene (PX) from 100% renewable plant sugars. The PX molecule, when combined with existing PET technology, allows manufacturers to offer customers 100% natural, renewable, plant-based PET and packaging. This announcement is the culmination of Virent’s mixed-xylenes development which started in 2010. “Today confirms a significant achievement for global leaders in consumer products,” said Virent CEO, Lee Edwards. “Our plant-based PX paves the way for 100% sustainable, recyclable products and packaging with complete freedom from crude oil.”
Virent’s Paraxylene, which has been trademarked BioFormPX™, can be used in bottling, packaging and in a wide variety of fibers and materials. The chemical is made through a patented, catalytic process which converts plant-based sugars into PX molecules identical to those made from petroleum. All of Virent’s chemicals are ‘drop in’ replacements that enable full utilization of existing processing and logistics infrastructure without blending limitations. “Our PX can be blended at any ratio the customer desires, and made from a wide variety of feedstocks, including sugar cane, corn, and woody biomass,” explains Edwards. “Our catalytic process is tunable to customer specs, and situated to meet the entire spectrum of fossil fuel replacement.” The company is working with potential partners and customers to explore large-scale commercial options to augment its existing 10,000 gallon/year demonstration plant in Madison, Wisconsin.
Shale gas in Europe and America
Fracking here, fracking there
Europe will have trouble replicating America’s shale-gas bonanza
Nov 26th 2011 | from the print edition
SHALE gas has turned the American energy market on its head. Production has soared twelvefold since 2000, to 4.9 trillion cubic feet, or a quarter of the country’s total gas output. By 2035 the proportion could rise to half. As the shale gas flows, prices have come crashing down. Not long ago, America depended on imports of liquefied natural gas. Now it is likely to become a gas exporter. These benefits have not gone unnoticed in Europe.
The old continent has nearly as much technically recoverable shale gas (natural gas trapped in shale formations) as America. Europe’s reserves are 639 trillion cubic feet, compared with America’s 862, according to America’s Energy Information Administration, a government agency. But technically recoverable does not mean economically recoverable, notes Peter Hughes of Ricardo Strategic Consulting.
Costs are higher in Europe, for several reasons. First, European geology is less favourable: its shale deposits tend to be deeper underground and harder to extract.
Second, America has a long history of drilling for oil and gas, which has spawned a huge and competitive oil-services industry bristling with equipment and know-how. Europe has nothing to compare with that. In 2008, at the height of the gas boom in America, 1,600 rigs were in operation. In Europe now there are only 100. America’s more cut-throat market drives costs down. A single gas well in Europe might cost as much as $14m to sink, three-and-a-half times more than an American one, estimates Deutsche Bank.
Third, America’s gas industry faces fewer and friendlier regulations than Europe’s. Call it the Dick Cheney effect. And fourth, in America wildcat drillers, if they strike it rich, enjoy access to a spider’s web of existing pipelines, so they can get their gas to market. Europe has no such network nor open-access rules.
Some European countries are keen to replicate America’s shale-gas boom. Poland, which may have Europe’s largest deposits, has issued exploration licences to more than 20 firms. Test wells have been sunk. But Poland’s prime minister, Donald Tusk, reckons that commercial production will not get under way until 2014.
Other European countries are less gung-ho about shale gas, often for environmental reasons. France has potentially abundant reserves, but has imposed a moratorium on hydraulic fracturing (or “fracking”), the technique for winkling gas from rocks deep underground, while the dangers are assessed.
These include the possible pollution of groundwater by the chemicals in fracking fluids, and the leakage of methane, a gas that aggravates global warming. Another fear is that fracking may cause earth tremors. Recent seismic activity near a test well in Britain has been linked to it. Such concerns are real and widespread—in August South Africa followed France’s lead and slapped a moratorium on fracking. More studies will be needed before the public is reassured.
Americans worry about the environmental impact of fracking, too. But Europeans worry more, not least because western Europe is far more densely populated than America. Extracting shale gas is more disruptive than hoicking other hydrocarbons out of the ground—far more wells must be sunk than are needed to produce the same quantity of conventional gas. Fracking requires oceans of water, brought in by fleets of noisy tankers. More people will live close to a typical European drilling site, so opposition to drilling permits is likely to be louder.
The legal framework is different, too. In America, mineral rights belong to the landowner. In Europe, they usually belong to the state. So when American property–owners see drills, they see dollar signs. European landowners just see big, ugly drills. (The situation is different in America if the gas lies under federal land. If so, getting leases can be trickier.)
Keep on fracking
American leases typically oblige gas firms to keep flushing out gas regardless of market conditions. So the gas carries on flowing whether prices are high or low (as they are now). And landowners keep wallowing in royalties whether the driller makes a profit or not. No such legal provisions are likely in European contracts.
In America, almost everything points in the right direction for the shale-gas industry, observes Paul Stevens of Chatham House, a think-tank. In Europe most things point the other way. But not all.
Europeans may care passionately about the environment, but they also care about the security of their energy supply, and its price. Many European countries buy gas from Russia, a country that uses hydrocarbons as a weapon to bully its neighbours. This is perhaps why Poland has been quickest to embrace shale gas; it trusts Russia as it would trust a bear to guard a picnic hamper. Ukraine, another nervous neighbour, recently awarded exploration licences to Exxon Mobil and Shell, two Western energy firms.
European gas prices are around twice what they are in America, a big incentive to frackers. In Europe, the price of conventional gas is largely indexed to oil prices, and the gas is provided on long-term contracts that stipulate minimum volumes irrespective of market conditions. This makes locally produced shale gas, supplied on flexible terms, look attractive.
Gazprom, Russia’s state-controlled gas giant, often disparages efforts to extract shale gas—a sure sign that its bosses are rattled. Yet they may not be affected for a while. America’s shale revolution began 20 years ago, but its impact has been felt only in the past five years. Europe’s may take just as long, reckons Mr Stevens. But when the fracking begins in earnest, it could turn Europe’s energy market on its head, too.
Shale Gas Revolution
By DAVID BROOKS
Published: November 3, 2011
The United States is a country that has received many blessings, and once upon a time you could assume that Americans would come together to take advantage of them. But you can no longer make that assumption. The country is more divided and more clogged by special interests. Now we groan to absorb even the most wondrous gifts.
A few years ago, a business genius named George P. Mitchell helped offer such a gift. As Daniel Yergin writes in “The Quest,” his gripping history of energy innovation, Mitchell fought through waves of skepticism and opposition to extract natural gas from shale. The method he and his team used to release the trapped gas, called fracking, has paid off in the most immense way. In 2000, shale gas represented just 1 percent of American natural gas supplies. Today, it is 30 percent and rising.
John Rowe, the chief executive of the utility Exelon, which derives almost all its power from nuclear plants, says that shale gas is one of the most important energy revolutions of his lifetime. It’s a cliché word, Yergin told me, but the fracking innovation is game-changing. It transforms the energy marketplace.
The U.S. now seems to possess a 100-year supply of natural gas, which is the cleanest of the fossil fuels. This cleaner, cheaper energy source is already replacing dirtier coal-fired plants. It could serve as the ideal bridge, Amy Jaffe of Rice University says, until renewable sources like wind and solar mature.
Already shale gas has produced more than half a million new jobs, not only in traditional areas like Texas but also in economically wounded places like western Pennsylvania and, soon, Ohio. If current trends continue, there are hundreds of thousands of new jobs to come.
Chemical companies rely heavily on natural gas, and the abundance of this new source has induced companies like Dow Chemical to invest in the U.S. rather than abroad. The French company Vallourec is building a $650 million plant in Youngstown, Ohio, to make steel tubes for the wells. States like Pennsylvania, Ohio and New York will reap billions in additional revenue. Consumers also benefit. Today, natural gas prices are less than half of what they were three years ago, lowering electricity prices. Meanwhile, America is less reliant on foreign suppliers.
All of this is tremendously good news, but, of course, nothing is that simple. The U.S. is polarized between “drill, baby, drill” conservatives, who seem suspicious of most regulation, and some environmentalists, who seem to regard fossil fuels as morally corrupt and imagine we can switch to wind and solar overnight.
The shale gas revolution challenges the coal industry, renders new nuclear plants uneconomic and changes the economics for the renewable energy companies, which are now much further from viability. So forces have gathered against shale gas, with predictable results.
The clashes between the industry and the environmentalists are now becoming brutal and totalistic, dehumanizing each side. Not-in-my-backyard activists are organizing to prevent exploration. Environmentalists and their publicists wax apocalyptic.
Like every energy source, fracking has its dangers. The process involves injecting large amounts of water and chemicals deep underground. If done right, this should not contaminate freshwater supplies, but rogue companies have screwed up and there have been instances of contamination.
The wells, which are sometimes beneath residential areas, are serviced by big trucks that damage the roads and alter the atmosphere in neighborhoods. A few sloppy companies could discredit the whole sector.
These problems are real, but not insurmountable. An exhaustive study from the Massachusetts Institute of Technology concluded, “With 20,000 shale wells drilled in the last 10 years, the environmental record of shale-gas development is for the most part a good one.” In other words, the inherent risks can be managed if there is a reasonable regulatory regime, and if the general public has a balanced and realistic sense of the costs and benefits.
This kind of balance is exactly what our political system doesn’t deliver. So far, the Obama administration has done a good job of trying to promote fracking while investigating the downsides. But the general public seems to be largely uninterested in the breakthrough (even though it could have a major impact on the 21st-century economy). The discussion is dominated by vested interests and the extremes. It’s becoming another weapon in the political wars, with Republicans swinging behind fracking and Democrats being pressured to come out against. Especially in the Northeast, the gas companies are demonized as Satan in corporate form.
A few weeks ago, I sat around with John Rowe, one of the most trusted people in the energy business, and listened to him talk enthusiastically about this windfall. He has no vested interest in this; indeed, his company might be hurt. But he knows how much shale gas could mean to America. It would be a crime if we squandered this blessing.
THERE could be a silver lining to the shale gas glut in North America, where despite the obvious disconnect between oil and gas prices, investments by resources heavyweights have continued, seemingly without second thoughts.
Any astute observer of the sector would be quick to point out a major theme in the natural gas industry in the US the past year had been the steady shift in drilling from pure dry gas plays to fields rich in natural gas liquids.
While US Henry Hub natural gas prices have averaged around the $US4 per million British Thermal Units mark, benchmark West Texas Intermediate oil prices are at $100 a barrel and the differential has been one of the widest in recent times.
But despite the gas supply overhang, companies are still committing significant funds for shale gas plays.
The latest to outline the 2012 financial year capital spend is Marathon Oil, which hived off its refining arm earlier this year and will invest $4.8 billion next year.
And unsurprisingly, one-third of the money will be spent beefing up its operations in the Eagle Ford shale in Texas, where it plans to operate 17 rigs and double its hydraulic fracturing crew to four by the middle of next year.
Another one-third of the capital outlay will be allocated to its other shale plays, such as Bakken in North Dakota, Woodford in Oklahoma and the Niobrara across Wyoming and Colorado where the company has a stated intent of targeting shale formations rich in oil and natural gas liquids.
Further up north, Canada's Encana yesterday announced it had reached an agreement to sell two natural gas processing plants it considered non-core for over $C900 million.
It is hoping to net $US3.5 billion once its 2011 divestiture program is completed, which it will then reinvest into developing natural gas and NGL production.
Encana invested $770 million this year in building a portfolio of liquids-rich lands, which now stands at 2.1 million acres across Canada and the US.
"We are exploring diversified geological opportunities by drilling about a dozen wells on these highly prospective liquids-rich lands," Encana chief executive officer Randy Eresman said in a statement.
He said the exploration program “goes well beyond our previously announced plan to grow natural gas liquids extraction to an estimated 80,000 barrels per day in 2015”.
All this comes in the week BHP Billiton reported bumping up natural gas production by 12% from its Petrohawk asset in the September quarter and in a broader context, would inject $60 billion over the next 10 years into its recent shale acquisitions.
A recent report from Bentek Energy and Turner Mason & Company finds that thanks to the surge in shale gas, natural gas liquids production is likely to go up by 950,000 barrels per day or 40% to 3.1 million barrels per day in the next five years.
Indeed, analysis of 20 North American exploration and production companies by Barclays Capital shows already there is a discernible shift by natural gas producers to increase their exposure to oil prices by growing their revenues from liquids production.
"As a result, producers have become more insulated from weak gas prices," Barclays said.
"At the beginning of the shale gas boom, our 20-company sample derived less than 50% of their revenues from liquids.
"By 2012, these … companies will derive 64% of revenues from liquids, a 19% change in five years."
The same sample group had an average liquids production of 26% in 2010, which Barclays estimates will grow by a cumulative 5% by 2012 to 31% of total production.
And though the drivers of the change are depressed gas prices due to supply glut and strong oil prices and a concerted shift towards increasing drilling for liquids rather than just natural gas, Barclays says the producers are still not completely immune to natural gas prices as revenue from natural gas is still a big portion of a producer's business.
"But as the share of gas revenue and production is slowly shrinking, producers may become less vulnerable to weak natural gas prices," the bank said.
While Australian gas producers face no such price disconnection risk, the potential green signal for the condensate-rich Ichthys development – despite the 50% cost escalation – makes it one of the less risky projects.
Perhaps less risky than even the leading coal seam gas projects in Queensland.
เป็นปีที่สองแล้วครับสำหรับ BP ที่ตีพิมพ์เอกสาร BP Energy Outlook 2030 ซึ่งสามารถดาวน์โหลดได้จากเว็ปของบริษัทที่ www.bp.com ผมนำ Press Release มาลงให้อ่านกันครับ
BP Forecasts Robust Global Energy Demand to 2030 Despite Efficiency Gains
Release date: 18 January 2012
Global energy demand will continue to grow over the next twenty years, albeit at a slowing annual rate, fuelled by economic and population growth in non-OECD countries. Increased energy efficiency and strong growth for renewable energy are also forecast in BP’s latest Energy Outlook 2030, which is published today.
Global energy demand is likely to grow by 39 per cent by 2030, or 1.6 per cent annually, almost entirely in non-OECD countries; consumption in OECD countries is expected to rise by just 4 per cent in total over the period. Global energy will remain dominated by fossil fuels, which are forecast to account for 81 per cent of global energy demand by 2030, BP forecasts, down about 6 per cent from current levels. The period should also see increased fuel-switching, with more gas and renewables use at the expense of coal and oil.
That gradual switching should see renewables, including biofuels, continue to be the fastest growing sources of energy globally, rising at an annual clip of more than 8 per cent, much quicker even than natural gas, the fastest growing fossil fuel at about 2 per cent a year over the period to 2030.
Presenting the 2030 Energy Outlook, BP chief executive Bob Dudley said: “This report is by turns challenging, fascinating and stimulating for anyone in the energy business. It helps us to be both realistic and optimistic. It shows there are things we can’t change - like the underlying drivers of energy demand - and things we can change – like the way we satisfy that demand.
“The main message is that we need to have an open, competitive energy sector, which encourages innovation and thereby maximises efficiency in order to enjoy energy that is sufficient, secure and sustainable into the future,” he added.
BP chief economist Christof Rühl argues that the impact of globalisation and competition will continue to deliver a remarkable convergence in energy intensity around the world, a measure of energy use per unit of national economic output.
The growth of unconventional supply, including US shale oil and gas, Canadian oil sands, and Brazilian deepwaters, against a background of a gradual decline in oil demand, will see the Western Hemisphere become almost totally energy self-sufficient by 2030. This means that growth in the rest of the world, principally Asia, will depend increasingly on the Middle East in particular for its growing oil requirements.
Oil, the world’s leading fuel today, will continue to lose market share throughout the period although demand for hydrocarbon liquids will still reach 103 million barrels per day (b/d) in 2030, up by 18 per cent from 2010. This means the world will still need to bring on enough liquids - oil, biofuels and others - to meet that forecast 16 million b/d of extra demand by 2030 and replace declining output from existing sources.
While coal is expected to continue gaining market share in the current decade, growth will wane in the 2020-30 decade; gas growth will remain steady and non-fossil fuels are likely to contribute nearly half of the growth after 2020.
Power generation is expected to be the fastest growing user of energy in the period to 2030, accounting for more than half the total growth in primary energy use. And it is in the power sector where the greatest changes in the fuel mix are expected. Renewables, nuclear and hydro-electric should account for more than half the growth in power generation.
This year’s Energy Outlook 2030 examines in more detail several important facets of the global energy story: the pathways for economic development and energy demand in China and India; the factors impacting the energy export prospects of the Middle East; and the “drivers” of energy consumption in road transportation.
In China, growth of energy use is expected to slow significantly after 2020 as the economy matures. Although India’s population is on track to exceed China’s, its energy growth path is unlikely to replicate China’s energy intensive growth path. It will more than double its energy use to 2030, heavily based on coal, but this will still result in consumption of some 1.3 billion tonnes of oil equivalent (toe), or just over one quarter of China’s total.
There will remain a heavy reliance on higher oil exports from Middle East OPEC countries to meet demand. BP’s analysis suggests that the Middle East countries have the capability to bring on the required new production to meet global demand, even though the region’s energy use per capita is expected to remain more than three times as high as the rest of the non-OECD world.
BP says it expects to see steady progress in longstanding efforts to displace oil with gas and to improve the efficiency of energy use within the region. Saudi Arabian, Iraqi, and regional production of gas-related liquids will dominate supply growth as the region’s share of global oil supply rises to 34 per cent by 2030.
Transportation is likely to be the slowest growing sector for global energy consumption; significant improvements in fuel efficiency, including hybridization of vehicles will partly offset continued strong growth in vehicle sales in emerging markets. Hybrid vehicles (including plug-ins) offer consumer flexibility and appear capable of meeting anticipated fuel economy targets in 2030; oil is likely to account for 87 per cent of transport sector energy use, down from 95 per cent today, with biofuels filling most of the gap, and accounting for seven per cent of transport sector energy use.
Global CO2 emissions are likely to rise by about 28 per cent by 2030—slower than the current rate of
energy demand growth due to the rapid growth of renewables and natural gas. If more aggressive policies than currently envisioned are introduced, global CO2 emissions could begin to decline by 2030.
By 2030 today’s energy importers will need to import 40 per cent more than they do today, but the experience will vary by region. In North America, efforts to reduce dependence on foreign supplies should show impressive results in the next couple of decades. Bolstered by supply growth from biofuels as well as unconventional oil and gas, North America’s energy deficit will turn into a small surplus by 2030.
In contrast, Europe’s energy deficit remains at current levels for oil and coal but will increase by some two thirds for natural gas, supplied by LNG and pipelines from the Former Soviet Union.
China’s energy deficit across all fuels will widen by more than a factor of five and India’s, mainly of oil and coal, will more than double in the period to 2030.
BP’s work on the Energy Outlook 2030 supplements BP’s Statistical Review of World Energy which will next be published in June 2012.
Last week, the Economist published an interesting article about the Energy in India. Chart 2 and 3 really caught my eyes. Enjoy reading krub.
Energy in India The future is black Power is essential for India’s long-term growth. But electricity is unlikely to flow fast enough Jan 21st 2012 | NAGPUR | from the print edition
STAB a finger at the middle of a map of India and you will hit Nagpur. Some 20 miles (32 kilometres) north-west of the city is a sloping tunnel bored into the rock. Ride two miles down into the gloom, hanging from a wire, and after a torch-lit hike past underground streams and conveyor belts you arrive at a black wall. Sweating men are rigging it with tubes of explosives and wire detonators. Soon they will blast it apart, and down should tumble tonnes of India’s most important commodity: coal.
In coal India has something as abundant as people. As more Indians enjoy the trappings of middle-class life and the country industrialises, demand for coal-fired electricity will continue to rise smartly, roughly in line with economic growth. India may not have much oil or gas to call its own but it has the world’s fifth-largest coal reserves. And it has successfully raised a mountain of the other raw material needed to turn carbon into sparks: capital. Some $130 billion has been ploughed into the power industry in the past five years. Of that, $60 billion or so has come from the private sector—probably the largest-ever private-sector investment India has seen.
Possessing coal and capital is no guarantee that India’s energy boiler will work properly, however. It also involves multiple states, government ministries, regulators, mandarins, politicians, tycoons, environmentalists, villagers, activists, crooks and bandits. There are the usual gripes of an emerging economy: blackouts (during peak hours the system delivers 10% less electricity than customers want) and an inadequate grid that does not reach some 300m people (although it has improved a lot in recent years).
There is also a risk that India cannot deliver the long-term increase in electricity generation that its economy needs to fulfil its potential. On January 18th a group of influential businessmen gathered in Delhi to bend the prime minister’s ear on this very matter.
The problem is partly one of design. Coal is dug up by a state-monopolist that has failed to boost output significantly in recent years, unlike China (see chart 1), and so cannot keep up with demand. Power is distributed to homes and firms by publicly owned grid companies that are often bankrupt, their tariffs kept too low by local politicians. Trapped in the middle are the firms that run power stations. In desperation they are importing pricier foreign coal, but the grid companies cannot afford the power it produces. With too little coal and wobbly customers, the private firms that have built new power stations are in financial trouble. Another wave of private investment looks unlikely.
In India, though, no one expects perfect design. The economy sits somewhere between the old command-and-control approach and the new ways of markets and private capital. What is worrying is that India’s talent for improvisation—a collective ability to muddle through—has deserted it when it comes to providing electricity.
The problem has been clear for ages. A circuitous blame game is taking place. Ministries squabble but no one knocks heads together. If you trawl round the offices of industry bosses the livid letters they brandish trace their incandescent correspondence with each other. Power, so vital for growth, is India’s biggest bottleneck. The danger is that it becomes a metaphor for the whole economy: many fear that the muddle-through approach of the past two decades of boom has diminishing returns.
One dam thing after another
It wasn’t always all about coal. Jawaharlal Nehru, the country’s first prime minister after independence, was obsessed with hydroelectric dams, calling them the “temples of modern India”. It would have been good for India’s environment, and the world’s, had many more temples been raised. The fad for hydro trickled away and it now provides only 14% of India’s power compared with up to a half in the 1960s.
That seems unlikely to change—India is too chaotic and free a place to manage the feats of national machismo that allowed China to build the Three Gorges dam. Although new projects are planned in places such as Kashmir and neighbouring Bhutan, harnessing Himalayan rivers to power all of India is for now a dream, not a policy.
The subcontinent has plenty of sun and wind, and states including Gujarat and Tamil Nadu are keen to encourage investments in renewable energy. These are likely to be niche sources of power, thanks to problems getting land and their high cost.
As for nuclear power, India’s attitude has long been hyperbolic on paper and ambivalent in practice, despite striking a civilian nuclear deal with America in 2005. Foreign companies are put off by the prospect of unlimited liability in the event of an accident. Nuclear plants face opposition from hostile state governments and protesters. Events in Japan have not helped. “By the time people forgot Chernobyl, along came Fukushima,” says one industry bigwig.
The result is that, as in China, fossil fuels will dominate the energy mix (see chart 2). Carbon emissions will rise in tandem, by about two-and-a-half times between 2010 and 2030 according to McKinsey, a consultancy. The growth of India’s power industry—assuming it is built and largely fired by fossil fuels—would contribute about a tenth of the total global rise in emissions over the period. Most Indians do not feel too guilty, arguing that dirtier rich countries, not poor ones, should show restraint. India’s emissions will remain far below those from America and China both in absolute terms and per head.
Fossil hunting
India has some oil and gas, mainly offshore and in Rajasthan, although production has been faltering. It lags China in developing pipelines from energy-rich Central Asia. Coal, then, is key. India’s is not of a high quality—it contains too much ash—but there is lots of it. The British started swinging picks in earnest in the mid-19th century, to meet the demand of a burgeoning railway system, and undertook geological surveys in Bengal. Today east India remains coal’s heartland and control of the sooty stuff lies with one of the most important companies that most people have never heard of: Coal India.
It is a mighty odd beast. Its blood is of the public sector, with modest buildings, 375,000 staff, an empire of largely opencast mines and company towns, and even its own song. Its managers are proud scientists and engineers. And prices are fixed by the state, at far below international levels. Yet its brain has some capitalist cells.
After privatisation in 2010, a tenth of its shares are listed (the rest are owned by the state) making it India’s third-most-valuable firm, worth $44 billion. It makes a huge return on equity of over 35%, has $11 billion of unused net cash and reinvests only a fifth of its gross cashflow. It even has a financial gnat on its hide in the form of TCI, a London-based activist hedge fund famed for its stagy belligerence.
What is beyond doubt, though, is that Coal India is not digging fast enough (see chart 3). Output has been flat for the past two years—a dire result. India’s ratio of production to reserves is middling by global standards and is well below China’s. Assuming production picks up and grows in line with the long-term average, a vast shortfall in production will still stunt growth in power generation.
From his office in Kolkata, outside which street vendors boil vats of soup on coal stoves, the firm’s outgoing chairman, N.C. Jha, says that Coal India is being made a scapegoat. The lag in production partly reflects one-off factors, such as bad weather, but is mainly the result of a deliberate clampdown by the central government on new permits for buying and clearing land, and an explosion of red tape. “Give me land, and I will give you coal,” says Mr Jha.
This complaint is reasonable. At Gondegaon, a vast opencast mine in the Nagpur field, engineers need more space to dump the earth and rock that is dug up with coal. A map shows the pit hemmed in by villages and scrub land. Acquiring the land, compensating the villagers and making sure they shift poses a challenge harder than geology, says the company. “We do not have a magic wand in our hand to increase production,” says D.C. Garg, boss of the Coal India unit responsible for the area. In east India the firm faces another problem: most reserves are in remote areas where Maoist guerrillas operate.
Yet for all the hurdles it faces, many say Coal India is part of the problem. A senior government official says it is riddled with trade unionism and gangs who steal coal—something the private sector would resolve by sending in “the toughest son of a bitch” they could find. The boss of one smallish state-owned electricity generator details how local Coal India employees collude with middlemen to steal his fuel. He says that its local chief is “hugely compromised” by corruption.
And no one really knows what Coal India’s mission is, thanks to its hybrid status. Should it maximise profits and the dividend it pays to a cash-strapped government, despite the fact it is a near-monopoly and unregulated? Or is its job to deliver cheap fuel for the nation and accept lower returns by investing more on new mines?
Let’s burn Australia instead
Private generating firms are not waiting to find out the answer to this identity crisis. Instead they have assumed that the state will not deliver enough and are prepared to import vast amounts of coal to fire their plants, either by acquiring it from wholesalers or by buying foreign coal mines. Some $7 billion has been spent in the past six years on pits in Australia, Indonesia and Africa. Gautam Adani, a Gujarat-based tycoon, is building a private network of mines abroad that feeds ports and power stations in India.
Amish Shah of Credit Suisse reckons that by the year to March 2017 domestic coal production will meet only 73% of demand, leaving a gap of some 230m tonnes, almost five times the level of 2012. Include other industries that use coal, such as steel, and some analysts calculate that India’s total imports by 2017 could reach some 300m tonnes. That is on a par with the current exports of Australia, or those of Indonesia, South Africa and Canada combined.
Even if India could improve its ports and already stretched railways, and adapt its power plants to burn alien coal, can it afford to import so much? Coal prices have soared in recent years (the benchmark price is some 50% above its average in 2009), partly due to Chinese demand. Indonesia has imposed new rules that hamper foreign mine owners from exporting coal at below market rates. So, adjusted for quality, foreign coal is perhaps four times pricier than the local stuff. The cost of shopping abroad could be as much as $20 billion by 2017—or 1% of today’s GDP.
That would swell India’s overall annual energy-import bill. Include coal used for purposes other than power, liquefied natural gas and oil and it could rise by $65 billion or so by 2017, compared with the year to March 2011, according to Sanjeev Prasad of Kotak, a broker. That would put a huge strain on the balance of payments. Even if India can afford to import all this coal, the next question is whether it can persuade its population to fork out for the electricity it produces.
Torture boards
Electricity meters are installed in unexpected places. Power in Dharavi, a giant Mumbai slum, is now largely tolled, with meters nestling next to curing factories piled with goat skins and people melting down used plastic cutlery. But the city, where power is distributed mainly by two private firms, is an exception: almost everywhere else state electricity boards operate the grid, usually badly. They typically lose about a third of the power they buy through theft or inefficient kit, and one executive reckons that up to another third is delivered legally to rural customers who pay subsidised prices or get it free. The result is that a small proportion of customers foot the bills.
Although tariffs are notionally set by regulators, local politicians often hold sway and keep them low to win votes. The legislation that governs power is reasonable but unenforced. The electricity boards haemorrhage cash as a result. They lost $11 billion, excluding any subsidies, in the 12 months to March 2010—the last year for which reliable figures are available.
The consequences are twofold. First, there is not enough money to upgrade the network: up to $200 billion of capital investment is required. And second, if the cost of the power rises because of the expense of imported coal, these outfits are neither strong enough to absorb the financial hit themselves nor capable of easily passing it through by raising prices to customers. That means it is their suppliers, the generating companies, that get squashed.
“I can see if someone is sleeping on the job,” boasts Arup Roy Choudhury, the chairman of NTPC, the country’s biggest electricity generator. In the floor above his office in Delhi a CCTV studio allows him to spy on his empire. He can zoom in on a giant construction site in Mouda, near those mines in Nagpur, where in March a new plant will fire up, fuelled by coal produced by Coal India. NTPC is likely to get the coal it needs partly because it is state-owned and big.
Another power firm in the same state with a new plant coming on line in March expects to get only half the fuel originally promised by Coal India. Private-sector firms with plants coming on line often assume they will be last in the queue for domestic fuel. If they substitute imported coal for domestic coal they worry that they may not be allowed to pass on the costs and that if they are, the electricity boards won’t be able to pay.
Generation should be a success story. After a false start in the 1990s, during which even Enron was briefly and disastrously tempted in, mainly local firms, including Tata Sons and Reliance Group, have piled in once more. Special rules were created to fast-track “ultra-mega power plants”, among the largest in the world, with their own captive coal supply and exemptions from some red tape. Total capital investment (including NTPC) has been perhaps $60 billion in the past five years. Yet now share prices have slumped and the central bank has been forced to reassure financial markets that a wave of defaults in the sector will not hurt the banks, which have about 7% of their loans to the power industry, mainly to generation firms.
The true cost to the country is not a few bad debts but a reduction in long-term investment plans as confidence wanes. Across the industry “projects are taking a hit, due to a lack of fuel among other things,” says J.P. Chalasani, the chief executive of Reliance Power, a generation firm. For the economy to expand at 8-9% it will need to add large amounts of generation, consistently. “We are nowhere near that unless immediate action is taken. At some point all this will hit our GDP growth.”
In theory there are two solutions to the looming power problem. One is to privatise the electricity boards, end Coal India’s de facto monopoly or break it up, create new regulators and give teeth to existing ones, and then hope that market forces raise standards, tariffs and production. The other is to resort to command-and-control, with a single authority breaking heads.
Either of these approaches might be better than today’s squabbling and passivity. Unfortunately, neither is likely. Privatisation is too politically sensitive, as is allowing private firms, let alone foreigners, to run riot over India’s coal beds. And the mesh of states, law courts, ministries and coalition politics means iron fists come out only in a crisis.
Watch while we juggle
That leaves an alternative approach of administrative fiat and improvisation. It hasn’t worked so far but there are some grounds for hope. A recent court ruling has prodded many electricity boards to raise tariffs. Crafty ways are being cooked up to allow private miners to do the digging while Coal India retains its notional title to the coal, and to grant permission for more “captive” mines where a private generator digs up its own fuel.
Banks seem to have been given the nod by the central bank to ease the terms of their loans to power firms without booking losses. Government officials talk of spreading the cost of imported coal across all firms, so it is not borne by a few, and dream of open access where a power station could bypass the state grid operators and plug into customers directly.
It is a safe bet that India’s skills of improvisation will recover—helped by stern words from the prime minister. The lights will not go out anywhere for long enough to annoy voters unduly, and by historical standards there will be decent improvements in the reach and availability of electricity. Companies which need reliable power supplies, including India’s technology giants, will carry on building their own generators just to be sure. Those states that can guarantee power supply, such as Gujarat, will attract the majority of energy-intensive investment, such as car factories.
If the test is avoiding a national catastrophe, India’s power sector will pass it. But if it is delivering the infrastructure that can allow the economy to grow at close to a double-digit pace and industrialise rapidly, India is failing.
อ่านเจอประโยคนี้ "the end of America's coal era" แล้วก็สะดุ้งเลยครับ
American coal
A burning issue
Tighter regulation, bountiful natural gas and declining installation costs for renewable energy herald the end of America’s coal era
Jan 28th 2012 | HARLAN COUNTY, KENTUCKY | from the print edition
A FREIGHT train, its dozen cars loaded with coal covered in a light dusting of snow, snaked through the narrow valley, sometimes following the two-lane highway and sometimes crossing it. The valley was silent and snowy, and though it was two days into 2012 it could easily have been 1982, 1942 or 1922: coal has been mined in Appalachia and carried out by rail for well over a century.
And by some measures, coal is still going strong. It provides more of America’s electricity than any other fuel. Production has fallen off since 2008, but it remains high, as do prices, for which thank the developing world’s appetite. In Appalachia, coal remains a source of well-paid jobs in a region that needs them: for the first three quarters of 2011 employment in the Appalachian coal industry was at its highest level since 1997. And the Powder River Basin, which spans Wyoming and Montana, has become America’s major source of coal in the past decade, relieving overmined Kentucky and West Virginia. The Energy Information Administration (EIA) reckons America has enough coal to meet current demand levels for the next 200 years.
But if the raw numbers look good, the trends tell a different story. Regulatory uncertainty and the emergence of alternative fuel sources (natural gas and renewables) will probably make America’s future far less coal-reliant than its past. In 2000 America got 52% of its electricity from coal; in 2010 that number was 45%. Robust as exports are, they account for less than one-tenth of American mined coal; exports cannot pick up the slack if America’s taste for coal declines. Appalachian coal production peaked in the early 1990s; the EIA forecasts a decline for the next three years, followed by two decades of low-level stability. Increased employment and declining productivity suggest that Appalachian coal is getting harder to find.
Toughening regulation has an effect, too. Coal-fired power plants are the source of more than one-third of greenhouse-gas emissions in America. Last July the Environmental Protection Agency (EPA) issued a rule that requires 28 states to reduce the amount of sulphur dioxide and nitrogen oxide they emit; in December came another, reducing the amount of mercury and other toxic air pollutants that power plants can puff out.
Many plants have already made the necessary upgrades and retrofits; around 53% of America’s coal-fired capacity comes from units fitted with scrubbers. But others, particularly older plants, will have to decide whether such expensive upgrades are worth doing at all. Most of America’s coal-fired capacity comes from plants at least 30 years old, and as much as 14% of existing coal-fired plants, accounting for 4% of America’s generation capacity, will have to be retired in the next five to eight years. Energy providers face a stark choice. They can fight these regulations in court (outcome uncertain). They can retrofit old plants: plenty have done that, too. Or they can build new plants—in which case, far more are choosing plants that burn natural gas or use renewables rather than coal.
To some, regulations prove the current administration’s hostility to coal. To others, however, they are a long-overdue attempt to gauge a putatively cheap fuel’s true external costs. A National Academy of Sciences report estimated that the external costs unrelated to climate-change costs (to human health, crop and timber yields, building materials and recreation) of coal-fired power plants in 2005 totalled $62 billion. A study of coal’s effects on Kentucky’s budget in 2006 found that it contributed $528m in revenue, but its on-budget costs—training, support, repairs to the roads, R&D for the coal industry—totalled $643m. A study in West Virginia in 2009 also found the coal industry a net cost to the state.
Without alternatives, America might need to resign itself to these costs. But alternatives are there. As coal’s share of America’s electricity-generation market fell between 2000 and 2010, those of natural gas and renewables rose: gas from 16% to 24%, and renewables from 9% to 10%.
The EIA forecasts that America will still obtain 39% of its energy from coal by 2035, but that assumes a consistent regulatory framework. Other sources are less sanguine. Deutsche Bank predicts that coal’s share will fall to 20% by 2030 as regulatory risk grows, with natural gas and renewables rising. That seems more likely. The EPA’s new emissions rules may have been stayed by the courts, but they loom nonetheless, hampering investment in coal.
The switch away from it will be painful for some. But as Robert Byrd, the late senator from West Virginia, once said, coal-dependent regions “can choose to anticipate change and adapt to it, or resist and be overrun by it.”
Difference Engine: Awash in the stuff
May 4th 2012, 14:29 by N.V. | LOS ANGELES
EVEN as it tries to slow production down, America is still pumping three billion more cubic feet (85m cubic metres) of natural gas a day out of the ground than it can consume. The country has become so awash in the stuff since “fracking” (hydraulic fracturing of gas-bearing shale deposits) began barely five years ago that the price has plummeted from $8 per thousand cubic feet to $2. (A thousand cubic feet of natural gas contains roughly a million BTUs of energy.) Not that long ago, natural gas was a tenth of the price of oil in energy terms; now it is a 50th.
If the natural-gas companies go on producing at the current rate, all the storage reservoirs in America will be full by autumn. With nowhere left to put the stuff, its marginal price will fall to zero. Such a situation is unsustainable.
Extracting natural gas from tightly packed shale deposits costs around $5-6 per thousand cubic feet. Wells have to be sunk thousands of feet underground and then drilled horizontally through the gas-bearing formations for thousands of feet more. A slurry of water, quartz sand and chemical additives has then to be pumped into the well at high pressure, to fracture the shale and open fissures for the trapped gas to escape. And all the waste water has to be pumped back to the surface to be processed and stored, at considerable cost.
At today’s spot prices for natural gas, producers are losing money hand over fist. Many could cease to exist as the industry is forced to contract. And consolidate it will. There are so many firms that the top ten producers account for less than half the market between them. The trouble is that fracking is almost too productive for its own good, and there is just too much shale gas out there. Only big companies with deep pockets will survive.
Back in 2000, America had enough accessible natural gas in the ground to provide a little more than 12 years of consumption. But once the country’s shale deposits started to be tapped in earnest, reserves leaped to over a century's supply. And because output from existing wells is not tapering off as fast as initially expected, the actual reserves could wind up being double present estimates.
Such a bonanza ought to be a blessing. And one day it will be. But right now finding users to suck up all that excess natural gas is a headache.
With the United States importing more than half its oil (at over $1 billion a day), and transport accounting for two-thirds of the country’s oil consumption, logically the biggest single market for natural gas ought to be motorists. If they could be enticed to switch from petrol to compressed natural gas (CNG)—as drivers in Brazil, Iran and Pakistan have done—America would no longer need to depend on foreign oil.
But do not count on it, even though there is much to like about CNG. For one thing, it is the cleanest burning of fossil fuels—producing significantly less carbon dioxide, nitrogen oxides and unburned hydrocarbons than petrol. Because it leaves no carbon deposits inside the engine, wear is reduced to a minimum and oil changes are required less often. At the equivalent of typically $2 a gallon, CNG is half the price Americans pay at the pump for petrol. It is also safer. If its pressurised container is ruptured, CNG does not pool on the ground, but disperses into the air. And with twice the ignition temperature of petrol, it is less likely to catch fire.
So, what is holding CNG back? One reason is that converting petrol engines to run on CNG is expensive. Conversion kits that meet Environmental Protection Agency (EPA) requirements cost anything from $6,000 to $16,000, depending on the vehicle. For another, the pressurised storage tank leaves little space for luggage in the vehicle’s boot.
Only one car designed specifically to run on CNG, the Honda Civic GX, is commercially available in the United States. Compared with its petrol-engined LX sibling, the GX has significantly lower power, has similar fuel economy, and has a sticker price that is $7,000 higher. But it is cheaper to refuel. The GX is also squeaky clean, having the least polluting internal-combustion engine in production anywhere. In California, it has the enviable right—like electric vehicles and certain hybrids—to use the car-pool lanes with only the driver aboard.
CNG cars have other drawbacks that similarly plague electric vehicles—including range anxiety. Refuelling stations are few and far between. At the last count, America had little over 1,000 natural-gas stations compared with 120,000 petrol stations. Honda sells a home-refuelling appliance called Phill, which uses the domestic gas supply to recharge the GX’s pressurised tank (equivalent to an eight-gallon petrol tank) in 16 hours, to give a typical range of around 200 miles (320km).
Lorries and buses are a much better proposition. Operating on fixed duty cycles and returning to base at the end of the working day, buses, delivery vans and waste-collection vehicles are ideal candidates for CNG. Indeed, the vast majority of America’s fleet of 114,000 CNG vehicles are buses and other municipal vehicles.
With diesel even more expensive than petrol, trucking companies have started converting their long-haul fleets to run on CNG. Cummins, a maker of heavy-duty engines, is doing good business with its new natural-gas engine as lorry owners re-equip their fleets to comply with new EPA regulations, starting in 2014, for lower carbon-dioxide emissions.
But none of that is going to happen overnight. Nor will it come anywhere close to mopping up America’s excess supply of natural gas. What will, though, are developments afoot in the process and power-generation industries. In both, the switch to cheap shale gas is underway—and represents nothing less than a renaissance in American manufacturing. A typical case is Dow Chemical, which had planned to build a new petrochemicals plant in the Middle East, but is now also constructing one in America, to take advantage of the low cost of natural gas.
In fact, cheap shale gas is giving American chemical companies a competitive edge over foreign rivals. That is because domestic processors use ethane, a natural-gas liquid derived from shale gas, as a feedstock for various chemical products. Foreign competitors rely on naphtha, a more expensive oil-based feedstock. The American Chemistry Council, a trade association, calls shale gas a “game changer” that is rejuvenating industry and bringing jobs back home.
That is all to the good. But your correspondent is convinced that the one thing that will do more than anything else to revitalise America will be to hasten the on-going switch from coal to natural gas for generating electricity.
Right now it costs twice as much to make electricity from dirty coal as it does from clean natural gas—ie, 12 cents or more per kilowatt-hour versus six cents. Yet, coal still accounts for 45% of power generation, compared with 24% from natural gas (plus 20% from nuclear, 6% from hydro, 4% from renewables and 1% from oil). Retire 30% of today’s coal-fired capacity and replace it with shale, and the savings would be enough to peg electricity prices for a decade, or even lower them.
This is no pipe dream. By April 2015, power stations throughout the United States will have to meet stringent new requirements for the amount of mercury they can emit. As a result, some 250 coal-fired plants built in the 1950s and later will have to be retired. Replacing them with clean natural-gas capacity will create demand for billions of cubic feet of shale gas. Even though gas prices will most assuredly rise, the savings for the country over the next 30 years—in environmental as well as economic terms—will be enormous.
Correction: We originally wrote that Dow Chemical will be building the plant in America instead of the Middle East. In fact, Dow plans to build both plants. Sorry.
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