Sewing up lower costs from falling commodity prices

In the past year the prices of many commodities—including cotton and oil—have fallen 30 to 50 percent. That should be good news for most apparel and footwear companies, since these are key raw materials for the production of yarns and the synthetic rubbers used in footwear. Companies are asking themselves how these price falls will translate into cost reductions from their suppliers, and how fast that will happen.

The basic estimates look promising. In a typical, mid-priced knit garment, raw cotton represents around 50 to 60 percent of the total cost of cotton yarns, yarn accounts for about 60 percent of fabric, and fabric for about 50 to 60 percent of the cost of a finished garment. Therefore, given the 30 percent drop in the price of raw cotton in the past year (Exhibit), a buyer might expect a 5 to 7 percent drop in apparel cost, depending on the complexity of the garment. The picture is similar in synthetics, with the price of PET¹ dropping around 25 percent between March 2014 and February 2015.

Few apparel and footwear companies have captured significant commodity-related savings from their suppliers, however. Some companies don’t have a structured process in place to ask for supplier cost reductions when commodity prices fall; others don’t know what cost reduction to ask for when they do. Of those that do ask, many receive small reductions of 1 to 2 percent from some suppliers, while others receive no savings at all.

When pressed to offer commodity-related cost reductions, suppliers may argue that the effects of raw material prices on their own costs have been smaller than estimated, have been diluted by other players in the value chain, or have yet to trickle through to them. (In practice, changes in cotton yarn prices typically lag commodity prices by one to three months.) Without a deep understanding of the whole value chain and such facts at their fingertips, companies find it very hard to counter these points.

To claw back the full savings potential offered by commodity price drops, companies need to develop a detailed picture of the end-to-end value chains of their products, and of the way input cost fluctuations percolate through that chain. That is a complex business, requiring an understanding of the underlying chemistry of key raw materials, the structure of the industries that produce those materials, and the evolution of supply and demand over time. The sidebar below (“From oil to polyester”) describes some of the complexities surrounding the production of PET, one of the most important apparel inputs. A similarly complex value chain exists for many important polymers used in the footwear industry, like EVA (ethylene-vinyl acetate), PU (polyurethane) and SBR (styrene-butadiene rubber).

From oil to polyester

While most apparel companies understand the cotton value chain relatively well, the value chain for polyester is often more of an enigma. Polyester fiber is made from PET (polyethylene terephthalate) that has been melted and spun. PET, in turn is made of two materials: Purified terephthalic acid (PTA) and mono ethylene glycol (MEG). Both these materials are made from oil, and their price tracks the oil price. MEG can also be made from natural gas, but since the marginal producers, especially in East Asia, currently use oil as a feedstock, the MEG price tends to follow the oil price rather than that of gas.

Analysis of the value chain shows that when oil was at $100 per barrel, it constituted approximately 50 percent of the cost of PET. If oil prices stay around $50 per barrel, PET prices should remain around 25 percent lower than last year. Moreover, overcapacity in the industry means the PET market is highly competitive and prices are set by the marginal producer, resulting in price declines over the past ten years. Thanks largely to overcapacity in China, the PET industry is currently running at only 66 percent of its full utilization. With demand projected to grow at 3 percent a year, overcapacity is likely to continue to keep prices down. Together these factors suggest that polyester prices will stay low at least until the end of 2015.

Companies that have taken such a fact-based and structured approach to supplier negotiations in the response to commodity price changes have been able to capture savings of 4 to 6 percent from their suppliers in a wide range of categories. One large apparel retailer did this by building a “rapid response system” based on detailed analysis of the effect of commodity price changes on the costs of different yarn and fabric types. Significant swings triggered assertive communications with its suppliers, asking for price adjustments within 30 days. The company was able to support subsequent negotiations with the data from its analyses.

The bigger picture

Beyond the specific opportunities related to a better understanding of commodity price effects, a procurement approach built on a deeper understanding of the whole value chain has the potential to offer more than just quick wins. It can also help the industry meet some of its most enduring challenges. For a decade or more, apparel companies have been fighting rising costs, driven by increasing labor, raw material and energy prices, as well as compliance costs in Asia. Their main weapon in this war against inflation has been to move production to lower cost countries and regions. But this strategy has many drawbacks: Supply chains must be reconfigured, and companies need to expend time and effort ensuring new suppliers meet the required standards of quality and environmental and social responsibility. Worse, by focusing so much on where their products are manufactured, these companies may not be paying enough attention to how they are made—and to the opportunities to reduce costs, manage risk and improve efficiency in their existing value chains.
There is also a significant opportunity for the apparel sector to make use of procurement best practices from other sectors. For example, the automotive and electronics industries for years have used advanced sourcing approaches such as Design to Value (DTV) teardowns, cleansheet “should cost” modeling and supplier collaboration. We will show in subsequent articles how these approaches can be adapted for apparel and footwear companies, and how leading players have driven 10 to 20 percent savings through their use.

Source: http://www.mckinsey.com/insights/operations/sewing_up_lower_costs_from_falling_commodity_prices

China finds opportunities in oil price drop

This week, Cnooc announced plans to reduce capital spending as the government and large state-owned enterprises respond to the collapse in oil prices. China’s third-largest oil producer said it would cut development spending by 67 per cent and, albeit less dramatically, reduce exploration and production capital expenditure.

At the same time, the Beijing government and refiners such as Zhuhai Zhenrong have increased their purchases of crude oil to record levels. Sinopec, another big state-owned energy enterprise, opened up a tank farm for crude oil on the resort island of Hainan in November.

These apparently contradictory signals reflect changes in the sources of growth in a slowing Chinese economy and show how the government and corporate China are exploiting the collapse to reduce their longer-term vulnerability to price swings in the volatile energy market.

It is easy to understand why Cnooc is cutting back spending. The economy is growing slightly below the level the cadres have commanded and slowed to 7.1 per cent in the final quarter of 2014. Reinforcing that trend is the fact that the energy intensity of Chinese production has gone down. Chinese crude oil demand per unit of gross domestic product has been dropping by 4.3 per cent a year since 2005, according to data from JPMorgan Private Bank.

Moreover, as the sources of growth shift slowly from manufacturing to services and from exports to domestic demand, that drop will probably accelerate, making further oil capex cuts likely — and shareholders happier.

But China is also looking ahead and taking advantage of the speedy and unexpected reversal in the oil price.

The increase in demand for crude on the mainland comes because China is exploiting lower oil prices to dramatically boost its storage capacity for both commercial and strategic reasons. By doing so, it will address one of its perennial weaknesses, its reliance on imported energy, and make itself more competitive.

The move comes at a moment when pessimism about Chinese prospects generally is on the rise. That downbeat attitude reflects chronic excess capacity, an overbuilt property market and concerns about a corporate sector that has borrowed too much, whether in renminbi or appreciating US dollars.

The way China is taking advantage of the declining oil price also suggests that some of the pessimism is unwarranted. The dramatic expansion in commercial and strategic holdings of crude while the price is half of what it was just months ago is only part of the story. The government is also increasing taxes rather than pass on the full benefit of bargain fuel prices to consumers.

Those taxes will go partly to dealing with China’s monumental environmental issues, according to Miswin Mahesh, Barclays’ commodities analyst in London. That spending should be good for China and its neighbours, if the past is any guide.

Up to now, Chinese growth has been good news for the rest of the world. In 1990, China’s contribution to global GDP growth was 5 per cent. Since 2010, the figure has swelled to more than 40 per cent. Its role as a crutch for world growth has become especially important as the growth rate of other emerging markets has fallen. (Last year emerging markets as a whole grew only 4 per cent — the worst figure since 2009 — and this year may even drop slightly below that.)

China’s demand for crude is already lifting the fortunes of shippers and others. Among the biggest beneficiaries of the increase in Chinese appetite for crude is Iran, says Amrita Sen, chief oil analyst with Energy Aspects in Houston and London. Indeed, Chinese demand for oil from Iran accounts for more than India, Japan, and South Korea combined. (All these countries have received specific exemptions from US-imposed sanctions on Iran, and they may also import more than the level the waivers allow.)

Earlier on, before China received permission from the US to procure Iranian oil, the country paid for its Iranian imports in renminbi. But today, Ms Sen says, the Chinese are using dollars. That benefits both sides. Tehran finds dollars more useful than renminbi as there are still controls on what Iran can do with its Chinese currency.

At the same time, China has clearly decided it is better to obtain real assets such as oil with its dollars than to purchase paper securities. Right now, both US Treasuries and the US dollar look attractive, while oil does not. But China always takes the long view — and in the long term neither Treasury securities nor the greenback seem as attractive as they do today — at least as seen from Beijing.

Source: http://www.ft.com/intl/cms/s/0/b083f7b4-ab8d-11e4-b05a-00144feab7de.html#axzz3Qnw9Fh8K

Dollar bears in for shock if US cuts energy imports

The future of the dollar is more likely to be determined in the shale gas and oilfields of Dakota and Texas than in the sovereign wealth funds of Asia and the Middle East. This is because striking new technological developments are set to transform America’s energy supplies, significantly improving the US balance of payments and the long-term outlook for the greenback.

The US’s current account deficit has been a longstanding drag on the dollar. At the height of the credit boom in 2006, it reached $800bn or 6 per cent of gross domestic product. Though the deficit has halved as the credit crunch has lowered imports, it still stands at 3 per cent of GDP, largely because the US, like the eurozone, Japan, China and India, remains a major energy importer, with annual net foreign oil purchases of $300bn a year. As the US economy slowly recovers, the International Monetary Fund expects the US current account deficit to start rising again. That would lead to foreign central banks accumulating greater reserves of dollars.

But such straight-line forecasts are likely to be challenged as the US’s shale gas and “tight oil” reserves are commercially exploited over the next few years. The US has vast reserves of shale gas but, until recently, energy companies were unable to tap the gas trapped in shale rock. Now, through hydraulic fracturing or ‘fracking’, US reserves of economically available gas supplies have started to rise sharply.

Already the ratio of US gas reserves to annual production has increased from eight years to 12 years. This may not appear substantial when compared to other regions of the world. Qatar, for example, has proven gas reserves well above 100 years of current production. But fracking may allow the US to soon count up to one hundred years of gas reserves relative to current production. That would lead to a major shift in the US’s energy outlook.

In addition the exploitation of tight oilfields through new technology is increasing the US’s domestic oil production relative to imports. This marks a significant departure from the past three decades, when the share of US oil consumption accounted for by foreign supplies rose from around 30 per cent in the 1980s to over 65 per cent by the time the credit crunch began in 2007. In 2010 imports had already declined to 61 per cent of total US oil consumption and are set to decrease further.

More strikingly, the US is starting to export oil again given its increased domestic oil production. Ten years ago, US oil exports were less than 10 per cent of the country’s oil imports. Now they are close to 20 per cent of US imports as local oil output surges. For example, North Dakota yielded more than 500,000 barrels of oil a day at the end of last year, exceeding the production of Opec member Ecuador.

There remain significant environmental concerns regarding the use of fracking to exploit shale gas in commercial quantities. But if America is able to dramatically increase its energy reserves, then it can reduce its reliance on foreign supplies – particularly from volatile regions such as the Middle East.

Over time this would engineer a sharp improvement in the US current account deficit. As the US’s net oil import position accounts for the lion’s share of its balance of payments deficit, increased domestic production has the potential to reduce the US current account deficit from 3 per cent of GDP to lower levels, or even send it into a surplus over the next decade.

The US economy last ran a current account surplus at the start of the 1990s. If the US is able to return to a similar position over the next few years owing to reduced energy imports, it would have three important consequences for financial markets and the global economy.

First, in the foreign exchange markets, the dollar would continue its recovery against the euro and other major currencies that began during the financial crisis of 2008. Consensus forecasts that the greenback will keep on depreciating to rebalance America’s current account deficit will need to be torn up.

Second, the negative relationship between oil prices and the dollar would break down. China and India are still likely to be large consumers of Middle East energy but significantly reduced US foreign oil purchases will limit the growth of the region’s sovereign wealth funds. As a result, their dollar-diversifying activities, heightened when oil prices rise, will be constrained in future.

Third, stronger growth in the US on the back of a more balanced economy would call into question the Fed’s current stance of keeping monetary policy super-loose.

Thus the conventional wisdom of an ever-weakening greenback is likely to become obsolete. Over the next decade, the currency is set to benefit from the US’s reduced reliance on foreign energy. That will be a positive shock for US consumers and companies and a negative shock for long-term dollar bears.

Source: http://www.ft.com/intl/cms/s/0/91501a42-5273-11e1-ae2c-00144feabdc0.html#axzz1mYi1Q0j0

Boeing: Faster, faster, faster

THERE are not many businesses in which the next six years’ worth of customers form an orderly queue, putting down fat deposits and topping them up with further instalments as they wait in line. But that is Boeing’s fortunate position. On January 25th it announced a 21% rise in annual net profits, to $4 billion.

Last September, after three years of delay, Boeing made the first deliveries of its newest model, the 787 Dreamliner. A revamped version of the trusty but ageing 747 jumbo has also arrived, two years late. A few airlines got fed up and cancelled, but most had little choice but to keep waiting. Boeing’s main rival, Airbus, has an even longer backlog—up to eight years at current production rates. And the delivery schedule for Airbus’s answer to the Dreamliner, the A350, has been slipping.

Last year, straining to ramp up production to meet soaring demand, the two big planemakers turned out a record 1,011 airliners between them. But for every plane they delivered, they won more than two fresh orders (net of cancellations), so the queue got longer. On January 25th Boeing won its largest-ever order from Europe: Norwegian Air Shuttle is to buy 122 planes worth $11.4 billion at list prices.

The lion’s share of 2011’s advance orders were for the A320neo, a re-engined version of Airbus’s short-haul airliner, which should enter service in 2015. This year the plane most in demand looks to be the 737MAX, a re-engined version of Boeing’s short-haul plane, deliveries of which are due to start in 2017.

At Boeing’s Renton factory near Seattle the existing version of the 737 is now being turned out at a record rate of 35 a month, after a recent speeding-up of the two assembly lines. At the front of assembly line number one, a plane destined for flydubai, an airline that can’t afford capital letters, is ready to roll. Behind it is the latest addition to Ryanair’s huge fleet of 737s, which has just had its engines fitted. Next, a Korean Air plane which is about to receive rows of seats; then an Azerbaijan Airlines jet, its toilet cubicles lined up alongside ready for installation. The plan is to increase the production rate further, to 42 a month by 2014. Fortunately, there is space to squeeze a third assembly line into the giant hangar.

Likewise, at Boeing’s Everett factory to the north of Seattle and another plant in South Carolina, plans are afoot to churn out more of the company’s bigger jets, including the 787. But the 40-odd unfinished Dreamliners scattered around the Everett campus and elsewhere are a reminder of how such attempts to ramp up production can go wrong. Having first suffered from a worldwide shortage of the fasteners that hold bits of the plane together, the 787 was then held back further by other mishaps, including faulty horizontal stabilisers sent by an Italian supplier. Boeing is struggling to correct the problems on the unfinished planes even as it strives to get its production lines turning out ten fault-free 787s a month by the end of next year.

The head of Boeing’s commercial-airliner division, Jim Albaugh, admits that with hindsight too much of the Dreamliner programme was contracted out to other firms. Some work has been brought back in-house so that it can be more closely supervised. The planemaker has also set up a “war room” that constantly monitors the world’s supply of aircraft parts and raw materials. It has signed a long-term deal with a Russian metals firm to ensure a steady supply of crucial components made from titanium. And it has hired hundreds of “examiners” to visit suppliers, to check that they are building up production to meet Boeing’s increasing needs and chivvy them along if not.

Boeing’s assembly plants are the final stage in a long and hugely complex global supply chain. It has about 1,200 “tier-one” suppliers, which provide parts directly to the planemaker from 5,400 factories in 40 countries. These in turn are fed by thousands more “tier-two” suppliers, which themselves receive parts from countless others. Beverly Wyse, who oversees production of the 737, admits that it has sometimes been a job to persuade all these suppliers to invest enough to meet future demand. To do so, Boeing has had to learn to be more open with them about its production plans, and a bit less paranoid about whether such information might reach the ears of its competitors.

Even with all these new measures in place, Boeing’s plans to boost production of the Dreamliner remain “hugely ambitious”, reckons Richard Aboulafia of Teal Group, an aviation consultancy. He wonders if the planemaker is serious about its target of making ten of them a month, or whether it is just bandying about an unrealistic figure to rev up its suppliers. “Not true,” retorts Mr Albaugh. Boeing has every intention of reaching the goal, he says.

Fasten your seat belts

Still, with the world economy looking wobbly and the euro-area crisis far from over, might suppliers not have good reason to fear that the recent surge in aircraft orders could go into reverse thrust? Myles Walton, an aerospace analyst at Deutsche Bank, believes that both Boeing and Airbus have quietly begun double-booking some of their delivery slots, in case a customer collapses. He reckons they have done enough of this to cope with the worst imaginable recession in Europe.

Perhaps the biggest risk on the horizon would be a sustained surge in the price of oil, which could send airlines into a tailspin of losses and bankruptcy. So far, though, the chief worry for Boeing and its main rival is how to get their products flying out of the door faster.

Source: http://www.economist.com/node/21543555

Can Big Oil Repeat Its Big Year?

Even today, $1.67 trillion is a lot of money. That is the amount wiped off the combined market capitalization of the top 50 energy companies between the end of 2007 and the end of 2011. Breaking it down offers big clues on Big Oil's prospects for 2012.

Every year, PFC Energy, a Washington, D.C.-based consultancy, ranks the top 50 listed energy companies in the world by market value. The latest, due Monday, has a surprise. The biggest gainers in 2011 were the dinosaurs of oil and gas: the supermajors. Their collective value increased by 8%, compared with a 7% decline for the PFC Energy 50 overall. It is only the second time they have led the field in the ranking's 13-year history.

Conventional wisdom holds this shouldn't be the case. Faith in the supermajors—Exxon Mobil, Chevron, Royal Dutch Shell, BP, ConocoPhillips and Total—has waned as state-backed rivals like PetroChina have emerged and smaller competitors have opened up new frontiers like U.S. shale. Seemingly too big to grow but too small to offset the power of petro-states, the supermajors have been priced for decline.

Why did investors fall in love with them again in 2011? First and foremost: security. The S&P 500 ended 2011 down slightly after wild swings. In choppy markets, scale and cash payouts provide comfort. And the supermajors, with a collective value of $1.2 trillion at year end, provide it in spades. The three U.S. ones alone paid out 9% of all S&P 500 dividends and buybacks in the year ended September 2011, according to data from Standard & Poor's and Capital IQ.



So how about that missing $1.67 trillion? It is gone despite the average price of Brent crude being 53% higher in 2011 than in 2007 (and 13% higher than in 2008, year of the super-spike). About half of that market value was lost by listed state-controlled national oil companies, or NOCs, like PetroChina. State support has its advantages, but it also means NOCs serve two masters: markets and mandarins. That makes them riskier investments.

While the NOCs in the ranking lost 44% of their value between 2007 and 2011, the supermajors declined by just 22%.

But it isn't just safety that helped the supermajors lead the charge in 2011. Chevron, Exxon and Shell likely all delivered cash flow per share growth of 30% in 2011, well ahead of the traditional growth stocks of the exploration and production sector, according to Credit Suisse.

Ed Westlake, analyst at Credit Suisse, says the oil majors are more sensitive to oil prices than many investors think. In part, that is because much of their global natural-gas production is sold at prices linked to oil, rather than at the depressed, de-linked levels that prevail in the U.S.

This year, the supermajors are forecast to make $67 billion in free cash flow, according to FactSet Research Systems. That is down slightly from 2011's expectation but still equates to a healthy free cash flow yield of 5.6%.

Goldman Sachs points out, however, that unlike a year ago, supermajor stocks enter 2012 trading at a slight premium to their smaller integrated oil peers. That, coupled with the fact that 2011's cash-flow surge is unlikely to be repeated, means some investors' gains may be redeployed into other energy stocks.

It seems unlikely that the supermajors will register the biggest gains in the PFC Energy 50 2012. That doesn't make them a bad investment. With markets still unsettled—Europe, in particular, remains unpredictable—Big Oil will likely remain a safe haven. Stocks don't always have to be the biggest winners to be reliable repositories of value.

Source: http://online.wsj.com/article/SB10001424052970203750404577173191238523960.html?mod=WSJ_Heard_LEFTSecondNews

Oil refiners: Europe runs out of gas

Vanishing operating margins and chronic overcapacity. No, not the airline industry. Think Europe's oil refineries. Pe-troplus, a Swiss refining company, is dangerously close to collapse .

Nine European refineries have closed since mid-2008 and 2.6m barrels a day of refining capacity has been removed from advanced economies since the global financial crisis, according to the International Energy Agency. Moreover, operating margins were negative in November. There could be more casualties ahead.

Petroplus is a marginal operator, lacking the scale and financial heft to modernise plant and wring greater efficiencies. Not surprisingly, perhaps, its near-death experience has been hastened by its creditors , which have frozen credit lines as the company struggles to meet even amended covenants. The credit freeze has forced it to begin shutting down three of its five refineries. With high fixed costs, it faces an immediate liquidity problem if credit lines are not restored.

The question is whether anything can be salvaged from the wreck for shareholders. Petroplus shares have collapsed by 90 per cent in a year, and by fully 99 per cent since their July 2007 high. Any remaining value depends on whether the refineries can be sold.
Closing down its capacity of 667,000 barrels a day permanently would ease the plight of other marginal operators. But political considerations could make that next to impossible. There are buyers for Europe's more efficient plants - Essar Energy paid Shell $350m in 2011 for the UK's Stanlow facility , for example. But only two Petroplus plants - one each in Germany and the UK - have the sort of capacity and margin potential to woo buyers.

Europe's refiners are too exposed to low-value fuel oil and petrol and not enough to high-margin products such as jet fuel and diesel. Unless overcapacity is addressed, that will not change. Petroplus is a timely warning to a complacent industry.

Source: http://www.ft.com/cms/s/3/48728056-3880-11e1-9ae1-00144feabdc0.html

Price of crude: Reversal of fortune

“All politics is local,” the Washington adage goes. As oil markets proved this year, ultimately all commodities are local too.

The price of crude is a headline financial indicator. But in 2011, commentators and investors were confronted by an almost philosophical problem: what is the price of crude?

The world’s two big oil benchmarks which, historically, traded in parallel, slowly diverged.

Brent, from the North Sea, was $115 a barrel in mid-October. A barrel of West Texas Intermediate in the US was $87 at the same time – a $28 gap.

One price told a very different story about the global economy from the other. The price gap also muddied the thesis of investors who had bet money on commodities as a way to harness global growth and hedge against inflation. Oil was not following the script.

Reasons for Brent’s relative strength included the lingering impact of lower output from revolutionary Libya, a big crude supplier to Europe.

In the US, WTI’s relative weakness was partly explained by poor demand for motor fuel in an economy still not fully recovered from financial crisis.

But the best explanation for the wide spread is very local.

Thanks to resurgent production in the US and Canada, crude was flowing into the delivery point for WTI futures at Cushing, Oklahoma faster than it could flow out.

This led to concerns a glut would develop, depressing the WTI price.

Analysts were torn over how long this difference could last, with some projecting it would widen to $50 a barrel and others arguing traders would figure out a way to move cheap WTI-linked crude closer to the price of Brent.

On November 16, the latter seemed vindicated when Enbridge, a Canadian pipeline company, said it would purchase 50 per cent of the Seaway pipeline running into Cushing and reverse it to run south to the Gulf of Mexico. The spread quickly narrowed to about $10.

“Crude oil is extraordinarily efficient, internationally. Gaps that exist, exist for very short periods of time,” says James Dyer, chief executive at Blueknight Energy Partners and a senior executive at Vitol, the world’s largest independent oil trader. Blueknight owns crude oil storage tanks in Cushing.

Enbridge and its joint venture partner, Enterprise Products Partners, said the reversed line would carry 150,000 barrels a day by the middle of 2012. By early 2013, capacity would rise to 400,000 b/d.

JPMorgan, the investment bank, estimates that with the reversal, WTI crude’s discount to Brent will shrink to $5 a barrel by the end of 2012, and just a few dollars by the end of 2013.

But some estimates show the volumes Seaway will carry are far less than the amount set to pour into Cushing in coming years, as production bounces higher in places such as the Permian Basin in west Texas, the Bakken formation in North Dakota and Canada’s oil sands.

Other projects to avert a glut at Cushing, which held a record 42m barrels of stock last April, include unit trains carrying oil directly from North Dakota to the Gulf of Mexico, barges floating crude down the Mississippi River and plans by Magellan Midstream Partners to reverse a pipeline to funnel 135,000 b/d of crude from west Texas to the Gulf coast.

“You can’t just assume that oil is oil,” says David Greely, oil analyst at Goldman Sachs, the investment bank. “Location matters, and you need to pay attention to what is happening to the infrastructure underlying the individual markets.”

Source: http://www.ft.com/intl/cms/s/0/6032249a-2704-11e1-b7ec-00144feabdc0.html#axzz1i2iwpKa6

Another oil shock?

It’s been a while since the world has been truly preoccupied with the threat of sustained high oil prices. The global economic recovery has been muted, and a double-dip recession remains possible.

But that dour prospect shouldn’t make executives sanguine about the risk of another oil shock. Emerging markets are still in the midst of a historic transition toward greater energy consumption. When global economic performance becomes more robust, oil demand is likely to grow faster than supply capacity can. As that happens, at some point before too long supply and demand could collide—gently or ferociously.

The case for the benign scenario rests on a steady evolution away from oil consumption in areas such as transportation, chemical production, power, and home heating. Moves by many major economies to impose tougher automotive fuel efficiency standards are a step in this direction. However, fully achieving the needed transition will take more stringent regulation, such as the abolition of fuel subsidies in oil-producing countries, Asia, and elsewhere, as well as widespread consumer behavior changes. And historically, governments, companies, and consumers have been disinclined to tackle tough policy choices or make big changes until their backs are against the wall.

This inertia suggests another scenario—one that’s sufficiently plausible and underappreciated that we think it’s worth exploring: the prospect that within this decade, the world could experience a period of significant volatility, with oil prices leaping upward and oscillating between $125 and $175 a barrel (or higher) for some time. The resulting economic pain would be significant. Economic modeling by our colleagues suggests that by 2020, global GDP would be about $1.5 trillion smaller than expected, if oil prices spiked and stayed high for several years.

But like any difficult transition, this one also would create major opportunities—for consumers of energy to differentiate their cost structures from competitors that aren’t prepared and for a host of energy innovators to create substitutes for oil and tap into new sources of supply. Furthermore, if we endured a period of high and volatile prices that lasted for two or three years, by 2020 or so oil could face real competition from other energy sources.

To paint a clearer picture for senior executives of what such a world would mean for them—and how to prepare now—we asked several colleagues to join us in a thought experiment about the impact of a prolonged oil price spike. Russell Hensley and Andreas Zielke, from McKinsey’s automotive practice, explain how intensified regulation already is leading a transition toward greater fuel economy, as well as the potential for higher oil prices to reinforce that momentum (see sidebar “The automotive sector’s road to greater fuel efficiency”). Jonathan Ablett, Lowell Bryan, and Sven Smit, from McKinsey’s strategy practice, assess the global economic impact of an oil price spike and the strategic implications of a slower-growth environment (see sidebar “Anticipating economic headwinds”). Finally, Knut Alicke and Tobias Meyer, from McKinsey’s operations practice, describe energy-efficient supply chain strategies that some companies are already undertaking (see sidebar “Building a supply chain that can withstand high oil prices”).


A delicate balance

The world is very far from running out of oil. By most estimates, at least a trillion barrels oconventional oil still reside beneath the earth’s surface, not to mention several trillion more barrels of oil or gas that could be extracted through unconventional sources, such as oil sands.

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	Building a supply chain that can withstand high oil prices Opportunities abound to boost supply chain efficiency. Most are in the money today, and will become even more attractive if oil prices rise. Knut Alicke and Tobias Meyer We don’t need to look very hard for a live case study of what happens to global supply chains when oil prices spike. Just three years ago, when they shot up to $125 and beyond, it became painfully obvious to many companies that their supply chains were not viable at those levels. Research we conducted at that time indicated that even if oil prices were as low as $40 a barrel, it would still make economic sense for companies to take a variety of actions that collectively would reduce the energy intensity of global supply chains by almost one-fourth. Energy intensity could be reduced by more than one-third if oil prices stayed above $100 a barrel for a prolonged period (exhibit). The potential would be even greater at higher prices. Here are some of the opportunities that farsighted companies are beginning to act on: Utilizing space-saving packages. A retailer and a wholesaler partnered to create a new, stackable format for milk containers. As a result, they no longer need traditional shipping crates for truck transport, thus freeing up additional space for other cargo and avoiding the need to haul back the empty crates. Operating larger ships and trucks. Vale, the Brazil-based miner, took delivery this year of its first new ultralarge ore carrier, with 400,000 deadweight tons of capacity—more than twice that of today’s standard vessel on the most important trade routes—to ship iron ore from Brazil to China. Scale is important because doubling the capacity of a transport asset typically increases its energy efficiency by one-fourth. The same goes for trucks too. In emerging markets, where average truck size is less than half that in OECD1 countries, partly because of poorer infrastructure and smaller retail outlets, every percentage point of average truck size would reduce fuel consumption per unit of capacity by about 0.4 to 0.6 points. Combining new technologies. Maersk, the Danish container liner, used most of the available technological advances when it placed orders for its new 400-meter-long vessels, each with space for 18,000 20-foot container units. These vessels set a new benchmark in maritime energy efficiency by virtue of their size, slower speed, design improvements, and a waste heat–recovery system that reduces the engine’s fuel consumption. Switching to alternative fuels. A road transport company recently estimated that it would save €15,000 a year per truck by converting its small fleet to run on vegetable oil rather than traditional diesel fuel. Because of North America’s recent flood of supply of natural gas, companies could also convert fleets to run on liquified natural gas (LNG) instead of diesel. Practicing smarter driving. Examining data collected by onboard computers, a logistics company found significant differences in the driving patterns and fuel consumption of drivers. Shifting to best practice could shave 10 percent off its $4 million annual fuel bill, with onboard computers helping employees drive more economically. Regulators also have a role to play. In the United States, the fuel efficiency gain of lowering the cap on truck speeds on highways could be 7 to 10 percent. Truck speeds are already capped to lower levels in Europe. But there are still opportunities—for instance, allowing longer (and potentially heavier) truck/trailer combinations in Europe’s road transport market could reduce its use of diesel by around 15 percent. These examples are just the tip of the iceberg. Further existing technological opportunities—such as trucks with better aerodynamics and ocean vessels with new, friction-reducing hull coatings—are economical at the $100-a-barrel prices that have prevailed recently. High prices also should induce companies to cut the distance products travel. Moving final assembly into regions of demand would make it sensible to manufacture less valuable components there, such as primary packaging, manuals, or power cables for electric goods. An alternative is to ship products with low value density by slow and more energy efficient modes of transport. Optimizing the energy efficiency of a supply chain’s production process, location footprint, transportation, and inventory is a complex task made harder by inevitable tensions between the supply chain group and functions such as sales, service, and product development. There are thorny trade-offs—for example, between service levels and the lower speed of energy-efficient transport. Part of the answer will be creating nimbler supply chains—for example, by using slower, more energy-efficient modes (such as ocean freight) for the base load and reserving the faster, less energy-efficient modes (such as air freight) for peak demand. CEOs also will need to facilitate meaningful discussion of important cross-functional supply chain issues so that executives can collaborate to uphold a company’s best interests.

More relevant for prices, though, is how much spare oil production capacity exists in the world. Three million or four million barrels a day typically represents a comfortable buffer when the global economy is healthy. If that buffer shrinks, and markets expect strong demand growth to continue, prices can rise—sometimes dramatically. That’s what happened prior to the 2008–09 financial crisis as surging emerging-market demand strained production capacity and prices approached $150 a barrel. This fly-up was short lived because the ensuing deep recession wiped out between three million and four million barrels a day of demand, sending oil prices sharply down.

During the sluggish recovery that followed, the global supply cushion shrank again, punctuated in the first half of 2011 by Libya’s civil war, which disrupted supplies from that country and knocked off a million barrels a day of global capacity. That tightness set the stage for price fly-ups to $120 a barrel in the first half of this year and underscores the strength of the pre-2008 fundamentals.

Going forward, barring prolonged economic stagnation, demand growth for liquids¹ is likely to chug ahead at around 1.5 percent a year. The pace would be even faster without the steady improvements in energy efficiency that we and other energy analysts foresee, particularly for cars and trucks as a result of technology improvements and stiffening regulatory standards that are already on the books.

Could supply growth accelerate to keep pace? Many industry analysts and our own supply model suggest that it won’t be easy. Despite high oil prices for much of the past decade and surging investment outlays by many major private and national oil companies alike, capacity has risen by only slightly more than 1 percent a year during that time. The logistics, supply systems, and political alignment needed to extract new oil supplies make that a complex, expensive, and time-consuming business. And coaxing more output out of existing oil fields, which typically have high production-decline rates, also is costly and challenging.

Our current projections suggest that in a “business as usual” scenario,² the world could reach a realistic supply capacity of around 100 million barrels a day by 2020, up from 91 million or 92 million today. That, however, would barely suffice to meet the roughly 100 million barrels of liquids the world would consume each day in such a scenario, up from 88 million or 89 million today.

When supply and demand collide

Simple math suggests that at some point, something has to give. And when it does, the world will have to start taking steps away from today’s oil dependence. The question is how rapid and volatile that transition will be.

The case for a gentle collision

This critical shift could happen in an orderly fashion, without price spikes, if governments, companies, and consumers worked together to accelerate the adoption of measures that reduce demand. Indeed, a common denominator of current forecasts by industry analysts (including ourselves) is a gradual transition in most regions toward lower oil intensity in transportation, power, and residential heating. But according to our analysis, it would take more than current trends in oil conservation (spurred by existing legislation) for supply to meet demand if robust economic growth returned.

A few examples illustrate the scale and scope of the task facing the world if we are to realize a gentle transition. Governments would need to raise auto fuel efficiency standards further, and consumers would need to place greater emphasis on fuel economy when they bought new cars. Policy makers in several developing countries would need to abolish fuel subsidies so that consumers felt the real price of oil. Around the world, we’d need to see deeper reductions in the use of oil for heating, power generation, and chemical manufacturing. Some transport by ships and heavy trucks would need to start shifting toward more reliance on natural gas as a fuel.

Changes like these could push oil supply and demand roughly into balance. However, they would require new policies and significant changes in how consumers and businesses behave. What’s more, they would need to start now because it will take years before the changes required to constrain oil consumption begin to take effect. If we do not succeed in implementing these changes in a farsighted way, the system faces a risk of falling out of balance.

Why the adjustment could be violent

That brings us to a second scenario: it’s possible to imagine global supply and demand for oil colliding faster, and more ferociously, resulting in a price spike as the global capacity buffer melted away. As we’ve said, anticipated economic growth alone could cause demand to expand faster than supply. Another possible trigger: supply disruption, which does happen from time to time. The possibilities include an exceptionally severe hurricane in the Gulf of Mexico, violence in the Niger Delta, instability in Venezuela, and further tension in the Middle East.

If this new price spike took place, it could have a more significant impact on global consumption patterns than most executives expect (for audio commentary by Occo Roelofsen, see the interactive, “How might a sustained oil price spike affect demand?”). For starters, it would hit global growth, which in turn would immediately knock down oil demand. In addition, there would be some rapid behavioral effects, such as a reduction in car, air, and sea travel. If the spike lasted longer, it could cause several more structural shifts, such as prompting individuals to use different modes of transport or even to look for work closer to home, encouraging companies to reverse offshoring trends and bring supply chains closer to home, accelerating the substitution of videoconferences for air travel, and pushing the freight transport industry to adopt less oil-intensive modes.

How might a sustained oil price spike affect demand?

Occo Roelofsen discusses demand during a sustained oil price spike, from both a general and sector-specific perspective.

Launch Interactive

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Because such shifts would take time, a high-price environment could last for years, not months, accelerating several other ongoing trends that, when combined, could lead to even further demand reductions. In other words, a sustained price spike could scare consumers, companies, and governments into more drastic responses—accelerating the transition to a less oil-dependent economy. A price spike of one to three years could be long enough to make governments raise standards for fuel efficiency at an accelerated pace and prompt automakers, reacting to regulatory changes, to modify their product-development road maps. Ultimately, all this would lead to more rapid efficiency gains and potentially to faster electric-vehicle penetration.

A prolonged price spike also could prompt investments in infrastructure needed to support the use of electric vehicles or other alternatives (such as natural gas and hydrogen) to traditional fuel sources. Such investments could have an impact on oil demand for trucking, light vehicles, and shipping. What’s more, very high oil prices would intensify energy efficiency efforts up and down the supply chain and reduce the amount of plastics used in packaging, thus shrinking demand for oil in chemicals. Additional government action, in the form of either more stringent regulation on the use of plastics or subsidized financing that reduced the up-front cost to consumers of switching away from fuel oil in residential heating, could play an important role in this transition.

All along the way, of course, these reactions, plus slower global growth, would do their part to exert some downward pressure on oil prices. Expanded supply would also play a role. From now to 2020, OPEC³ could increase its capacity by, say, two million barrels a day above currently assumed increases, and new investments in mature assets could slow decline rates, leading to an additional one million to two million barrels of daily production. Furthermore, additional investments in unconventional oil sources, such as oil sands, could increase supply by, say, one million to two million barrels a day. Biofuels, too, would have room to grow. But given the time it would take to pursue some of the available opportunities—and the danger that they could quickly become uneconomic once oil prices fell—the supply response is likely to be slower and more muted than that of demand.

In the end, once all the efficiency gains and supply expansions described above kicked in, the world could again wind up in balance and with significant excess capacity, so that eventually—perhaps by 2020, perhaps later—prices fell below the $80 to $100 range. Until then, however, given how slowly many of the demand changes would unfold, it’s only prudent to imagine the possibility that the world could experience a prolonged period of both significant volatility and generally much higher prices.

Preparing for the unexpected

If the shock scenario outlined above unfolded, sustained high oil prices would challenge the top and bottom lines of many companies. However, high prices also could create opportunities for companies to differentiate themselves from competitors whose cost structures and operating approaches were ill suited to the new environment. And for companies on the front lines of the resource productivity revolution, a prolonged oil price increase would be beneficial. Providers of a range of new technologies—from car batteries for electric vehicles, to horizontal drilling and other tools for unconventional oil extraction, to biofuel production techniques, to electricity cogeneration equipment for manufacturers—would see their businesses grow, faster, than they would in a world of lower oil prices.

In many cases, these companies would be supplying or partnering with more established firms: oil companies in need of unconventional extraction technologies, auto manufacturers trying to create the winning vehicle of the future, and chemical companies hoping to take advantage of new feedstock sources, for example. From a strategic perspective, the interesting question is who would grab the most profitable positions in the new energy ecosystem.

No less fascinating are the managerial implications of the second-order and feedback effects that would occur as this ferocious collision played itself out. For example, our analysis suggests that even if prices subsequently fell, companies that pursued strategies for reducing their dependence on oil would be unlikely to regret it. One reason is that many strategies are already “in the money” at today’s prices. If prices got high enough, they would concentrate the attention of consumers, businesses, and governments sufficiently to promote many positive-return investments that haven’t been implemented so far, because of behavioral inertia. This development would accelerate the changes in our capital stock, while leaving them economically viable even if prices fell again.

Furthermore, many technologies could become significantly cheaper as demand for them increased and their providers went down learning curves. Examples include batteries for vehicles, highly efficient internal-combustion engines, and certain biofuel technologies, such as those that are cellulosic or perhaps even based on algae. In a high-price environment, more capital would flow into these technologies, enabling them to scale up. The time needed for them to become economically attractive would fall by five or even ten years compared with the time frame if oil prices stayed at lower levels, potentially making these technologies economically viable even if oil prices subsequently fell.

Indeed, a striking and often-underestimated feature of energy price shocks is the nonlinearity of their impact. Take electric vehicles. The market for car batteries would likely be about five or ten times larger if oil prices stayed for a considerable period at $150 a barrel than it would be at $100 a barrel. Few corporate-planning processes, however, place sufficient emphasis on extremes like this—even though these are precisely the scenarios that produce many of the most interesting opportunities and powerful threats for a business. Building corporate processes and skills that enable thoughtful reflection on a wider, more volatile range of outcomes could be a significant competitive differentiator in the years to come.

In the long run, these structural changes could well be a positive development for the world—resulting in more predictable and sustainable energy supplies and prices. But navigating the transition would be challenging and would reward the well prepared. The time is now for companies to start planning for the possibility of another price shock and a powerful market response.

Source: https://www.mckinseyquarterly.com/Another_oil_shock_2873

Latin moves in China’s rush for oil

In a few weeks’ time, two oil rigs off the coast of Brazil will move smoothly into production, pumping thousands of barrels of oil a day out of the Peregrino oilfield in the Campos basin. They would be unremarkable if it were not for the story that lies behind the field and its investors. Owned by Statoil of Norway, another investor in the project is Sinochem, a Chinese state-owned energy and trading group, which won a bid for 40 per cent of the field in one of the most hotly contested bidding rounds in the industry last year.

Sinochem paid $3.1bn for that stake, sealing the deal last June. It is not unusual for Chinese oil companies to make big acquisitions these days – last year they spent more than $30bn on overseas mergers and acquisitions, accounting for roughly one-fifth of global deal activity in the sector.

But the Peregrino story is unique because the process pitted three of China’s largest oil companies against each other in heated rounds of bidding – a scenario that is a harbinger of Chinese oil majors expanding their hunt for assets overseas.

It was not long ago that all of the country’s outward-bound investments were carefully choreographed by Beijing. Big state-owned enterprises would lobby for months to convince their regulators to approve investments overseas. That system had one major advantage: it prevented Chinese oil companies from bidding against each other for overseas assets, since the regulator would not usually grant approval for two companies to bid for the same thing.

However, that changed in 2007-08 when regulators in Beijing started taking a slightly more hands-off approach. The result is that Chinese companies have started competing for assets overseas with each other, not only with their western peers.

One of the clearest examples of this was the bid contest for the 40 per cent stake in the Peregrino oilfield. The block was contested by no less than three Chinese state-owned oil companies: Sinochem, which grew out of China’s state oil trading arm; Sinopec, which historically has run most of China’s refineries; and Cnooc, which specialises in offshore oil production.

“[In] the Peregrino auction ... Sinopec and Sinochem were extremely competitive, aggressive. Cnooc was there but wasn’t quite as aggressive,” says one person involved in the deal.

The hot bidding meant the companies’ strategic approach to the deal became a key factor in determining who won. According to two people who worked on the deal, Sinopec offered the best financial terms, but insisted on standard conditionality and due diligence. Sinochem, meanwhile, made an unconditional bid, according to one insider – an unusual gamble for the industry but certainly an attractive proposition for the seller.

Statoil also seems to have been drawn by the prospect of working with Sinochem in the future. “I am pleased that we also have agreed to sign an MoU [memorandum of understanding] to jointly investigate further opportunities in Brazil and elsewhere,” said Helge Lund, chief executive of Statoil, when the deal was announced.

Sinochem is relatively new to China’s overseas oil rush. The company’s $3.1bn spend on the Peregrino stake was nearly twice as much as the total amount it had previously spent on overseas oil projects. Although it is a large conglomerate, with roughly $15bn in assets at the end of 2009, it has traditionally been focused on importing oil and trading oil and chemicals, including fertilisers.

Sinochem made its first overseas energy acquisition just eight years ago, in 2003. But it did not take long for the company to make a mark in the global oil M&A field. Most recently, it explored the possibility of launching a counterbid for Anglo-Australian mining group BHP Billiton’s $39bn hostile bid for PotashCorp, the potash mining company based in Saskatchewan, Canada. Sinochem eventually decided not to pursue the deal – partly because of opposition from Chinese regulators concerned about overpaying for the assets.

In many ways Sinochem is typical of the Chinese companies making waves in global M&A. They have been extremely fast to move into the sector they are interested in, and those who have worked with them describe Sinochem’s M&A team as savvy and sophisticated.

One particular coup was Sinochem’s decision to walk away from a potential acquisition of Nufarm, an Australian agricultural company, in 2009. Today, Nufarm shares are trading at a less than half of what Sinochem was offering at the time, before the deal fell through.

That is not to say that there has not been a learning curve. As with any companies doing overseas M&A for the first time, Chinese resources companies have been learning the ropes. Sometimes that has been painful, as with Cnooc’s failed bid for Unocal, the US oil group, in 2005, which was derailed by loud political opposition out of the US. But China’s state-owned companies have largely been remarkably fast learners.

Investment shift

China’s overseas investments in oil and gas have become an important driver of the industry. Last year, Chinese energy companies spent more than $30bn on overseas energy deals, about one-fifth of global deal activity. To give a sense of the pace of the change, consider that in 2008, Chinese energy deals accounted for just 4 per cent of the global dealbook.

While this shift towards overseas investment has been initiated at the highest levels of government as part of the “go out” strategy under which state-owned enterprises are encouraged to venture overseas, it is also driven by commercial considerations.

“In general, the Chinese can take a more long-term view. They are probably on balance less payback-focused [than other oil firms] and more focused on improving the number of barrels produced,” one oil and gas banker observes. “This makes them very competitive bidders.”

Some industry experts say that Chinese oil companies have a history of overpaying for assets, although a recent report from the International Energy Agency refutes this claim.

The country’s large oil companies have a mandate to boost production, and their ownership structures usually make shareholder value a secondary consideration (one exception is Cnooc, which is structured differently from Sinopec or CNPC, China’s largest oil and gas producer). This structure allows companies to take longer-term bets on oil than their western peers, because they do not have the pressure to turn around their investments as quickly.

Many state-owned oil companies cut their teeth on assets that were not hotly contested by global oil competitors, sometimes in investments in Africa or the Middle East in countries deemed too risky or unpalatable for most energy firms. This is rapidly changing, though – as the Peregrino oilfield saga shows.

Source: http://www.ft.com/intl/cms/s/2/05230786-5ec8-11e0-8e7d-00144feab49a.html#axzz1ZTnHKNnT

Vegetable oil: What’s cooking?

OIL markets are full of uncertainty. Asian demand is booming and doubts abound over the ability of supply to match the world’s appetite. What goes for crude oil also applies to the stuff squeezed out of vegetable matter.

The price of stir-frying and dressing a salad has rarely been higher. Over the past decade the price of vegetable oils has all but quadrupled. Like other commodities, prices hit records in 2008. The subsequent slump is now forgotten: prices are back close to the peaks. Glencore, the world’s biggest commodity trader, may be about to confirm the industry’s allure: rumours are flying that it is mulling an investment in KS Oils, an Indian edible-oil firm.

Kona Haque of Macquarie, an Australian bank, points to two structural factors behind oil’s sizzle: China and biodiesels. A planet with more mouths to feed and deeper pockets has led to rapid growth in consumption of vegetable oils as well as grains and meat. And although the rapid surge in demand for oils in China and the rest of Asia is slowing there is still plenty of scope for more growth.

In the past few years a new source of demand has emerged for vegetable oils. Biodiesel production has rapidly accelerated and now consumes over a tenth of the global vegetable-oil crop. Depending on the crude-oil price and governments’ enthusiasm for mandating biofuels it could account for as much as a fifth by 2020, according to Peter Thoenes of the UN Food and Agriculture Organisation.

The effect of growing demand for the two main types of vegetable oil, palm and soya (see chart), is amplified by supply problems. In the case of soya, competition for land is the main concern. Farmers in America, the world’s top exporter, and Brazil, in second place, are switching to maize as sky-high prices make it more attractive.

Palm oil, also used to make soaps and cosmetics, comes almost exclusively from Indonesia and Malaysia. It suffers from even more acute supply problems. Already intensively cultivated and mechanised, there are few opportunities for farmers to increase output by improving yields on existing acreage. Developing and rolling out new higher-yielding strains is much easier and quicker for annual crops like wheat than for perennials such as palm trees that take time to mature and will bear fruit for many years.

Finding more land has unpalatable costs. Environmentalists point out that the spread of palm-oil plantations is the greatest threat to forests in Indonesia and Malaysia. In May Indonesia introduced a two-year moratorium on forest clearance in return for $1 billion, as part of a bilateral climate deal with Norway. But loopholes and exemptions mean that it may not slow down deforestation much. Like its crude counterpart, the march of the vegetable-oil business is not easily resisted.

Source: http://www.economist.com/node/21529085