Opinion Editorials, March 2017

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Oil Majors' Costs Have Risen 66% Since 2011 By Nick Cunningham Oil Price, Al-Jazeerah, CCUN, March , 2017

The oil majors reported poor earnings for the fourth quarter of last year, but many oil executives struck an optimistic tone about the road ahead. Oil prices have stabilized and the cost cutting measures implemented over the past three years should allow companies to turn a profit even though crude trades for about half of what it did back in 2014.

The collapse of oil prices forced the majors to slash spending on exploration, cut employees, defer projects, and look for efficiencies. That allowed them to successfully lower their breakeven price for oil projects. However, some of that could be temporary, with oilfield services companies now demanding higher prices for equipment and drilling jobs, in some cases upping prices by as much as 20 percent. The result could be an uptick in the cost of producing oil for the first time in a few years. Rystad Energy estimated the average shale project could see costs rise by $1.60 per barrel, rising to $36.50.

That does not seem like the end of the world. After all, those breakeven prices are still dramatically lower than what they were back in 2014. In fact, Reuters put together a series of charts depicting the fall in costs for shale production in different parts of the United States. Every major shale basin – the Eagle Ford, the Bakken, the Niobrara, and the Midland and Delaware basins in the Permian – have seen breakeven prices fall by as much as half since 2013. The slight uptick in costs expected in 2017 is a rounding error compared to the reductions over the past half-decade.

But that is just for shale drilling. The oil majors produce most of their oil outside of the shale patch, with much of their output coming from longer-lived projects in deepwater, for example. To be sure, some of the largest oil companies have made some progress in cutting costs over the past few years, but a new report casts doubt on the industry’s track record.

According to new research from Apex Consulting Ltd., the oil majors are still spending more to develop a barrel of oil equivalent than they were before the downturn in prices – in fact, much more. Apex put together a proprietary index that measures cost pressure for the “supermajors” – ExxonMobil, Royal Dutch Shell, Chevron, Eni, Total and ConocoPhillips. Dubbed the “Supermajors’ Cost Index,” Apex concludes that the supermajors spent 66 percent more on development costs in 2015 than they did in 2011, despite the widely-touted “efficiency gains” implemented during the worst of the market slump. It is important to note that this measures “development costs,” and not exploration or operational costs.

However, performances varied by company. Eni, for example, saw its development costs decline by 32 percent between 2011 and 2015, a notable achievement. Chevron and ExxonMobil also posted efficiency gains, although more modest figures than Eni. Chevron’s costs fell 6 percent and Exxon’s were down 5 percent over the five-year period.

At the other end of the spectrum is Royal Dutch Shell, which saw development costs quadruple. ConocoPhillips and BP fared only slightly better, with costs roughly doubling over the timeframe. As a whole, the development costs for the group of “supermajors” rose 66 percent to $18.39 per barrel.

After the collapse of oil prices in 2014, the cost index did decline. Oil producers squeezed their suppliers, streamlined operations, and improved drilling techniques. But costs still stood 66 percent higher than in 2011.

The index points to underlying structural increases in development costs for the broader industry.

At $18 per barrel, the cost figure would seem rather low. But it is important to note that this is just for “development costs,” which represent just over half of a company’s total cost. That figure excludes the cost of exploration as well as funding ongoing operations. So the “breakeven price” so often quoted in the media is actually quite a bit higher. BP, for example, recently admitted that its finances will not breakeven unless oil trades at roughly $60 per barrel.

The supermajors are in a tricky position. They are trying to cut back on spending in order to fix their finances and pay down the massive pile of debt that they have accumulated in the past few years. However, their reserves will decline if they fail to replace them. Exxon, for example, only replaced 67 percent of the oil it produced in 2015.

Moreover, as Apex Consulting notes, oilfield services might demand higher prices in the future as drilling activity picks up. Right now, offshore rigs are still underutilized, meaning that price inflation has yet to kick in.

In other words, the decline in costs post-2014 are, at least in part, cyclical. Costs will rise again as activity picks up unless oil producers work with their suppliers to address the underlying structural costs of oil production.

Link to original article: http://oilprice.com/Energy/Energy-General/Oil-Majors-Costs-Have-Risen-66-Since-2011.html

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Next Oil Rally? Futures Say Market Is Tightening

By Nick Cunningham

U.S. oil inventories are at record levels, but there are a few glimmers of hope that the glut could be starting to subside.

Storing crude oil for sale at a later date is no longer profitable, as the futures curve has flattened out in recent weeks, depriving traders of a strategy that has served them well over the past few years. The market “contango,” in which front-month oil contracts trade at a discount to oil futures six months or a year out, has all but vanished. The differential must be large enough to cover the cost of storage, and for many time spreads that is no longer the case. After three years of a steep contango, storing oil simply to take advantage of the time spreads is increasingly uneconomical.

One of the more expensive forms of storage is floating on tankers at sea, and because of the narrowing contango, floating storage is unprofitable today. Reuters reports that traders are beginning to unload crude from floating storage along the Gulf Coast. "Right now, traders aren't incentivized (to store)," Sandy Fielden, director of oil and products research at Morningstar, told Reuters in an interview. "It won't all stampede out of the gate, but inventory levels will come down. What will happen is that some of it will go to refineries, but a fair amount will be exported too."

Just as the rapid rise of floating storage in 2015 and 2016 was a sign of the deepening global supply imbalance, draining tankers of stored oil is an early sign that the supply glut is receding.

So far, it is only the most expensive storage facilities that are seeing drawdowns – the U.S. on the whole has seen crude stocks swell to record highs. But oil analysts argue that the surge in crude inventories is a symptom of stepped up imports booked at the end of 2016, when OPEC members pumped out huge volumes of crude just ahead of implementation of their deal to cut production. After a few weeks of transit time, the extra supply started showing up in U.S. storage data in January and February. In other words, the stock builds could be a temporary anomaly.

More recently, the time spreads for Brent futures also indicate increasing tightness in the market. John Kemp of Reuters notes that the spread between futures between April and May has sharply narrowed this month, meaning that the market is betting on a supply deficit as we move into the second quarter. The spreads for May-June and June-July are even smaller, trading at a few cents per barrel. This is a complicated way of saying that there isn’t a way to make money by buying oil, paying for storage, and selling it at a later date.

In a separate report, Reuters notes that inventories are also starting to drawdown in Asia, adding further evidence that the glut is not as bad as feared. As OPEC has throttled back on production, Asia is starting to see the impact. Reuters says that unusually large drawdowns took place across key oil hubs in Asia – 6.8 million barrels of oil were withdrawn from tanker storage off of Malaysia’s coast while Singapore saw a 4.1 million barrel decline and Indonesia’s storage fell by 1.2 million barrels.

"Dancing contango is now not a profitable thing to do, so we've sold out," an oil trading manager told Reuters. The trader no longer stores oil on tankers because of the disappearing contango.

The details of the contango and the oil futures market may seem complex and arcane, but the shift in time spreads is exactly what OPEC has been targeting with its supply cut. By cutting near-term supply, OPEC has succeeded in changing the economics of oil trading, forcing inventories to draw down. That could cause a short-term supply problem as oil is unloaded from storage, but in the long run OPEC needs to drain that excess supply from storage tanks around the world in order to spark higher prices.

Traders are more and more confident that the oil market will experience tighter conditions as we move into the second quarter, a bet that is reflected in both the time spreads and the exceptional buildup in bullish positions on crude oil. The oil price rally is not without its risks – very notable risks that have been covered in previous articles – but for now, the futures market is offering investors and traders some reasons for bullishness.

Link to original article: http://oilprice.com/Energy/Energy-General/Next-Oil-Rally-Futures-Say-Market-is-Tightening.html

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