More price drops predicted as the market is yet to recover
Oil prices could take some time to bounce back - and the rout is not over yet
The bottom is nearing, but the pain is really just beginning. The plunge in oil prices, which in mid-January were trading beneath $50 a barrel (/b), or about 60% lower than their summer 2014 peak, has shaken the industry and is already devastating upstream investment plans. Steep price drops are still plausible, especially in the first half of this year, because the market is oversupplied -- and Opec, true to its word, is not blinking. The group will not change its strategy, Suhail bin Mohammed al-Mazroui, the United Arab Emirates’ oil minister, said in mid-January. Opec is determined to deal with the “oversupply coming from shale oil”.
The depth of this commitment was plain, too, in Ali Naimi’s startling interview with Middle East Economic Survey in early January. With production costs of just $4-5/b, the kingdom was willing to wait until less efficient producers - North American unconventional drillers, Russia, Brazil -- surrendered market share, he said, even if Saudi Arabia had to borrow money and run a deficit. “If [the price] goes down, others will be harmed greatly before we feel any pain.” It was not in Opec’s interests to cut output, he reiterated, “whether [the price] goes down to $20/b, $40/b, $50/b, $60/b, it is irrelevant”.
With Saudi Arabia playing hardball, bulls have little to latch on - especially considering the spare capacity the kingdom could yet draw on to support its strategy. At 3 million barrels a day (b/d), that reserve supply “is a huge weight hanging over the oil market”, Citigroup analyst Seth Kleinman said in a recent note. “If Saudi Arabia is sincere about abandoning its role as the central bank of oil and letting the market fall where it may, there is no rationale for the kingdom keeping its large buffer of spare capacity.”
For now, extra Saudi supply need only remain a virtual threat. Opec’s output is rising anyway - in December, it climbed by 80,000 b/d to 30.48m b/d - and further big jumps in production are possible in the coming months.
Iraq will be one source of this. Its production hit 3.7m b/d in December, its highest level since 1979. The International Energy Agency (IEA) noted that the state’s oil marketing firm, Somo, had issued a preliminary schedule of exports for February of 3.3m b/d, its highest-ever allocation, implying another 360,000 b/d reaching the market compared with December. The falling oil price is an incentive to export more crude, so Baghdad can recoup through volume some of what it is losing in price. The agreement between the central government and the Kurds, meanwhile, could add another 120,000 b/d of exports through the north in January, before rising further in the months after.
Libyan and Iranian supply also hang over the market. Negotiations to end the civil war in Libya took place in mid-January and even small progress could help restore output, which is now beneath 300,000 b/d following the attack on Es Sider’s oil-storage facilities. Libyan sources told Petroleum Economist that export infrastructure at the port had not been damaged by the attack (which was on the tank farm that lies in clusters 5 km from the export terminal itself). So exports out of Es Sider could, technically at least, resume quickly. A deal between Iran and the international community is another bearish threat: lifting some sanctions on Iranian oil could bring up to 1m b/d of more supply onto the market.
Then there is North America. Despite the plunging price, output will still rise from Canada’s oil sands this year by up to 300,000 b/d, say Calgary analysts. South of the border, the true bellwether for the market, the news for the first half of the year is also bearish.
Further production growth in the US, the main target of Opec’s decision to let the market deflate, is not straightforward. The price drop, after all, has already sent rig counts sharply lower. In North Dakota, home to the Bakken, the number in operation dropped from 191 to 181 between October and December -- and in the first two weeks of January plunged by another 25, said Lynn Helms, the state’s director of mineral resources. Across the country, 209 rigs went off line between 5 December and mid-January, the sharpest six-week fall ever recorded by Baker Hughes, the oilfield services company that collected the data. This has created much media noise about the perils facing US supply.
But, for now, the rig count - which at 1,366 in mid-January remained historically high - doesn’t tell the whole story. In search of cash flow, drillers are eking out more efficiency - helped by falling rig rates, as units are idled at the least profitable wells -- and turning to the highest-yield plays. A backlog of several hundred uncompleted wells offers easy production gains, and cash flow, for less outlay than drilling new wells.
This will bring a spurt of production growth in the first half of 2015. The US’ Energy Information Administration (EIA) says output, at 9.16m b/d in December 2014, will rise to 9.47m b/d in May before falling back in the rest of the year. Then it will recover again, reaching 9.91m b/d by December 2016. Texas’s Permian basin, where output was 1.1m b/d in October, will be core to this growth, as its productivity continues to increase. So far, the balance of drilling in the basin has been weighted to vertical wells, meaning that as more horizontal drilling is deployed output will rise -- by up to 300%, says Ed Morse, head of commodities research at Citi.
If all this potential supply-side growth -- which includes also rising output from Russia, where production reached a post-Soviet high of 10.67m b/d in December — makes for a gloomy price picture, the short-term demand-side outlook is doing nothing to help, either.
There is little sign, yet, that the price crash is persuading consumers to use more oil than they were when prices were twice as high. The IEA’s most recent forecast said consumption in 2015 would rise by 900,000 b/d - still well beneath pre-2008 trend levels and unchanged from its earlier forecast. “Steep drops in crude prices are only providing a limited boost to [global] demand, as the price decline is itself at least partly demand-driven,” says the IEA. Despite a spurt in sales of gas-guzzlers in the US, demand in the rich world remain static.
That puts the onus on China and the developing world. The shift in the Chinese economy in recent years, from investment- to consumer-led growth, means that the large annual jumps in oil consumption from the country are not going to return. Even those parts of the consumer economy that are crucial to robust oil-demand growth are cooling. The IEA said passenger-car sales in November were up by 4.7% year-on-year, the weakest rate of increase in 18 months. Total Chinese demand was still growing at a “modest” 3% a year, while weaker car-sales data, bigger taxes on fuel products and a “more subdued macroeconomic outlook” mean demand in 2015 will rise by just 2.5%, the agency says.
For the market, this is complicated by China’s oil-storage strategy. The low price is giving the country an opportunity to fill its strategic stocks cheaply, swelling the number of cargoes it imports - a reaction to market weakness, not a sign of stronger real demand. The IEA calculated that China’s stock-building was equivalent to about 290,000 b/d of demand in November, a number it expects to rise further.
Elsewhere, falling GDP in oil-exporting countries like Russia or those in the Middle East may also dampen oil consumption. Subsidies made fuel prices in the Middle East cheap before the crash. So the fall in the cost of crude won’t easily translate into more oil spending. It will, though, bring sharply lower revenues for governments that are often the largest employer and generator of investment. As the construction sector slows, for example, marginal demand for oil will too. Indeed, this kind of multiplier may even affect oil demand in countries like the US and Canada, where humming upstream activity in Alberta, North Dakota, Texas and other regions has itself been a source of petroleum consumption. Fewer workers driving fewer trucks to fewer well-pads will have some kind of marginal impact on demand.
All of this leaves the market vulnerable to further falls in the first half of 2015. Some support to the front end now comes from the shape of the curve, where contango - market jargon for spot prices being cheaper than oil to be delivered in future - is encouraging traders to buy oil for storage, hoping to sell for a profit later.
In mid-January, reports emerged that traders had chartered 16 very large crude carriers (VLCCs) to store crude oil - a move that could see at least 25m barrels of oil put into floating storage. Daily rates for VLCCs have soared on the back of the demand. Analysts say that capacity already chartered for floating storage is closing in on 60 million barrels. (In 2009, during the so-called “super-contango”, levels reached 100m barrels.) The IEA said in January that OECD commercial stocks built counter-seasonally by 12.5m barrels in December, taking inventories to their widest surplus against the five-year average since August 2010.
Changes in the storage market in recent years – partly a legacy of that earlier contango - are helping in this, especially for onshore storage. US commercial on-land oil storage capacity is now a third greater than it was in 2009. Reuters calculated in mid-January that only 150m of the country’s 439m barrels of shell storage capacity was occupied in October. That number will have grown significantly as traders pour crude into the tank farms - but lots of spare capacity still waits to be filled.
The availability of this onshore capacity in the US also helps to explain WTI’s relative strength against Brent, with the differential narrowing sharply in January (when WTI even periodically traded above Brent on the ICE). Storage levels in Europe are thought to be far closer to capacity, meaning traders are seeking cargoes of the US benchmark that can be stored closer to home, firming its price. Even some West African crude is reportedly being bought for delivery into US storage tanks.
Eventually the contango will end, or the curve won’t be steep enough to cover rising storage costs. If oil has nowhere to go, the price will have to fall even further, either to widen the contango again or force producers to keep their oil in the ground. When that happens, the floor will be visible - but the market will also be left with a large overhang of stored oil to clear before any significant price rises are possible. Burning off this excess could take the best part of a year.
That will prolong the pain for the industry - for companies and oil-exporting nations. A great retrenchment is now already underway. Faced with rising costs in the past few years, many of the majors had embarked on a phase of capital discipline even before the price started falling last summer. Now the jobs and upstream budgets are being knifed.
In the capital-intensive oil sands, firms are already slashing spending plans. Suncor announced a C$1bn ($836bn) cut in its 2015 budget. Canadian Natural Resources slashed $2.5bn from its budget for this year and deferred one of its projects. Shell has also announced big cuts in the oil sands, and in Qatar has abandoned a $6.5bn petrochemicals venture. Elsewhere, BP has begun pulling back in the North Sea, where Wood Mackenzie says prevailing oil prices now put $3.2bn worth of already sanctioned upstream investment at risk. Schlumberger plans to axe almost 8% of its workforce. Statoil has handed back three Greenland exploration licences. Independents across the industry are deferring upstream decisions as they wait for the price to recover.
The grim tidings will continue across the industry in the coming months. All told, capital expenditure will fall by 20-30%, making for greater cuts in investment than in the last major collapse in 1999, says Bernstein, a Wall Street research firm.
The industry’s retrenchment will create opportunities for consolidation, both in the upstream and the services sector. Cash-rich Chinese and Gulf firms could lead some of the acquisition activity. The contraction should also shrink costs. Rig rates, labour costs and other inputs are on their way down. Day rates for drill ships in the Gulf of Mexico have already plummeted. Goldman Sachs, a bank, predicts costs across the industry could fall by a fifth.
Governments will help with this - where they can. In the North Sea, the UK government has already commissioned the Oil and Gas Authority, an industry body, to “identify key risks to oil and gas production”. Oil firms are already lobbying for deep tax cuts to help the sector. Oil-rich states will have to make their upstreams more attractive to secure investment. The companies that survive the downturn will see their productivity rise.
But how long will the slump last? Despite the spurt in production growth still to come in the first half of 2015, the picture could change quickly in the second half, when tight oil’s high decline rates and the industry’s sharp cut-backs begin to be translated into much weaker activity levels.
Or at least that is the way things should pan out. Some analysts point nervously to the mining sector, where metals and other prices have fallen in the past three years, but production has remained stubbornly robust. More analogous still may be the experience of the US shale-gas industry. That sector has suffered one L-shaped crash in Henry Hub prices and two collapses in operating rig numbers in the past seven years. In mid-January, Baker Hughes said there were just 310 rigs operating in the US gas sector. In 2008, there were more than 1600. Yet in the same period, productivity gains, the switch from vertical to directional drilling and a focus on increasingly prolific plays brought more than a third increase in gas output, pointed out Citi in a recent research note. (The focus on liquids-rich plays also spurred more output of associated gas, so the collapse in oil prices may yet begin to affect shale gas output.)
Shale oil’s resilience will determine whether the market recovers slowly or quickly. Globally, cuts in capital expenditure affecting conventional projects will take longer to be visible in market balances. The ever-bullish Bernstein says as much as 10% of US production (around 0.9m b/d) or 5% in Russia (equivalent to about 0.5m b/d) could be cut. Bernstein compares the latest slump with that of 1998-99, when supply growth vanished. “That’s what a 20% industry capex reduction will do for you and we expect a similar dynamic to be visible at the end of 2015,” it says, while forecasting average Brent prices of $80/b this year and $90/b in 2016.
Citi’s Morse thinks that at today’s price up to 0.7m b/d of output could be cut by the end of 2015. Russia and Venezuela could each contribute 200,000 b/d, while the slowdown in the US’ tight-oil sector could cut 300,000 b/d from projected production, he says. Demand should also perk up. Every $1/b drop in the oil price brings marginal GDP gains to consumers, translating into a 0.018% rise in oil consumption - hardly a demand-side shock-in-the-making but, alongside similar rises in consumption elsewhere, enough to increase global demand by 500,000 b/d above expectations.
For Opec, that would offer a marginal but meaningful boost to its market share in 2015, at least in the second half. For 2015 as a whole, the IEA predicts that demand for Opec’s crude will be 350,000 b/d higher than it previously thought, at 29.2m b/d. As the cuts in non-Opec output begin to be felt in the second half of the year, when a stock draw should also begin, the call will rise to 29.8m b/d.
Point of no return
This will not, however, return the market to where it was before. An “historic shift” has taken place, says the IEA. Oil prices were too high too long, and demand and supply reacted in fundamental ways. The marginal supply - US tight oil - is far more responsive to the market’s signals than most conventional oil, offering near just-in-time reaction to price. That means that while the bottom of the latest market crash isn’t yet visible, the recovery - when it comes - will be less extreme than after previous slumps. Even when prices begin rising again, the industry will have to get used to more modest returns. Predicting a “U-shaped” recovery, Goldman Sachs says prices will “likely rebound to far lower prices levels from where they sold off from”.
It isn’t only the industry that will have to get used to the new market dynamic. “Current prices are unsustainable,” said the UAE’s Mazroui in mid-January, “not for us, but for the others”. These others include not just the world’s high-cost producers - Alberta, Brazil, Norway and others - but fellow Opec members. Venezuela’s economy is already close to collapse and as oil prices fall its pre-export agreements with China mean it must supply even more barrels to honour the terms. Iran in January slashed its budget oil price from $72/b to $40/b -- or less than a third the country needs to break even. Saudi oil minister Naimi may be sanguine about the kingdom’s finances in the face of the market collapse, but the government’s spending will still fall almost 20% this year, to $241bn, forecasts Citi.
Iraq, Russia, Libya, Nigeria and a host of other exporters that depend on oil revenue to mask chronic failings elsewhere in their economies will suffer even more. So as oil’s latest bust forces new changes on the industry, creating a leaner, fitter sector, political change could follow in many of the countries which, for too long, believed and acted as if prices would never fall.