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Global oil firms are about to cut exploration spending, pulling back from frontier areas and jeopardizing their future reserves, industry insiders say.
OSLO, Feb 17 (Reuters) – Global oil firms, hit by one of the worst years for discovery in two decades, are about to cut exploration spending, pulling back from frontier areas and jeopardising their future reserves, industry insiders say.
Notable exploration failures in high-profile places such as Africa’s west coast, from Angola all the way up to Sierra Leone, have pushed down valuations for exploration-focused firms and are now forcing oil majors to change tack.
“It is becoming increasingly difficult to find new oil and gas, and in particular new oil,” says Tim Dodson, the exploration chief of Statoil, the world’s top conventional explorer last year.
“The discoveries tend to be somewhat smaller, more complex, more remote, so it is very difficult to see a reversal of that trend,” Dodson told Reuters. “The industry at large will probably struggle going forward with reserve replacement.”
Although final numbers are not yet available, Dodson said 2013 may have been the industry’s worst year for oil exploration since 1995.
As a result, exploration will probably be cut, especially in the newest areas, said Lysle Brinker, the director of energy equity research at consultancy firm IHS.
“They’ll be scaling back on some exploration, like the Arctic or the deepest waters with limited infrastructure … So places like the Gulf of Mexico and Brazil will continue to see a lot of activity, but frontier regions will see some scaling back,” he said.
Oil majors, which have a large resource base to maintain, are suffering the most, as the world is running out of very large conventional oil fields, and access to acreage, particularly in the Middle East, is limited.
That is leaving them with an increasing number of gas projects.
“When you look at the mix of oil and gas of the majors, it is definitely moving towards gas – simply because they can’t access conventional oil, which ultimately I believe will have an impact on oil prices,” said Ashley Heppenstall, the CEO of Sweden’s Lundin Petroleum, which co-discovered Johan Sverdrup, the biggest North Sea oil field in decades.
Prices Down Then Up
Before oil prices rise from a lack of exploration, they are first expected to fall, squeezing margins and forcing further investment cutbacks.
The International Energy Agency sees oil prices down at $102 per barrel next year from the current $108 as several producers ramp up output.
“Oil prices need to remain at elevated levels because there is a risk that a fall in oil prices or a cutback in investments by companies will mean that production growth slows,” said Virendra Chauhan, an oil analyst at consultancy Energy Aspects.
Although world oil reserves increased by 1 percent in 2012, they equalled just 52.9 years of global consumption, down from 54.2 in 2011, energy firm BP has said previously. BP sees consumption up by 19 million barrels a day by 2035, which would represent a 21 percent increase on th U.S. Energy Information Administration’s (EIA) estimate for 2011.
Energy firms have already been shifting capital from conventional to shale production, and this trend could continue as the exploration risk is smaller, the lag from investment to cash-flow is shorter, and project sizes are more manageable.
This is weighing negatively on the shares of exploration-focused companies.
“Explorer stocks are trading at discovery value or a discount to it, so from an equity market perspective, there’s no interest in owning exploration stories. People are losing faith in exploration,” said Anish Kapadia, a research analyst at consultancy Tudor, Pickering, Holt & Co. International.
Shares in Europe’s explorers fell 20 percent over the past year, underperforming a 2-percent rise by the European oil index .
Tullow is down 39 percent in a year, while peers Cairn and Cobalt are down 33 percent, and OGX is down 92 percent.
The spending cutback also cut mergers and acquisitions activity by half last year, IHS data showed, and plans to boost shareholder returns could shift focus to cooperation rather than fully fledged takeovers.
“You will probably see more activity at the asset level more than at the corporate level … More joint ventures, swapping assets, buying and selling of assets,’ said Jeremy Bentham, Shell’s vice-president for business environment.
Insiders believe the cuts may not be reversed until capital tied up in projects like Chevron’s $54 billion Gorgon LNG or Conoco’s $25 billion Australia Pacific LNG start producing cash flow and return.
“There will be less investor pressure, then companies can get activity back up, so this may be a pause of a couple of years where companies scale back,” Brinker said.
Last week the U.S. Senate’s Energy Committee held the first hearing in decades on the question of whether exporting US crude oil, prohibited by law since the 1970s, should be allowed again. Attendees heard proponents say that allowing crude exports would hold prices down with opponents claiming the opposite case.
To be clear, these would not be net crude oil exports. Of the 19+ million barrels a day that we consume at present, we import roughly 7.5 million barrels of crude per day and export roughly 2.5 million b/day of petroleum products (diesel and propane, for example). And even the US EIA admits we’ll be importing millions of barrels of crude oil for decades, in fact indefinitely.
So this is really an intramural fight: US oil producers want to be able to export while refiners and most users want to keep the crude at home. As Senator Ron Wyden, Chairman of the Energy Committee, said in his remarks, don’t expect this argument to be resolved quickly.
Here’s a related thought experiment. It involves the UK crude oil situation between 1980 and today, shown in Figure 1 below. After joining the exclusive club of Top 20 world oil producers in 1978, two years later the UK’s oil producers joined the ranks of oil exporters. Over the next 25 years they exported roughly ¼ of their total oil production, earning around $20+ per barrel most of those years. But after production peaked in 1999, within six years the UK was back to importing oil, at an average price approaching $100 a barrel. Imports have grown back to ½ million b/d, which is 1/3 of total consumption.
My question to the Brits: if you could turn the clock back, would you allow all your oil to be produced at the maximum possible rate, earning the amount of export dollars you did, if it meant that within a generation you would be back to being an oil importer paying roughly five times as much per barrel? In other words, how did the buy-high sell-low plan work for you? And were those exports in your best long-term national interests? Didn’t think so…
There are almost as many differences as there are parallels between the UK and US circumstances. But they share a bottom-line question: is it in the USA’s best long-term national interests to produce unconventional shale oil sufficiently fast that we end up exporting some of it overseas? Didn’t think so…
Fig. 1: The UK exported oil for 25 years from 1980 through 2005, shown above as the amount produced above the consumption line. Exports peaked at 1.2 million barrels a day in 1999, the same year that production peaked at 2.93 million b/d. imported roughly a half-million b/d in Data is from BP (2013).
Steve Andrews is a former energy consultant and a contributing editor for Peak Oil Review.
Posted by Jeff Rubin on January 27th, 2014
Judging by pump prices, Canadian drivers might think oil companies were rolling in profits that only move higher. Lately, though, the big boys in the global oil industry are finding that earning a buck isn’t as easy as it used to be.
Royal Dutch Shell, for instance, just announced that fourth quarter earnings would fall woefully short of expectations. The Anglo-Dutch energy giant warned its quarterly profits will be down 70 percent from a year earlier. Full year earnings, meanwhile, are expected to be a little more than half of what they were the previous year.
The news hasn’t been much cheerier for Shell’s fellow Big Oil stalwarts. Exxon, the world’s largest publicly traded oil company, saw profits fall by more than 50 percent in the second quarter to their lowest level in more than three years. Chevron and Total, likewise, are warning the market to expect lower earnings when fourth quarter results are released.
What makes such poor performance especially disconcerting to investors is that it’s taking place within the context of historically high oil prices. The price of Brent crude has been trading in the triple digit range for three years running, while WTI hasn’t been far off. But even with the aid of high oil prices, the supermajors haven’t offered investors any returns to write home about. Since 2009, the share prices of the world’s top five publicly traded oil and gas companies have posted less than a fifth of the gains of the Dow Jones Industrial Average.
The reason for such stagnant market performance comes down to the cost of both discovering new oil reserves and getting it out of the ground. According to the International Energy Agency’s 2013 World Energy Outlook, global exploration spending has increased by 180 percent since 2000, while global oil supplies have risen by only 14 percent. That’s a pretty low batting average.
Shell’s quest for new reserves has seen it pump billions into money-devouring plays such as its Athabasca Oil Sands Project in northern Alberta and the Kashagan oilfield, a deeply troubled project in Kazakhstan. It’s even tried deep water drilling in the high Arctic. That attempt ended when the stormy waters of the Chukchi Sea crippled its Kulluk drilling platform, forcing the company to pull up stakes.
Investors can’t simply count on ever rising oil prices to justify Shell’s lavish spending on quixotic drilling adventures around the world. Prices are no longer soaring ahead like they were prior to the last recession, when heady global economic growth was pushing energy prices to record highs.
Costs, however, are another matter. As exploration spending spirals higher, investors are seeing more reasons to lighten up on oil stocks. Wherever oil producers go in the world these days, they’re running into costs that are reaching all-time highs. Shell’s costs to find and develop oil fields, for instance, have tripled since 2003. What’s worse, when the company does notch a significant discovery, such as Kashagan, production seems to be delayed, whether due to the tricky nature of the geology, politics, or both.
Shell ramped up capital spending last year by 50 percent to a staggering $44 billion. Oil analysts are basically unanimous now in saying the company needs to rein in spending if it hopes to provide better returns to shareholders.
Big Oil is discovering that blindly chasing production growth through developing ever more costly reserves isn’t contributing to the bottom line. Maybe that’s a message Canada’s oil sands producers need to be listening to as well.