What will they do with all that cash?
That’s the question investors are asking of major oil firms like Apache (NYSE: APA).
The company recently completed a slew of property sales, beefing up its coffers. First divesting its extensive Gulf of Mexico Shelf portfolio to privately-held Fieldwood Energy, for $3.75 billion. Then announcing the sale of one-third rights to its Egyptian acreage to Sinopec for $3.1 billion.
Combined with cash on hand, this will give Apache over $7 billion in the bank. Raising the issue: where will they spend it?
The same could be asked of other major oil firms. Most are making good profits with oil over $100 per barrel. Some like Shell have recently completed multi-billion dollar financings.
You’d expect such an environment to be rife with acquisitions. Companies re-deploying abundant capital to convince investors they’re positioned for growth.
And yet, few such deals have emerged.
In fact, there are signs that majors are actively shying away from some of their most stalwart global plays. Look at the deepwater Gulf of Mexico. An August lease sale brought in the lowest dollar amount of bids in 14 years, at $102.4 million. In total, only 61 bids were placed across 53 blocks—less than half of the 131 bids on 116 blocks put up in the same sale last year.
Even some of the world’s biggest, billion-barrel plays are getting the thumbs down from big oil.
ConocoPhillips (NYSE: COP) said recently it will sell its 8.4% stake in the 35 billion-barrel Kashagan oil field in Kazakhstan, for $5 billion. The buyer is not another major, but rather Kazakh state oil company KazMunaiGas (who preempted a bid from India’s Oil and Natural Gas Corp).
Even Brazil’s offshore pre-salt fields—arguably the hottest oil play in the world for the last half-decade—appears to be drawing yawns.
This month industry group the Americas Society and Council of Americas Energy Action Group released a report saying that big oil companies may sit out Brazil’s upcoming offshore bid round in October. Brazilian terms for the big fields are reportedly too steep—chiefly the requirement for state E&P Petrobras to retain a minimum 30% stake, and serve as operator of all projects.
What in the World is Left?
All these recent divestitures and deferrals raise the question: what are the majors doing these days?
This issue is obviously critical for investors in these big firms themselves—will big oil be able to find plays that create a return on capital? Or will now-flush cash reserves be funneled into non-operational activities like share buybacks and dividend increases?
The former seems to be hard to come by. The latter is unlikely to create value—most majors today trade at a substantial premium to the assessed worth of their reserves. The chart below shows, for example, that Shell’s (LON: RDSA) current share price values the company (on an enterprise value-basis) at nearly four times the worth of its in-ground oil and gas.
Buying back shares at such a lofty valuation—the way Shell has been doing of late—is a good investment only if significant growth is on the horizon. Paradoxically, the fact that Shell is investing in share buybacks rather than operations suggests exactly the opposite—the company sees few good growth opportunities out there.
With few majors trading at the low multiples that make buybacks productive, this strategy doesn’t appear to be a value-enhancing path for the industry. That doesn’t mean big oil companies won’t do it—just that they shouldn’t, and investors shouldn’t stand for it.
The question of what majors will do next is also poignant for investors in the junior E&P sector.
The fate of a junior company can be much enhanced by aligning with the machinations of big oil. If a small E&P can get into a play with potential to attract the majors, it stands a much better of chance of receiving joint venture funding (vital for capital-intensive projects like deepwater drilling) or getting a lucrative buy-out from a big firm after initial, proof-of-concept success.
So everyone is wondering: what’s big oil thinking in terms of the next big thing?
Tea Leaves in Australia and the Arctic
Unfortunately, there aren’t a lot of definitive indications on this question yet. But a couple of recent announcements from the majors might suggest an industry undercurrent that’s starting to swirl, perhaps to break the surface soon in a headline-grabbing way.
Such as in the Australian offshore. Where Shell reported this month it has begun drilling the first-ever development well for a floating liquefied natural gas project.
The “FLNG” technology is something Shell has been pushing for years. Rather than have a large, expensive liquefaction plant sunk into one spot on the planet, the floating module can be moved to any offshore location—and start sucking up, shipping and selling gas. Local government wants to increase taxes? Field doesn't turn out to be as big as modeled? Simply pull up anchor and let your billion-dollar facility set sail for greener pastures.
Shell’s initial test of FLNG will be the Prelude project in the Browse Basin, off northwest Australia. The current well is expected to take two years to drill, with another six wells to follow. All told, Prelude’s reserves are thought to be three trillion cubic feet.
If proved out, FLNG could be a game-changer for the industry. So-called “stranded” gas reserves—fields in places too remote or challenging to develop, or where no local gas market exists—might suddenly be economically viable. The east and northern coasts of Canada along with Alaska might benefit, as could large number of stranded gas fields in Southeast Asia. Take note, majors and juniors alike.
If it’s not exploiting new fields, the next move from the majors could be exploiting old fields better.
That’s the thrust of a new technological initiative from Norwegian major Statoil (NYSE: STO): the subsea factory.
The idea is to build an entire oil and gas processing plant on the sea floor. Making facilities much more stable and resilient, especially for cold or harsh environments. Statoil also believes subsea facilities will improve recovery rates and reduce production costs.
The company has already developed working seabed separation and injection systems. It started on the next piece of the puzzle this month, announcing a $100 million joint venture with electrical suppliers ABB to develop power transmission, distribution and conversion systems that can function in 3,000 metres of water depth.
With this in place, Statoil hopes to develop working underwater compressor units as soon as 2015.
The company estimates that the subsea factory could knock hundreds of millions off capital costs for offshore developments. Combined with lower production costs, that could make many marginal fields economic.
The other use of the technology would be taming wilds like the Arctic. Billion-barrel fields in these harsh environs might finally be unlocked if equipment can be tucked safely on the sea floor, out of the elements.
All of this could be pipe-dreaming. But it’s starting to look like, given the choice, majors today would rather manufacture new reserves than discover them. Keep an eye on the R&D space.