Global view

Optimisation was the buzz word at this year's Middle East and Africa Global Energy Forum in Dubai. Oil & Gas Middle East discussed the burning issues facing the upstream sector with keynote speakers.

David Hobbs, head of research at Cambridge Energy Research Analysts (CERA) and principal author of a major assessment of the world economic crisis, "Recession Shock: The impact of the economic and financial crisis on the oil market," spoke to Daniel Canty about where the challenges and opportunities lie for upstream players in the current climate.

What is happening in global gas markets?

There is more gas available today for import, but the important issue for producers is whether or not there is going to be sufficient demand for it. In North America particularly the conventional gas revolution has cast into doubt whether there will be a real need for imported gas.

Two massive gas fields (Haynesville Shale and Marcellus Shale) in the US could be two of the largest gas fields in the world. These aren't just big in North American field comparisons, but big in North Field and South Pars terms. Recent estimates are in the region of 600-900 trillion cubic feet in those two accumulations alone.

This means we're starting to see a dramatic turnaround in the prospectivity of North America for gas production, brought about by changes in technology and know-how that is allowing that gas to be unlocked in a commercial way.

Can shale gas really compete with the low extraction costs of Qatar?

Everybody assumed that because it's shale gas it would be costly to produce, but in actual fact, through the drilling of horizontal wells and fractures of those wells, rates of 3 - 10 million cubic feet a day are starting to come through. What was initially perceived as costing $8-12 per million cubic feet is actually coming in at much more competitive rates than that.

What we're seeing there now is an excess of drilling prospects, and rigs can be mobilised very quickly, so any increase in the price and you're likely to see an increase in rig utilisation and associated increases in production. The lead times on turning that around are really quite short now.

Will the USA become a gas exporting to rival Qatar on the global scene?

Currently there is no mechanism for export so that gas would have to be swallowed up by domestic consumption. What that means is that earlier predictions, ranging between 5 - 15 billion cubic feet per day of imports - pretty much in line with the expansion coming on stream from Qatar and Nigeria, that now is not necessarily required.

If I'm an LNG producer and I've got a choice between oil indexed sales in Europe or gas on gas competition in North America, it's more likely that those volumes will find their way into Europe than North America because at least the European market doesn't clear solely on price, which its North American counterpart does.

Does this pose big problems for the companies geared towards the US market, such as the major JV's in Qatar?

I don't think so. The joint venture companies developed these projects with a 30 year timeframe in mind, and there is no doubt that the world is going to need that gas at some point and in some form. However, it may be the case that this is a bump in the road for them. North American demand was probably the impetus for a lot of these JV gas megaprojects to get off the ground.

However, these projects will most likely become hugely profitable for the developers even if that gas never makes it to the United States.

So new markets will be easily found?

Ultimately, natural gas is becoming more fungible. There is no question that the proportion of LNG that is fungible between markets is increasing, and that's only good news for developers, because it means they don't have to bet their investments or long term strategy on one particular market.

Does this extra available capacity mean Qatari exports will replace Russian ones in European markets?

Despite the furore over supply issues last year, Russia has historically been a very reliable supplier of gas. There are both sides to the Ukrainian cut-off story, and I think these discussions draw a lot of parallel's with the ‘oil-weapon' scares of the 70s which was, in practice, very rarely deployed.

However, to say that doesn't that mean there isn't a growing desire to diversify away from a perceived over-reliance on Russian gas to Europe. In some countries Russian gas is actually a smaller part of the portfolio than the media makes out, and primarily it is Eastern European countries where it is a majority supplier.

Diversity is always good, but how much people are willing to pay for that diversity is an important question to ask. It wouldn't surprise me if politically European countries wanted to lock-in long term supplies from Qatar just as much as they want to lock-in long term supplies from Egypt, and Algerian and Libyan expansions.

What's different about the current oil price slump to the low price era a decade ago?

One of the topics I touched upon in the keynote address is that typically it is the big ticket projects which normally fall first. That's not been the case this time, but that's largely attributable to the rapid speed of the decline. If you go back to 1988-89 it was actually quite a long run-in, over a period of three years before we ended up in the abyss of sub-$10 oil.

As a result, back then, there had been a deferral of big capital projects. Also, as a share of overall supply these big projects were not as important to overall supply as they are now. That's the big difference.

In the late 90s there was a foreseeable decline which saw the big capital projects taken out of the equation, companies ran for cash flow and laid people off, and IOCs reduced exploration and reduced their dividends. This time around, the run-down happened in such a short time frame, just six months, that the response has been back-to front compared to normal run of events in slowdowns. Once the market has had a chance to normalise we'll likely see a reversion to the norm"

So some big projects could still be cut?

If oil stays where it is I think we'll certainly see some companies deferring big capital projects. However, if we have some sort of supply interruption that kicks the oil price back up, then all bets are off. All capital can be funded at $70, and we'll see no major cutbacks should that happen this year.

Will the more expensive enhance recovery projects be cutback in the meantime?

EOR using thermal recovery is actually one of the last things to be cut back in a run down, because once it's shut it down you lose that heat from the reservoir. Building up that steam front again is costly and time consuming, so if there is any way of avoiding that then you do. In Canada there has been some cutback as they've reduced the volumes of steam injection, and reduced production, but they're looking for the minimum level that maintains the heat in the reservoir which would enable them to step up production again when the time was right.

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