European Natural Gas: So What's the Real Price?
Although it's difficult to discern the real price paid for natural gas in Europe, Howard Rogers, Director, Natural Gas Research at the Oxford Institute for Energy Studies, says there is a correlation in pricing between many of the hubs in Northwestern Europe.
That's according to analysis through 2012 published by one of his colleagues at the Oxford Institute, Beatrice Petrovich. While the Austrian CGH and Italian PSV hubs were outliers, he explains the survey trended towards better correlation amongst such hubs.
“What we've found when we did the update, which took us to October 2013, was that the playing field had tilted: with Asia pulling LNG away from Europe, the supply balance had shifted such that Southern Europe in particular had less LNG coming in; that meant that it needed to suck more gas from Northwest Europe, and various bottlenecks, whether they were physical or contractual, had contributed to some de linkage on the hubs in the south of France, in Italy, and to a degree, in Austria as well,” says Mr. Rogers
This was not what the Oxford Institute expected to find, he adds.
“In general, I think there is a willingness to move towards hubs,” he says, explaining that the further south and east one goes in Europe, the earlier in that stage of evolution the markets are. “The first stage is bilateral trading over the phone with no price disclosure; then you get ad hoc price disclosure; then you get trading on a hub with rules, balancing and all the rest – standard contracts, good price disclosure, an OTC market and an exchange forming in parallel.”
Northwest Europe, he says, has gone all the way down that route, while some parts of Eastern Europe are just at the beginning of that, with little or no price disclosure.
“Even in Turkey,” he explains, “it's in their bilateral telephone conversation in terms of trade but there's not very reliable price disclosure.”
Part of the problem, he says, is the difficulty of introducing sources of supply other than Russian gas.
Mr. Rogers says he keeps up to date with a price chart of NBP average monthly price, and also calculates what contract prices would be for Russian gas if they had the same relationship to gas oil and fuel oil prices from 2001-2008.
“If that relationship pertained, then currently that gas under those contracts would be selling for $13-14 MmBTU or thereabouts,” he explains.
It is strange, he contends, that for 30% of Europe's gas supply, i.e. Russian pipeline gas under long-term contracts, there is no publicly disclosed price. “Europe has no exact data on how much it's paying for that supply, which is somewhat bizarre I find.”
He says that the only disclosed price is the German average border price, comprised of Russian gas, but also Norwegian gas and Dutch gas, which all used to be on oil-indexed, long-term contracts. Additionally, Germany, he says, imports some gas on hubs, say TTF, but no one knows what the relative proportions of these components are.
“What we do know, though, is that the base price has de-linked from this historic relationship with gas oil and fuel oil; the last price that was disclosed was about $10 MmBTU, and that was just before we saw the recent plunge in hub prices in Europe, which are currently something like $7 MmBTU.
As for the key players, like RWE and E.ON, Mr. Rogers recalls that in 2010-11 they reported that they were losing a lot of money on their gas trading operations. “Because at that time they were committed to buying gas from Russia and others under long-term, oil-indexed contracts, but because of the surge of supply from Qatar and other LNG projects that catalyzed the hubs, then customers were increasingly pointing to the hub price and saying 'that's what I'm paying – you're not going to pass on your oil-indexed prices to me.'”
He says there were some rulings in Germany, for example, that decreed that end-users were no longer required to buy gas on an oil-indexed pipe price formation structure, and were no longer required to sign up for such agreements for more than a year.
“So, if you're a midstream player in the awkward situation of buying high and selling low, the customers were no longer captive to you under multi-year contracts.”
At that time, in 2011 announced to the press that the company expected to lose EUR 1 billion/year on their gas trading operation.
The situation improved a bit for such companies in 2012, he says, because either through arbitration or the threat of arbitration they were able to get price concessions from Gazprom, first by fiddling around with the formula variables in their contract price clauses. “More recently, Gazprom instituted rebates for its customers, the details of which are not fully known, but I think the idea was, whatever you paid for gas in a period of time, at the end of that period you looked back and got a rebate from Gazprom to bring the effective price you paid either down to or close to what the hub price was in that period,” he explains.
“By the end of 2013, with hub prices around about $10 MmBTU, these rebates kind of kept people whole.”
Mr. Rogers recalls he made a mischievous suggestion at the time: “If you're a midstream player and know you're going to get a rebate, why not just nominate high volumes, put them on the hub and generally bring down European prices in order to boost volume and improve your business.”
Mother nature, he says, produced the same result via a mild winter.
“That's one of the reasons that prices have collapsed the way they have on the hubs in Europe in the last couple of months,” he explains. “But it's also interesting that, as far as I'm aware, Russian volumes into Europe are pretty high, higher than you'd expect them to be.”
But are these volumes coming through contracts or gas that Gazprom is feeding into the hubs outside of its long-term contracts?
“The positive explanation for that is Gazprom is doing its bit to help Europe fill its storage in the event that Ukraine stops transit of gas through Ukraine.”
According to Rogers, the more Machiavellian take could be that because a lot of US LNG export projects are to reach their final investment decisions (FID) this year, the Russians might want to keep gas prices low in Europe. “So that when these guys come up to their FID they say 'of course we're all going to wave at Asia, but if Asia becomes saturated there's always Europe as a fallback market of last resort.' And at $10-10.50 MmBTU that's fine, keeps us whole, but $7 might give them pause for thought,” he explains.
And if US LNG projects come on to local markets one wonders what the actual effects will be on European gas prices.
Howard Rogers says that because other LNG projects are also scheduled to go online on a similar timeline the prospect for oversupply exists. “The excess over what Asia requires inevitably ends up in Europe and then the issue for Russia is, 'do we defend prices and reduce volumes and accept a loss of market share that we know will be temporary, or do we engage in a price war to bring our prices down in Europe, at Henry Hub and Asian LNG spot prices, in the hope of slowing down this pesky shale gas drilling in the States for a while? Once that's slowed down we can fall back on supplying to Europe, bring up prices to the levels that we're happy with and at a higher market share for a while.'”
Russia, contends Rogers, has been a sort of “shock absorber” of this system, by accident.
“Ten years ago at gas conferences everybody was expecting European power sector demand for gas to carry on growing strongly the way it had in the 1990s. Everyone was urging Russia to make sure it kept up its upstream investment so there was enough gas for Europe – Russia obligingly did this,” he recalls, “in the form of the Yamal Bovanyenko field.”
That said, he reports that European demand has been stagnant since the crisis. What's more, Novatek, Lukoil and Rosneft have stolen Russian domestic market share from Gazprom. “And so Gazprom is sitting on productive capacity that's not currently being used, somewhere in the range of 50-100 BCM/annum, so 5-10 BCF/day. That's kind of the buffer.”
Given the implementation of European regulation going forward, we asked Mr. Rogers how closely European gas markets might resemble that in North America. Gas will likely be associated with price on hubs, he says, whether it be spot supply or contracted gas that's indexed to hubs.
“In a sense, Northwest Europe has adopted the 'supply-demand price determination.' The European gas market will always be a bit more complicated than the US in the sense that we have many sources of imports; domestic production only provides about half of Europe's needs and it's declining.
“In the US the storage inventory change is obsessively watched, because that's a great indication of how tight the market is in terms of demand versus supply. That isn't that reliable in Europe, because all the different supply flows coming in from outside of Europe,” he explains.
Storage levels in Europe, he notes, are monitored in terms of how well storage is faring during the injection season to gauge how well Europe would do in the event of a severe winter.
Regarding Austrian OMV's recent announcement to join South Stream, Howard Rogers recalls that at one time the final destination for the pipeline's gas was set to be Italy.
He comments, “Although we're only talking 10 BCM/annum, the Azeri gas expansion clearly aims to get to Italy in the longer-term, so exactly why South Stream re oriented itself towards Austria, which, of course, was the original Nabucco concept. It's interesting.”
He points out that there's still the overarching problem of how to get South Stream to sit comfortably within the EU Third Package requirements, which have not been resolved.