Weekly Overview: How Low can Gas Prices Go?

There were more predictions of doom for oil and gas producers this week, despite apparently contradictory facts: hundreds of billions of dollars have been cut since 2014 from companies' upstream investment plans; oilfield output is presumably still declining each year with pressure as it naturally will; and US shale oil producers are on the skids as hedges run out and cash flow evaporates.

What is already being built upstream will go ahead but with Brent at $50/b translating into gas at around $7.00/mn Btu, integrated gas to LNG projects in Alaska and Canada are unlikely to see the light of day. We are, one argument goes, heading for a shortage, implying higher prices sooner or later – as the majors had said earlier this month.

But according to one respected energy economist, Oxford University’s Professor Dieter Helm, oil prices will struggle to rise above $50/b for the foreseeable future, thanks in part to weak Chinese demand and strong US shale output. He reportedly told the annual IP Week conference in London February 9 that industry forecasts of $60-70/b were unrealistic, given the potential for Iranian oil and gas and Iraqi oil to come on stream at very low cost and in the future $50/b was likely to seen as very expensive.

The shorter term also offers producers little grounds for hope, according to the International Energy Agency, which said in its monthly report this week that having peaked at a five-year high of 1.6mn b/d in 2015, global oil demand growth is forecast to ease back considerably in 2016, to 1.2mn b/d, pulled down by notable slowdowns in Europe, China and the US.

For its part, the US Energy Information Administration said in its short-term energy outlook published the same time that Brent and West Texas Intermediate crude oil prices were both forecast to average $38/b in 2016 and $50/b in 2017. But it also hedged its bets, pointing out that the current values of futures and options contracts show the market expects WTI prices to range from $21/b to $58/b (at the 95% confidence interval).

Bad news for gas suppliers 

The price news for wholesale gas suppliers specifically was also poor. The EIA forecasts that inventories will end the winter heating season (March 31) at 2,096 Bcf, which would be 41% above the level at the same time last year. It sees Henry Hub spot prices averaging $2.64/mn Btu in 2016 and $3.22/mn Btu in 2017, compared with an average of $2.63/mn Btu in 2015.

That might well help the US lower its carbon emissions in the power sector by displacing coal, but the price is not low enough for the purposes of companies with long-term offtake contracts with Cheniere Energy for LNG at Sabine Pass.

As the first off-taker at train 1, BG – which will be Shell by the time train 1 starts up in the coming weeks – secured the lowest of all the fixed prices: $2.25/mn Btu for liquefaction capacity. On top of that it pays the standard price to Cheniere for the gas: 115% x Henry Hub for the relevant month.

If the EIA is right, that adds up to an average of $5.30/mn Btu over the course of the year – in other words, higher than the present UK price, and that is before the vessel has even left the Louisiana dock. For other contracts it gets worse as the fixed fee rises across the trains, peaking at $3.00/mn Btu, which BG/Shell also paid for a later train.

At the time the deal was done, that looked a very safe bet from BG’s perspective. Shell might not like the look of it as the buyer, but as an LNG seller of some size itself, it will be unable to challenge the terms without risking awkward questions about its own sales contracts.

So this has led to some observers rowing back from earlier claims made for US LNG as the liberator for Europe, with the emphasis now being on the long-term nature of the gas business.

This is a standard industry response when things go awry at the outset although it is seldom issued as a note of warning when projects launch into a rising market, and it reminds one of the joke about long-term investments being no more than short-term investments that have inexplicably gone wrong. However, the contracts are of 20 years' duration.

On the other side of the Atlantic this price weakness is good news for Gazprom as it might not need to defend its market share so aggressively: in theory it could cut prices and win back friends.

But in practice, some European countries have a negative attitude towards its gas in particular – consumers in Poland for example are trying to build a case to have Nord Stream 2 stopped on competition grounds, the relevant agency this week announcing an extension to its investigation while it seeks more evidence for this unusual claim. 

Capacity for pain

Perhaps also worrying, although a less sensational topic, is the situation in Europe’s gas capacity markets, where transmission system operators (TSO) are facing an uncertain future.

While terminals are being commissioned – Poland is in the process of joining the not-so-exclusive club of LNG importers with its second commissioning cargo arriving this week and Estonia wants to as well, if only it can secure public funding for just 43% of it – one mystery is who will build big pipelines onshore to take the gas to where it is needed.

Unless the taxpayer underwrites it all, as part of a European Union-funded programme which has seen so much done in central and east Europe, the market signals for long-term capacity remain weak. Maybe there is already too much capacity in some places following interventionist measures; or maybe shippers are simply matching capacity to their increasingly short-term hub trading.

Either way, shippers are progressively moving to short-term bookings. Pan-European pipeline capacity trading platform Prisma said in its report on February 9 that on the primary market, shippers are clearly more interested in the short-term products, judging from  the auctions held in the last gas year, giving little clarity on future infrastructure investment needs.

In the pre-competition days this was different. Gas suppliers were also regional pipeline monopolies so they knew where potential consumers were and they could build pipelines or LNG terminals to deliver gas. That was the basis on which Wingas developed, competing with Ruhrgas for the same demand in Germany, for example – often using gas from the same upstream source. The gas price came down for everyone in consequence.

With unbundling, which came first to the British market, there were problems over the TSO’s cost recovery, when shippers discovered they could get capacity almost free if they left it till the last moment. But these problems could be addressed – as it was operating on an island – through some rebalancing of entry and exit charges. The shipper had no alternative but to pay up.

The European picture though is more complicated, because there is not one TSO, but dozens of possible TSOs across the continent depending on the route chosen for the gas. Selecting the cheapest option implies bypassing the most expensive which will see its revenues decline and its shareholders out of pocket. Putting up its prices will only worsen the problem.

Tariff code problematic

But even selecting the cheapest route and the cheapest contracts that also ensure firm access is not as easy as it could be. The levels of service on offer and hence the risk are not comparable between all the different TSOs. In some cases the cost of transport between two hubs is greater than the price difference between them.

Perhaps that is why the tariff network code remains on the to-do list. The Agency for the Cooperation of Energy Regulators (Acer) has, however, set up, with pipeline operator umbrella group Entso-g, a web-based platform for stakeholders to communicate “issues” with the existing network codes that are in operation.

Already achieved are the capacity allocation mechanisms, congestion management procedures, balancing and interoperability and data exchange rules.

Acer, which was set up by the European Commission, is under the scrutiny of the European parliament, which this week sent an eight-strong delegation from its committee for transport, research and energy to Slovenia. “The delegation discussed the latest developments in the Agency’s work towards a single, well-functioning and transparent energy market in Europe,” Acer said in its account of the meeting.

Discussions focused in particular on Acer’s work for the development of sound regulation and complementarity of rules at national and EU level and the current status of the single energy market as well as its work on developing trans-European infrastructure for energy and the role of Acer in the framework of the EC’s strategy for an energy union, Acer said.

No doubt they also discussed whether public or private money should be used to further any of these objectives and if the latter, how best to attract it.

William Powell