Natural gas price convergence appears inevitable as US shale exports rise
In an oversupplied natural gas market, the hegemony of traditional exporters is being challenged by the emergence of US liquefied natural gas (LNG) as a competitive alternative for Asian and European buyers.
Sidestepping connotations concerning geopolitics and the direction of trade flows, a perfectly intended consequence is likely to be the convergence of natural gas prices at major hubs, and a further weakening of the link between gas and oil prices.
In Europe, major players pre-empted the arrival of the first US shipments by adjusting their pricing strategies. For instance, Statoil and Gazprom have increased the share of gas sold under spot-based or hybrid-based contracts, compared to oil-linked contracts.
In the Asia Pacific, considered the most lucrative market for natural gas exporters, gradual decoupling of pricing linked to the Japan Customs-cleared Crude (JCC) Index is also being driven by the potential of incremental US export volumes.
On paper, almost 80% of US LNG export agreements destined for Asian markets have been contracted on pricing terms directly linked to the Henry Hub price stateside, or under a hybrid pricing mechanism with links to Henry Hub, according to the US Energy Information Administration (EIA).
Furthermore, the EIA notes that flexibility in destination clauses enshrined in such export contracts is expected to promote greater liquidity in global LNG trading. It will also shift pricing away from oil-based indices, such as the JCC, and contribute to further development of Asian regional trading hubs and indices.
While there is currently no globally integrated market for natural gas, incremental US exports are piquing everyone’s interest in the direction of Henry Hub spot prices. More so, as the benchmark has to first and foremost contend with a domestic glut.
Looking back at the current 52-week range [from the time of writing], the Henry Hub spot price has fluctuated between $2.168 and $3.300 per million btu. My guesstimate, based on conversations with industry analysts, suggests a price north of $3.000 per million btu and no higher than $3.500 million btu would be the US medium term norm.
The implication of such a price range stateside on European prices cannot be understated. For instance, while rising exports and other variables have supported Henry Hub prices above $3, and dragged it gradually up from the sub-$2 despair of April 2012, the UK National Balancing Point (NBP) price – Europe’s longest-established spot-traded natural gas benchmark – has been steadily falling.
Currently lurking around $4 per million btu, the NBP spot price has shed $1 over the last four months, and nearly touched $3.50 towards the end of August. Deep down there is a realisation that Europe is a more attractive market for US LNG than Asia at current spot prices, because transportation costs to Asia are significantly higher.
One of the most ambitious undertakings has been by petrochemicals firm Ineos, which has commissioned eight Dragon-class carriers – each capable of carrying 27,500 cubic metres of US Marcellus shale sourced ethane – that would work round the clock to create a virtual feedstock pipeline from North America to Europe for its operations.
The first of these ships docked in Grangemouth, Scotland on 27 September, 2016, making it the first shale consignment to the UK. Now that history has been made, expect more of the same. Portugal and Norway have also received their first consignments of US shale gas, and soon Ineos will have company as other UK-focussed importers make similar overtures.
Offtakers will continue to consider shipping US LNG to Europe as long as the cost of the gas, transportation and regasification are below European spot prices, which happens to be the case at the moment.
Even though Henry Hub spot prices have held firm well above $3 in recent weeks, many analysts reckon US exporters would continue to look overseas to get more bang for their buck in an oversupplied domestic market.
Michael Hsueh, Research Analyst at Deutsche Bank, believes gas prices stateside are close to or above incentive costs for much of the country’s supply curve. “Therefore, we see fewer structural reasons to be bullish on the US domestic gas market, particularly while planned pipeline capacity additions from the Northeast could turn into supply-driven surpluses in the next two years.”
Hardly anyone suspects rising US exports would mean higher gas prices for American customers. To quote, Dmitry Marinchenko, Analyst at Fitch Ratings: “The US market is too big and too well supplied for LNG exports to significantly increase domestic natural gas prices.”
Of course, European importers are unlikely to have a monopoly on US exporters’ attention span, according to Stefan Revielle, commodity strategist at Morgan Stanley, who expects the recently expanded Panama Canal to boost export economics to Asia.
“Thanks to the completion of the Panama Canal expansion [in June 2016], US exports to Asia are now favoured over Europe thanks to a ~$0.35 per million btu reduction in shipping costs and a voyage now half as long. For instance, Shell and BP have already signalled their intentions of using the route to Asia and West coast of Mexico.”
In summation, while Asian and European buyers would still pay a premium for natural gas compared to their North American peers, price disconnects would be nothing on the scale of what we have seen in recent times. Already, non-US buyers are looking to adjust their premiums to Henry Hub prices on flexible short-term contracts.
Given the market as it stands, 2020 could well usher in a decade of higher gas price symmetry at lower price-points with the US tipped to be the third-largest LNG capacity holder after Qatar and Australia.