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A mild end to winter has meant depressed demand for spot LNG cargoes in Asia and has pushed both JKM and TTF prices below $5.00/mmbtu for May-19 and Jun-19. Europe remains the more profitable destination for US cargoes and has used US LNG to push its inventories 875 bcf (24.7 bcm) higher y/y. Assistance in balancing the supply overhang in Europe should come from expected y/y drops in domestic output (due to maintenance, field declines and regulations), Algerian supply and Russian flows. We expect demand-side response from the power sector as well. TTF prices below $4.50/mmbtu would help 1.5 bcf/d of gas displace coal in the merit order this summer. South Asia could see gas grow its share in power generation due to low LNG prices. Bangladesh could add another 0.3 bcf/d y/y in gas-fired generation demand thanks to low LNG prices and a new 3.8 Mtpa FSRU set to start-up in Q2 19. JKM prices below $5.00/mmbtu would boost Indian power sector gas demand too, placing as much as 2.3 bcf/d more gas y/y above coal in the merit order. We do not expect US LNG volumes to be rejected, even in the face of a summer of low global prices, but a more constructive tilt on global LNG production or Russian gas exports to Europe would make closing the US export arb more likely.
Hit the switch
The start of spring has left global gas markets in a bearish mood. Both JKM and TTF prices are continuing to move downward, with May-19 and Jun-19 contracts for both hubs closing below $5.00/mmbtu on 3 April. A mild winter in Asia saw the major NE Asian LNG buyers reduce spot purchases for the season, after bulking up their buying in summer 2018. That left many cargoes from the US and Russia to head to Europe, which, combined with a mild February and March on the continent, helped push European storage up by 875 bcf (24.7 bcm) y/y by end-March.
With front-month contracts showing the JKM at near parity to the TTF, prices are pointing to Europe being the prime destination for spot LNG volumes. Our balances suggest 2.3 bcf/d (11 Mt) will be available for Europe this summer. The main question moving forward is how will Europe balance given growing LNG imports y/y? Lower Norwegian, Dutch, and British gas production y/y—due to a mix of maintenance, field declines, and regulatory limits—will cut European supply by 1.3 bcf/d y/y over the next six months.
Supply-side response to low prices will likely come from lower Algerian pipeline flows, which are indexed to oil prices and are therefore increasingly uneconomic. We forecast Algerian flows will fall by 0.9 bcf/d y/y this summer. A wild card in the European production mix is Gazprom sales through its short-term sales platform. How aggressive Gazprom is in offering discounts to prevailing hub prices will ultimately dictate how well Russian gas is able to compete with low LNG prices, and will also dictate the level of prices at the TTF and, indirectly, the JKM. So far, Gazprom has offset reduced customer nominations with selling on its short-term sales platform.
Demand-side response to bearish prices will come from more gas being pushed into the European power sector. There is room for an additional 2.2 bcf/d in added gas demand from pushing hard coal out of the merit order during summer 2019. While gas fully replacing all of that 2.2 bcf/d is unrealistic, the equivalent of approximately 1.5 bcf/d could be reached if European gas prices fall below the 5% fuel switch trigger (where a 45% efficiency gas-fired plant is as competitive as a 40% efficient coal-fired plant). That trigger would be hit with the TTF at $4.50/mmbtu, given current coal prices. Summer 2019-delivery TTF contracts currently average $4.91/mmbtu, meaning even if not all 1.5 bcf/d is achieved at the 5% trigger, Europe is certain to push more gas into power this summer.
We still expect flat Japanese LNG imports y/y and South Korean takes to slip by 0.4 bcf/d y/y this summer (1.9 Mt), due to higher nuclear availability in both countries. While a hot summer could see both Northeast Asian countries pick up additional cargoes, our balances suggest China will provide the only y/y boost to imports in that region, growing by 1.4 bcf/d (6.5 Mt) y/y during the injection season.
After China, the other key LNG import growth market is likely to be South Asia, which we forecast will see 1.0 bcf/d (4.7 Mt) more imports y/y this summer. New infrastructure will help boost send out, as capacity expands in both Bangladesh and India. Summit’s 0.5 bcf/d (3.8 Mtpa) Moheshkhali FSRU in Bangladesh is due online in Q2 19, which will double the country’s import capacity. India’s 0.7 bcf/d (5.0 Mtpa) Ennore terminal was commissioned in March, while the long-awaited Kochi-Mangalore pipeline is now scheduled for a May start-up to push utilisation at the Kochi terminal to 0.2 bcf/d (more than double the current usage rate of below 0.1 bcf/d). These new projects will help diversify the geography of India’s LNG demand, with Ennore the first regas terminal on the country’s east coast and Kochi the sole operating terminal in the south.
India’s LNG takes of 2.5 bcf/d (6.5 Mt) in 2019 through the end of February were down by 12% y/y. Part of this decline stems from the country’s power sector, where gas use fell by 1% y/y. The start of 2019 has seen hydro-electric generation push out gas in India’s power market. There is some room for gas-fired generation to grow in India via fuel switching. Coal-fired output currently accounts for more than 80% of India’s power generation, totalling 987 TWh in 2018. Gas-fired capacity stands at just 175 TWh, with 50 TWh used in 2018. If all 125 TWh of additional gas-fired generation is realised, there would be an increase in underlying Indian gas demand of 2.3 bcf/d y/y (17.5 Mt). While coal-fired plants fed by India’s domestic coal supply are unlikely to be shifted out of merit, JKM contracts below $5.00/mmbtu could begin to price out some coal imports. At that price, we would expect 30 Mt of coal displacement as more distant importers are cut out, resulting in 2.0 bcf/d (8.4 Mt) of uplift in gas demand in summer 2019. This assumes that India’s infrastructure expansion keeps pace with falling prices.
In Bangladesh, it remains to be seen how much of the country’s new import capacity will be used once available. Bangladeshi gas-fired power plants only had a 40% utilisation rate in 2018, as gas availability issues lifted oil-fired generation to 17.2 TWh (+27% y/y), while 13 TWh of gas-fired capacity went dormant. The recent drop in spot LNG prices should allow the country to buy enough gas to alleviate existing constraints, adding 0.3 bcf/d (1.9 Mt) to gas demand over the 2019 gas year by pushing oil out of the mix.
It is unlikely that US export cargoes will be rejected by the global market during summer 2019 because of the potential for gains in gas demand in both Europe and South Asia, as well as low Henry Hub prices keeping the US arb to Europe open. It would also be incredibly difficult to shut-in US LNG volumes, given Cove Point is fully subscribed through long-term contracts, and offtakers at Cheniere’s facilities have an approximate 60-day notice period to declare if they will not lift cargoes (see North America Panorama: Summer shut-ins, 28 March 2019). Even with these impediments, the ongoing downward trajectory for TTF and JKM prices leaves open the risk of shut-ins in the US, though this scenario is not our base case. If US feedgas demand were to fall due to global oversupply, we would expect the volumes of one to two US trains at most would likely be diverted from LNG feedgas into either the power sector or storage this summer.
|Fig 1: European gas storage, bcm||Fig 2: Global arb levels, $/mmbtu|
|Source: GIE, system operators, Energy Aspects||Source: Refinitiv, Energy Aspects|