Algonquin as a premium LNG market

Published at 18:48 10 Sep 2019 by . Last edited 15:14 11 Sep 2019.

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New England’s Algonquin Q1-20 prices are still above those of any major LNG market, although a sharp near-curve rally at European gas hubs on 10 September may have eroded much of that premium. Algonquin becoming the highest priced market this winter is in part because of a likely y/y increase in power sector gas demand. But it is also because fast growing US exports have been weighing on Northeast Asian and European markets, while US shipping restrictions effectively prevent LNG transfers from the US Gulf Coast. We expect new pipeline infrastructure to New England from low-cost US production zones to only start weighing on Algonquin prices after the coming winter. 

Algonquin city gate Q1-20 prices were at 7.37 $/mmbtu on 9 September, with a peak in January 2020 at 8.60 $/mmbtu. The JKM Q1-20 market was at 6.31 $/mmbtu on 9 September. TTF winter 2019-20 prices rallied sharply on 10 September, with the January market rising to 6.2 $/mmbtu in mid-afternoon trading from 5.79 $/mmbtu a day earlier. 

LNG imports will provide the marginal supply for New England this winter and the region’s appetite for LNG will depend on aggregate demand. Baseload gas demand from the power sector should receive a boost this winter from the retirement of the 0.68 GW Pilgrim nuclear reactor in June. This could translate into as much as 3 mcm/d of additional gas demand y/y—that equates to three more LNG cargoes in Q1 20.

Further y/y growth in power sector gas demand could come from the increased displacement of heating oil from the New England power sector. Near-curve LNG prices have continued to slip against Brent prices—often used as a proxy for hedging heating oil purchases—encouraging generators to make spot LNG purchases. We noted the breakdown in the relationship between Algonquin prices and the Brent market earlier this year (see E-mail alert: AGT-TTF gas spread becomes the correlation to watch as AGT-Brent link weakens, 26 April 2019).

New England heating demand will be the main driver of aggregate gas demand, but weather conditions were broadly normal in Q1 19, so it is unclear if temperatures will support or weaken heating demand in y/y terms this winter.

In any event, a higher share of New England’s LNG supply could be bought on the spot market this year. The Everett terminal, which received most of the region’s LNG supply last year, was taken over by US utility Exelon from French utility Engie in October last year. Exelon has increased the terminal’s share of spot and strip LNG imports against long-term contract supply compared to when Engie owned the terminal and imported exclusively under long-term contract from Trinidad and Tobago. Of the eight cargoes Everett received in Q1 19, six were under supply deals of under two years. A year earlier, short-term supply made up just two of the 11 cargoes imported in Q1 18.

New England has ample spare LNG import capacity this winter as imports last winter were 6.98 Mt below capacity. The Everett LNG terminal took 0.56 Mt against a capacity of 2.7 Mt. The Northeast Gateway Deepwater Port in Massachusetts received two cargoes together totaling 0.07 Mt last winter against capacity of 1.5 Mt. The Northeast Gateway terminal requires the use of two floating storage and regasification units (FSRUs) for maximum output, and we expect Excelerate to position two FSRUs for imports this winter. Canada’s Canaport terminal, which was also used to meet peaks in New England demand, took 0.35 Mt, against capacity of 3.75 Mt.

Structural barriers

Algonquin city gate prices becoming the premium market for LNG this winter is a function of the infrastructure constraints that prevent the region from accessing low cost US output, while increasing LNG supply is weighing on other global markets, particularly European gas prices.

New England has not been able to draw on US LNG exports because of the 1920 Jones Act—a legal constraint requiring goods transported between US ports to be carried on US-built, US-flagged and US-crewed vessels. No standard-sized LNG carriers meet these criteria. The constraints were waived in 2017 to facilitate supply to Puerto Rico in the wake of hurricane Maria, but only for a 10-day period. President Trump in May recommitted not to waive Jones Act restrictions, having briefly considered it in April to eliminate a reliance on gas imports. 

Rather than satisfying domestic demand, fast-growing US LNG output has instead increasingly been directed towards European markets, amid slack demand in Northeast Asian markets, weighing on European gas hubs relative to Algonquin prices. Europe received a 31% share of US exports in January-August, which was up from a 2% share a year earlier.

New infrastructure will only cut LNG import demand from the 2020-21 winter

Pipeline expansion projects intended to deliver more gas from US production regions to New England are scheduled to start coming online in H1 20, but we do not expect them to cut demand for LNG imports in Q1 20.

Phase II of the Algonquin Atlantic Bridge project will add 93 mcf/d (2.6 mcm/d) of capacity to the Boston-area pipeline system. But the project is again awaiting approval for a compressor station and could be delayed beyond H1 20.

In the longer-term, there is also a proposal for the 0.65 bcf/d (17.8 mcm/d) Constitution Pipeline, to take gas from Pennsylvania (Marcellus) to New York state and potentially onward to New England. It has just received a federal permit, but the project has been long delayed and its construction is still being challenged by New York state. If the project ever does get commissioned, it is still years away and will not affect LNG imports in the short-term.

Fig 1: Share of US exports to Europe, % Fig 2: AGT-TTF Jan-20 basis, $/mmBtu
Source: US DoE, Energy Aspects Source: CME, Argus Media Group, Energy Aspects

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