Northeast U.S. natural gas price link to Europe primarily a winter concern

U.S. natural gas markets have been relatively insulated from historical global pricing exposure primarily due to abundant domestic supply and limited LNG and pipeline export capacity.  When the war with Iran began back on the last day of February and 1/5th of the world’s LNG supply was shut in due to the closure of the Strait of Hormuz, very little price impact was felt in the U.S., particularly at the Henry Hub benchmark, which has not really moved over the past four months.  The reason is fundamental.  Domestic production was still ample, and LNG exports were already maxed out, resulting in very little change in U.S. gas prices.  Not nearly the same story for Europe’s TTF benchmark where prompt month pricing jumped $7.71/MMBtu in less than a week after the start of the Iran war.  While the price premium has retreated in recent weeks with ongoing peace Memorandum of Understanding discussions, TTF remains a 4.4 multiplier to Henry Hub currently.   

So does any of this structurally change for U.S. markets once winter comes should the Strait of Hormuz remain restricted?  Admittedly, the correlation between global benchmarks have strengthened, and U.S. prices are being influenced by global supply-demand dynamics, primarily at the Henry Hub benchmark.  But that influence has been measured in dimes, not dollars per MMBtu, with most other non-Henry Hub regional indices typically trading at a discount most of the year against that benchmark.  However, there is an exception to this norm, which is the northeast region of the United States which still imports LNG to meet peak demand.  

While northeast gas prices are not directly linked to European prices most of the year, they are influenced during periods of high demand for natural gas, particularly in the winter when insufficient pipeline capacity exists to deliver needed gas supply and prices diverge from Henry Hub and spike.  It is during these short periods that the marginal price of energy becomes LNG imports.  It is the confluence of increased demand, lack of domestic pipeline capacity, and the significant LNG premium to European buyers that forces the northeast market to compete for LNG molecules that would otherwise head to Europe.   

Highlighted in the chart below are three natural gas pricing locations that clearly show this unique market dynamic.  The Title Transfer Facility (TTF) European benchmark in the Netherlands, the Henry Hub benchmark in Louisiana, and Algonquin City Gate, a northeast pricing point that has no other alternatives to pull from during spurts of extreme demand.  Highlighted are the past 5 winters where Algonquin City Gate prices departed the typical tight correlation to the Henry Hub to attract LNG molecules from Europe for a growing number of winter days.  While LNG can raise national benchmark prices, the magnitude of impact is moderate relative to regional price drivers seen at Algonquin. 

The dominant factor driving this trend is insufficient pipeline capacity.  However, in the current energy market where price mitigation reliability are at the forefront, even the Northeast, an area long known for opposing gas infrastructure, is receiving some unlikely tailwinds from multiple sources.  Algonquin Pipeline, which is currently in an open season for their Project Beacon, which would, if built, increase pipeline capacity in New England by 10%, has a new supporter in Massachusetts Gov. Maura Healy, which recently urged power generators to consider subscribing in some form to support the project.  In the area of permitting at the federal level, the FERC unanimously issued a Notice of Proposed Rulemaking (NOPR), in May, which would more than double the spend threshold of current automatic “blanket authorization” program from $14.5 million to $30 million, to allow pipelines to move forward with smaller infrastructure projects without prior FERC review.  Developments like these will greatly assist gas pipeline and storage projects, reduce both costs and opposition to get them built, and significantly reduce the timelines to complete. 

Conclusion 

Northeast U.S. natural gas prices exhibit a partial and episodic correlation with European prices with an LNG structural linkage when the stars align.  Regional infrastructure constraints and short periods of high demand dominate pricing outcomes. The higher the price of gas in Europe, the higher the floor price for the Northeast U.S. during these periods. However, the historical tides of opposition may be turning warmer to be more receptive to natural gas infrastructure development into New England.  But time, and likely the next election or two, will likely play out the longer term direction in this evolving energy market dynamic.