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Energy Markets and Scarcity Pricing

Regional Constraints and the Marginal Unit of Supply


Author: Brynne Kelly 11/08/2021


In their latest Winter Fuels Outlook, the EIA stated that they expect higher heating oil prices & a slightly colder winter compared with last year will contribute to households across the U.S. spending more on heating this winter (Oct-Mar) compared with the past two winters


For background, about 4% of all U.S. households use heating oil as the primary fuel for space heating, and the vast majority of these households are concentrated in the Northeast. About 18% of households in this region use heating oil for space heating, down from 27% 10 years ago.


Supply shortages have been a hot topic recently which have lifted energy prices across the globe. Specifically, we are seeing the real cost of regional constraints being exposed. Logistical constraints between regions include pipeline capacity, shipping rates and natural gas liquefaction capacity. With winter fast approaching, and the primary sources of heating homes and businesses coming from electricity and natural gas, regional constraints are being exploited in global LNG markets which are highly exposed to capacity constraints.


LNG Prices Impact US Consumers Too

High LNG prices are certainly a problem for Asia and Europe, but they are also a problem for the US Northeast in the winter. Incremental supply to meet demand in the US Northeast in the coldest months of the year comes from imported LNG into the region. Typically this has been imported from places like Trinidad and Tobago, but can come from anywhere really.


There has been a lot of focus on global LNG prices and how they might affect US natural gas prices now that we have the capacity to liquefy it and export it. Much less focus is placed on the one area in the US that is dependent on LNG to meet incremental demand in the cold winter months - specifically in the US Northeast. With limited pipeline capacity into states like NJ, NY and MA from the US shale basins, they must rely on LNG imports to fill the gap.


This dynamic can be seen in monthly US LNG import data below, where US LNG imports (primarily into the Everett, MA LNG terminal) reach their highest in December and January.

Since LNG is the marginal until of supply in the US Northeast, futures prices need to reflect that. Accordingly, natural gas futures - delivered in to the Boston area via the Algonquin pipeline - need to move towards global LNG pricing in order to attract supply.

This year, with Asian LNG prices trading near record highs this year, Algonquin natural gas futures have been reluctant to keep pace. Below you can see what this looks like as we compare heating fuels across the complex. All fuels are represented on a heat-content adjusted US$/Mmbtu basis. The red line represents Algonquin (aka, Boston city gate), the green and pink lines represent UK natural gas and Asian LNG futures, respectively. From the oil world, the blue and orange line represent US heating oil and Brent crude oil futures.

Basically, we have northern US markets competing for supply with global LNG markets and southern US markets competing to supply global LNG demand.


The dynamic is bizarre. We have natural gas from the main clearing hub in Louisiana (Henry Hub, black line below) being liquefied and exported to Asia and Europe in the hopes it displaces enough LNG to be imported from other countries into places like the Everett, MA in the US. With global LNG prices being so elevated this year, Algonquin natural gas futures for delivery in January and February of 2022 are even trading above NYH ULSD (heating oil futures, cyan line below) which looks like the 'cheap seat' relative to LNG imports. However, ULSD accounts for less than 1% of U.S. utility-scale electricity generation and only 4% of all U.S. households use heating oil as the primary fuel for space heating (as noted earlier).



Logistical Constraints

Natural gas is a market often defined by logistical constraints. In fact, when you compare US gas markets to Europe and Asia, it's easy to see that the further away you get from Henry Hub, the more that logistics add to the cost of the product (pipeline cost, liquefaction costs, tanker rates, etc.). In the case of US pricing hubs such as Algonquin and Tetco M3 (MidAtlantic region delivered) futures, winter prices are defined by the marginal unit available for import into the region - namely LNG from other countries or through scarcity pricing of domestic pipeline import capacity into the region.

As a result, we end up with natural gas futures in places like Boston trading close to $20/Mmbtu for January and February delivery - more than $14 above prices at Henry Hub. With few supply alternatives in certain regions, scarcity pricing can be extreme. There is a fixed amount of domestic pipeline import capacity into regions like the US northeast and the market uses 'price' as a tool to allocate capacity. This makes for volatile markets as scarcity is often defined by weather and weather is not something that provides a lot of visibility until we approach the delivery window. A warmer than expected winter in the northern part of the US could quickly eliminate the need for LNG imports and therefore, the premiums they are currently trading at.


At the moment, markets have lost their go-to cheap seat. Utilities, refiners and consumers have enjoyed cheap natural gas feedstock prices for years.


Regional Power Prices

This regional disparity in US natural gas prices translates into regional electricity prices since natural gas has become the marginal fuel in many of the US power pools. Specifically between ERCOT (Texas, blue line below) and PJM (MidAtlantic, gold line below) on-peak futures prices in the winter. In the summer months, the situation is reversed. Cooling demand in the southern half of the US leads to constrained pricing the Texas power markets as the market attempts to price in the marginal unit of available electric power generation.

The spread between natural gas and power prices, called the 'Heat Rate' is similar to crack spreads in the refining sector. Heat rates define the spread between regional natural gas prices and their corresponding regional wholesale power prices. Using this lens we note that 'refining margins' in ERCOT are higher than those in PJM during winter months given the logistical pricing constraints attached to natural gas delivered in the northeast regions even though outright futures prices in PJM are higher.



Natural Gas Consumption by Sector

According to the EIA, the United States used about 30.5 trillion cubic feet (Tcf) of natural gas in 2020, the equivalent of about 31.5 quadrillion British thermal units (Btu) and is 34% of U.S. total energy consumption. The majority of this natural gas consumption is driven by the use for electric power generation, followed by industrial consumption. In 2020, the electric power sector accounted for about 38% of total U.S. natural gas consumption.


The industrial and utility electric power sectors have developed tools over the years to entice demand response when supply is low. Utilities often provide incentives for customers to reduce demand via demand response programs. This means there is a level of shadow supply waiting in the wings to balance the market. This dynamic also adds to the volatility of spot prices in winter months.


Bottom Line

Energy markets across the board are grappling with not only trying to price in scarcity dynamics within their own family, but also against it's competitors outside the 'family'. This year in particular all markets appear to be pricing at the marginal unit of scarcity, lifting prices across the board and leaving no cheap seats to turn to. Realizing these expectations will be a bumpy ride for sure. We have, at best, 3-4 weeks before we have more clarity on how cold weather will impact supply and at what level the market clears that incremental unit of supply.



Of Note Over the Weekend:

  • Larger-Than-Expected Saudi Crude Price Hikes To Asia Bullish For Markets - RTRS. Top oil exporter Saudi Arabia has raised the price differential of its flagship crude to Asia by more than double in December versus November, exceeding market expectations and sending a bullish signal to the global oil market, traders said.

  • Gazprom Won't Offer Spot Gas At Its Sales Platform This Week

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EIA Inventory Recap


Weekly Changes

The EIA reported a total petroleum inventory BUILD of 2.30 for the week ending October 29, 2021 (vs a net BUILD of 0.80 last week).


YTD Changes

Year-to-date cumulative changes in inventory for 2021 are DOWN by 135.00 million barrels (vs down 137.30 million last week).


Inventory Levels

Commercial Inventory levels of Crude Oil (ex-SPR) compared to prior years are have gone from way above historical levels to surprisingly below historical levels and should continue to draw as long as backwardation in the market persists.





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