The growth of low-priced natural gas supply from Appalachia and Texas appears to be changing the market calculus on winter heating demand this year.
With pre-winter gas inventories sitting at their lowest levels in over a decade, prices remain near historic lows. In the coal market, inventories are also at their lowest level in more than a decade, but prices have shown little reaction.
For both commodities, an early or colder than normal winter could have a significant impact on pricing. Winter gas prices in some parts of the US suggest squeezes lie ahead. But until demand shows up, the markets for both fuels seem to believe supply will be available when it is needed.
In general, the market seems to be saying, “what’s the rush?”
Despite low inventory levels in the gas market, recent supply growth has led traders to believe that flexible production should be sufficient to meet residential-commercial heating demand this winter in most areas.
Through late September, US gas production has averaged more than 83.3 Bcf/d for the month, according to a modeled estimate from S&P Global Platts Analytics. In the past 12 months, production is up 13%, or about 9.7 Bcf/d, with more than half of that growth coming from Appalachia and one-quarter from Texas.
In late September, the US Energy Information Administration reported total gas stocks at 2.77 Tcf, down 18.3% from the five-year average. Gas in storage should end the injection season in early November at less than 3.3 Tcf, which would be the lowest level since 2005.
Meanwhile, gas demand is expected to rise. Demand is forecast to average 79.6 Bcf/d in 2018, according to EIA data. That would be a 5.4 Bcf/d, or 7.3%, increase from 2017.
So far, strong production growth has kept a tight lid on benchmark US gas prices this year. At the Henry Hub, the cash market has traded at an average $2.91/MMBtu from January 1 to date. The prompt futures market has been even weaker, with NYMEX Henry Hub natural gas futures averaging just $2.84/MMBtu over that same period, S&P Global Platts data shows.
The forwards market appears to reflect a similar price outlook. As of late September, the 12-month forward curve at the Henry Hub was priced at an average of just $2.87/MMBtu.
Coal prices also remain subdued despite low inventory levels, but could rally quickly if winter weather and rising gas prices lead to a shortage.
Powder River Basin coal, largely mined in Wyoming, makes up roughly half the market for thermal coal in the US. Stockpiles have shrunk in the last two years, and are now at levels not seen since 2006, when rail issues in the Powder River Basin led to a precipitous decline in inventories.
According to the most recent EIA data, utility coal stockpiles at the end of July stood at 110.5 million st, down 27.1% from the five-year average. S&P Global Platts Analytics estimates stockpiles stood at 107 million st as of last week.
The price for physical CSX coal has shot up in recent months to more than $70/st, but that has largely been due to export demand fueled by higher pricing in Europe.
For PRB 8,800 Btu/lb coal, however, which is not subject to export demand due to its relatively low heat content and distance from port, the price has remained stable. Since May, the price for PRB 8,800 for prompt-month delivery has averaged $12.44/st.
This stability despite low stockpiles is the result of a lack of demand, driven by both low gas prices and fears of over-contracting for coal. Coal buyers believe that if coal demand increases due to cold weather, there will be plenty of supply.
Coal producers, however, are warning that should gas prices rise this autumn or winter due to cold weather, utilities may find themselves with too little inventory, sparking a rally in prices.
In contrast to the broader US gas market, elevated winter prices in the Midwest suggest that traders are concerned that the recent growth in aggregate US gas supply may not be enough to meet demand there — especially on the coldest winter days.
In recent trading, the January-2019 and February-2019 forwards contracts at Chicago city-gates have climbed to nearly a 30 cent/MMBtu premium to Henry Hub. As recently as June, those same forward contracts were trading at a discount to the benchmark price.
Other regional hubs have seen a similar price trajectory.
At the Northern Ventura hub in Iowa, the two winter forwards contracts were trading recently at nearly a 70 cent/MMBtu premium to the benchmark. At Dawn Hub in Ontario, January and February forwards were recently priced at an average 24 cent/MMBtu premium.
Midwest forwards markets’ premium to Henry Hub could provide an opportunity for coal to regain some share of the generation mix, at least this winter. If prices remain stable, PRB 8,800 coal should stay competitive throughout the fall and winter and could even add some market share due to relatively low delivered costs.
Nationwide, the average delivered cost year to date for PRB 8,800 coal was $1.92/MMBtu through June of this year, according to EIA data.
Even with new pipelines bringing more gas from Appalachia to the Midwest, the risk of regional supply shortages seems to be driving prices in some locations.
Established supply arteries like Rockies Express Pipeline will move much of this gas west. But increasing volumes on Rover Pipeline and later this fall, Nexus Gas Transmission, will provide additional volumes, most notably to the Michigan and Dawn markets.
Aggregate flows from Appalachia to the Midwest should average about 5.3 Bcf/d from December 2018 to February 2019, according to S&P Global Platts Analytics.
On the coldest winter days, though, high utilization of the region’s supply pipelines means that certain Midwest hubs may be more dependent on gas in storage to meet demand. Midwest gas storage is currently sitting at 800 Bcf, about a 15% deficit to the prior five-year average.
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