Appalachia's tight forward gas spreads pose risk to summer storage injections

Narrowing summer-to-winter forward price spreads at Appalachia's natural gas hubs are promising to slow storage injections this season, potentially posing a risk to the region's pre-winter stock levels.

At key upstream locations across the region, peak-summer prices have hit historic highs in relation to next winter's forward valuations. At the regional benchmark, Eastern Gas South, prices for June, July, and August are now trading at an average discount of just 10-15 cents to next winter's December, January, and February contracts. At Texas Eastern M2 receipts, the same seasonal spread has been cut in half over the past four months to around 30-35 cents currently, S&P Global Commodity Insights data shows.

Relatively strong summer prices have been fueled by elevated spot-market demand and expectations for continued near-term supply tightness in the US market writ large. In the cash markets, Appalachian gas prices are now trading in the upper $6/MMBtu range. Compared with last spring, basis spreads to Henry Hub are much narrower with most hubs now pricing just 70-80 cents behind the US benchmark.

The tighter spreads come as near-record volumes of Appalachian gas are flowing beyond the region to destination markets, mainly in the Southeast and the US Midwest. Month to date, net outbound flows from the US Northeast are averaging about 14.2 Bcf/d—just 600 MMcf/d below the record monthly average recorded last May, S&P Global data shows.

With spot demand and prices for Appalachian gas expected to remain strong through the summer months, a shortfall for the Northeast region's storage build this summer looks increasingly possible.

Storage, supply

As of mid-May, regional gas storage in the Northeast is estimated at just under 360 Bcf—about 80 Bcf below the prior five-year average and its lowest mid-May level since 2018.

After bottoming out around 280 Bcf in early April, Northeast gas storage has been slow to fill this year. Over the past five weeks, utilities and traders have injected an average of 2 Bcf/d to inventory, undershooting the five-year average injection pace by some 800 MMcf/d, historical data from S&P Global shows.

The paltry pace of injections comes as a steady narrowing in the summer-to-winter price spreads in Appalachia have made storage injections increasingly less profitable, particularly for supply stored and sold at Eastern Gas South, where the peak-summer to peak-winter spread is now around 10-15 cents.

Despite current market challenges, injections to Northeast storage would actually need to outpace the prior five-year average this summer by about 450 MMcf/d to 500 MMcf/d for regional stocks to hit typical pre-winter levels at more than 1 Tcf by early November.

Strong gas demand from power burns and LNG exports, expected in Appalachia's destination gas markets this summer, is just one factor that's likely to keep the spot market tight. Another is producers' constrained response to the recent runup in gas prices. On first-quarter 2022 earnings calls, some of the region's largest operators promised to keep production at maintenance level this year, using free cash flow to pay down debt or return more value to shareholders.

So far in Q2, Appalachian gas production has averaged about 33.3 Bcf/d—an increase of just 180 MMcf/d from its year-ago level, S&P Global data shows.