[Editor's note: A version of this story appears in the August 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.]

In recent years, Appalachian gas firms have faced some big challenges: chronically low gas prices, infrastructure that is in perpetual catch-up mode and the changing complexion of competition. Initially, low gas prices resulted in part from success in dry gas plays like the Marcellus. More recently, associated gas from the Eagle Ford Shale, Permian Basin, Midcontinent and other oily plays factored prominently in the ongoing saga of rising supply and low prices. However, those low prices may find reprieve this summer thanks to low storage inventories.

At midyear, storage inventories were well below five-year averages. Working gas, or the gas available for drawdown, stood at 2,074 billion cubic feet (Bcf), almost 750 Bcf below last year’s reading and 500 Bcf below the five-year average. Although it may seem too early for sounding the alarms on gas supplies for the next heating season, the time left for replenishing stocks is fairly short at 19 weeks. And, given the robust injection volumes in recent weeks (averaging 91 Bcf), one could surmise that gas supply for the next heating season is fine. However, a little probing casts doubt on this being a foregone conclusion.

Consider for a minute, average gas in storage at the start of the heating season (Nov. 1) in the past five years was 3,800 Bcf. Coincidentally, last year was also in-line with the average. So far, no worries. However, if we start with midyear’s 2,074 Bcf, and assume storage injections mirror the five-year average throughout the remainder of the injection season (1,250 Bcf), we arrive at a storage inventory of 3,300 Bcf. Is 3,300 Bcf adequate or will markets demand 3,800 Bcf? Let us assume for a minute that 3,800 Bcf, the “new normal,” is indeed the threshold and target for November.

Assuming 3,800 Bcf of gas in storage is the bogey, the industry faces a daunting challenge—the need to inject about 1,700 Bcf of gas during the next 19 weeks. Said another way, an average of 92 Bcf per week will need to find its way into storage facilities without fail, week in and week out, during the next 19 weeks. This is 40% above average and represents a level that has never been sustained before.

For reference, the five-year average injection is 66 Bcf per week from midyear through the end of October. Last year, storage injections averaged 52 Bcf per week for this period.

Continuing with this course of reasoning, questions naturally arise on sources of additional supply. Is another 500 Bcf readily available? Can the industry ramp up drilling in time? The short answer is there is no higher priority for gas than winter heating. Consequently, storage will be filled. As for sources, that is a more complicated question. On average, Stratas estimates that drilled but uncompleted wells can be turned in-line as quickly as three months. Drilling and turning in-line fresh opportunities takes markedly longer. Fortunately, the markets are quite efficient at sorting out priorities, and gas prices tend to be highly sensitive to storage concerns. As such, concerns over the lack of adequate supplies for winter heating show quickly in prices.

This translates into an opportunity for Appalachia. Appalachian producers enjoy many advantages, starting with geography and economics. Geographically, the Marcellus and Utica are centrally located to leading consuming regions in the Northeast, Mid-Atlantic and Midwest. Storage deficits are meaningful in key East and Midwest regions. Hence, Marcellus and Utica producers with abilities to scale production are well-positioned to address shortages in these areas. It is worth noting, storage is also in deficit to the five-year average in the South Central (producing) region. This may provide some buffer to Marcellus and Utica production from growing and competing associated gas volumes.

Economically, the Marcellus and Utica gas are highly competitive. Breakeven prices, particularly in overpressured areas in northeast and southwest Pennsylvania, are among the top in dry gas plays. Since 2015, producers have made great strides to improve wellhead economics and these efforts have resulted in a string of successes in capital efficiency, that is, lower finding and development costs through the drillbit.

Robust production growth in Appalachia is projected based on rising rig counts, continued focus on drilling in higher-quality areas and through enhanced well designs. Current projections call for 3.1 Bcf/d of growth for the region. However, additional upside is not only possible, but also deemed likely given the storage situation.

Associated gas from the Permian and Midcontinent is projected to add another 3.3 Bcf/d of incremental production this year. Vibrant activity, especially in the Permian, will remain a key driver of growth in associated gas.

As is often heard, things are different this time around. Appalachia has come a long way. Catalysts for higher prices have been identified and associated gas is likely to remain in the Gulf Coast region. That leaves one lingering topic—infrastructure. Gas processing and conduits for taking natural gas and related products to market appear mostly in-place and regional downstream options are developing. All of a sudden, the dawn for Appalachia is looking a bit brighter.

Stephen Beck can be reached at sbeck@stratasadvisors.com.

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