The Marcellus is both amazing and, at times, reminiscent of a maze filled with increasing numbers of people scurrying to find a way out. There are exit routes, but too few, and not wide enough to handle a growing volume of gas in Northeast markets pressing for access elsewhere. New exits will be found, but not fast enough to handle the current and near-term congestion.

Of course, the amazing part about the Marcellus is that, even as it has grown into the world’s No. 1 or No. 2 natural gas field, projections of rising production continue to grow.

Speaking at Hart Energy’s Marcellus-Utica Midstream conference, Alan Armstrong, CEO of Williams Companies Inc. (NYSE: WMB), says production from the Marcellus and Utica is heading to 18 billion cubic feet per day (Bcf/d) by 2020. Jack Lafield, CEO of Caiman Energy II LLC, says production potential is for more than 20 Bcf/d by the end of the decade, up from around 13 Bcf/d currently.

Managing director Brad Holmes, of Tudor Pickering Holt & Co., projects growth in the Marcellus/Utica will add some 15 Bcf/d of supply, taking production to 25 Bcf/d in 2020, of which more than two-thirds will come from the Marcellus. The two basins will account for all the growth in U.S. gas supply, according to Holmes, who says associated gas from natural gas liquids (NGLs) and oil production will simply hold non-Northeast production flat.

The challenge — in terms of where to channel all this gas — stems from the imbalance between what Holmes describes as “explosive” supply and “stagnant” demand in the Northeast market. Against a 15 Bcf/d rise in supply, he projects a paltry 3 Bcf/d growth in demand in the region. As producers await new take-away to help mitigate the imbalance, Holmes warns of “turbulent differentials” that could translate into discounts to Henry Hub of up to $1 or more per thousand cubic feet (Mcf) through 2016.

Such pressures could shift producers’ focus away from a simple well hookup and processing arrangement, and toward a long-haul contract offering a more stable netback and protection against collapsing local prices, says Holmes. Gathering and processing operations would likely become more integrated into long-haul pipeline infrastructure, or into rail and waterborne solutions.

Perceptions of plentiful pipeline projects to solve take-away issues in short order may be misleading, in that about one-third of the projects are “simply redirecting gas within the Northeast market, creating gas-on-gas competition,” says Holmes. In addition, in-service dates for projects based on long-haul contracts, accounting for 60% of the total, are mostly for 2016 and beyond.

Another factor cited by both Holmes and Williams’ Armstrong is the relatively higher cost of building infrastructure in the Northeast. Specifically, Armstrong points to the Constitution pipeline connecting upstate New York and northeastern Pennsylvania. With “dozens” of overlapping regulatory agencies, its costs are $4.8 million per mile, says Armstrong, as compared to $1.7 million per mile for the Keathley Canyon connector, in 7,000 feet of water in the Gulf of Mexico, subject to a single regulatory body that is “strict but clear.”

In terms of NGLs, more infrastructure is needed to handle what is projected to be 1 million barrels per day in search of a home by 2020, according to Armstrong. In Holmes’ view, there is less logic to pipelines taking propane and butane to the Gulf Coast if they end in “just another dock” to access international markets. With NGL supplies outstripping regional demand in 2016-2017, the Northeast needs to “learn to swim,” using its own ports to access overseas markets or ship to the Gulf Coast, he says.

Armstrong described the upsurge of production from the two Appalachian basins as representing a “shift in the world’s energy center of gravity.” But there may also be a shift of similar magnitude as far as gas trends within the U.S., according to Holmes.

With such an imbalance of supply and demand in the Northeast, market forces will impel supplies to markets in the Midwest, Florida and Canada, says Holmes.

But it is the Gulf Coast markets — Texas and Louisiana — that Holmes sees as home for “at least half of Northeastern exports,” providing an outlet for as much as 6.3 Bcf/d of gas in 2020. With “unparalleled industrial demand” associated with petrochemical projects, coupled with growing power generation demand and rising exports — to Mexico and as liquefied natural gas — the Gulf Coast is likely to be a “premium market” by 2020.

Northeast gas supplying Texas and Louisiana? Now, that’s a reversal.