With so much new supply hitting the market over the next few years, and with incremental demand from the Gulf Coast, natural gas producers haven’t seen the last of widening basis differentials, according to RBN Energy LLC’s Rusty Braziel.

The new pipeline capacity planned for the Marcellus and Utica shales — headlined by the 3.25 Bcf/d Rover Pipeline — should soon relieve takeaway constraints and allow Northeast exploration and production (E&P) companies to stretch their legs, Braziel said during a recent web presentation.

Based on current forward curves, RBN is projecting combined Marcellus/Utica production to grow from around 24 Bcf/d currently to nearly 40 Bcf/d by the end of 2022.

“That’s a 16 Bcf/d increase, almost half of which is probably going to happen between now and 2019, so Rover shouldn’t have any problem at all filling 3.25 Bcf/d,” nor should a “gaggle of projects to get gas out of the Northeast. But “the market may have a bit of problem” once all this new supply comes online, “because the Marcellus and Utica region is not the only area that’s experiencing supply growth.”

There’s the resurgence in the gas-focused Haynesville Shale, where RBN is counting another 3 Bcf/d of supply coming online through 2022 based on forward curve pricing.

Associated gas from oil-directed drilling also is growing, particularly in the Permian Basin and in Oklahoma’s stacked reservoirs, notably the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend of the Anadarko Basin, mostly in Canadian and Kingfisher counties).

In the SCOOP/STACK, RBN is modeling about 3 Bcf/d of associated gas supply growth through 2022.

In the Permian, a lack of historical data for greenfield development, for example, Apache Corp.’s Alpine High, presents upside to associated gas growth and makes accurate modeling difficult, Braziel said. RBN estimated the Permian, spread across West Texas and southeastern New Mexico, could generate 3 Bcf/d of associated gas growth just from the Delaware sub-basin by 2022, with the Midland chipping in another 1 Bcf/d.

Associated gas is generally understood as a source of production that’s unresponsive to natural gas economics, but Braziel made it crystal clear what that means in terms of an E&P’s bottom line.

Moving forward, a $3/MMBtu gas price should work for natural gas producers, according to Braziel, with Marcellus and Utica breakevens in $1.75/MMBtu to $2/MMBtu range and the Haynesville not far behind.

“The problem is what happens if gas is not at $3/MMBtu because of weather” or an interruption to liquefied natural gas (LNG) exports “or because of a problem with pipeline capacity?” Braziel asked. “Because those crude producers have breakeven prices that are far lower, ranging anywhere between negative $10/MMBtu up to a $1/MMBtu in the Permian and the SCOOP/STACK.

“What I’m saying here is that at $50/bbl crude oil prices, many producers in the Permian and SCOOP/STACK can afford to pay someone to take their gas and still break even, not that they would, mind you…but they could.”

Meanwhile, with a lot of incremental supply and limited growth from power burn, additional exports from the Gulf Coast in the form of LNG and pipeline deliveries to Mexico would be needed to balance the market.

Lower 48 supply is on pace to grow to more than 90 Bcf/d by 2022, with baseload demand expected to remain essentially flat and power burn only expected to grow around by around 2-3 Bcf/d during that timeframe, depending on gas economics relative to coal, Braziel said.

Exports to Mexico are expected to increase from around 4.5 Bcf/d to close to 10 Bcf/d through 2022, according to RBN’s projections.

Meanwhile, the United State is on track to have close to 11 Bcf/d of LNG export capacity by 2019, with around 85-90% utilization, Braziel said. “That translates into just under 10 Bcf/d of LNG moving out of the U.S., which goes a long way to balancing the market, but the catch is that doesn’t happen overnight.”

Also, once that first wave of LNG projects comes online, “it’s going to be a while before additional capacity can be added, most likely until 2022 or so for most of the projects that we count as first wave expansions,” with another roughly 20 “second wave facilities” further off.

Braziel said a situation is developing where all major supply basins are competing for new demand out of the Gulf Coast. Supply from the Marcellus and Utica continues to push into the Midwest and into the Gulf Coast region to compete with associated gas, while “Rockies gas is moving east, exactly where it is not needed.”

Now Rover is entering this “traffic jam,” Braziel said. “It’s good that Marcellus and Utica producers have all this new capacity, but they’re not all the way out of the woods yet.” Rover, for example, plans to move a good percentage of its gas to the Dawn Hub in Ontario.

“But guess what? Demand is not growing at Dawn,” Braziel said. “In fact, a lot of Canadian producers are also targeting Dawn on TransCanada, so that means gas that is currently supplying Dawn is going to have to go someplace else. But remember, the only place where demand is growing is the Gulf Coast, and that’s a long way away from Dawn, Ontario.”

Ultimately, this points to a scenario where “there’s simply not enough pipeline capacity” to move all the supply to the Gulf, “which is going to show up as widening basis for all the points outside the Gulf Coast region. Bottom line: We haven’t seen the last of natural gas price basis problems across most of the country, at least for the next couple of years.”