A massive increase in natural gas pipeline capacity from Appalachia is poised to hit the market over the next couple of years, which when combined with a likelier looser federal regulatory environment, may temper Henry Hub prices in 2018 and beyond.

The Trump administration has signaled it plans to dismantle stringent regulatory oversight, and put pipeline approvals front and center by greenlighting the crude oil behemoths Keystone XL Pipeline and Dakota Access Pipeline.

Analysts Darren Horowitz and John Freeman of Raymond James & Associates Inc. said the go-forward is less clear for natural gas infrastructure, but the “trickle-down effect” of loosening federal regulations overall will be a positive.

More infrastructure is necessary for bottlenecked Appalachian supply, but “wildcards” are mounting overall for the gas market, which tilts the outlook for Henry Hub prices in 2018 and beyond to “cautious,” analysts said.

“Despite these uncertainties, we are fairly confident that Northeast spreads will shrink in the coming years,” Horowitz and Freeman said. Gas pipeline is being added through at least 2019, and if all currently announced projects materialize on schedule, “the industry could see Northeast pipeline takeaway capacity essentially double by year-end 2020.”

Following 3.5 Bcf/d of year/year takeaway capacity increases on average in 2016, Raymond James expects to see another 3 Bcf/d-plus on average in 2017 and 6.5 Bcf/d in 2018, “tracking toward 15 Bcf/d-plus of total capacity additions by 2020. When this capacity is operational, Northeast markets should open up,” alleviating pricing pressure somewhat on hubs that include Tetco, MC, Dominion South, etc. Better prices would improve exploration and production (E&P) netbacks, ultimately raising production growth.

“While many questions remain, our base outlook includes shrinking regional price spreads, growing Marcellus and Utica production, and a lid on medium/long-term Henry Hub pricing,” said the Raymond James team. “In addition to involved midstream players, this trend is positive for E&Ps with more exposure to higher risk/reward hubs.”

With its quorum still in place, the Federal Energy Regulatory Commission earlier this month approved Energy Transfer Partners LP’s Rover Pipeline, Transcontinental Gas Pipe Line Co.’s (Transco) Atlantic Sunrise expansion, National Fuel Gas Co.’s Northern Access expansion, Dominion Carolina’s Transco to Charleston Project and Tennessee Gas Pipe Line Co.’s Orion Project. However, 11 Bcf/d of greenfield projects may face challenges, BTU Analytics’ Matthew Hoza, senior natural gas analyst, said last week.

As more takeaway capacity is added into the market, Hoza said Dominion South basis would continue to tighten and reach minus 20 cents by 2022 under BTU’s base-case scenario. As of Feb. 8, Dominion South cash basis was at minus 25 cents, according to NGI data. The same day, Dominion South’s basis price for March sat at minus 45 cents, NGI’s Forward Look shows.

Raymond James expects that by 2018, Northeast blended differentials will be around 60 cent/MMBtu, which could support the region’s robust supply growth profile — but be bearish for Henry Hub long-term.

“At what price does the market balance as Northeast gas ‘backs up’ gas supplies from other regions to pressure Henry Hub? We can’t know for sure, but it appears it will be around $3.00 — our long-term Henry Hub price forecast,” Horowitz and Freeman said. “We could see Northeast prices above $2 at that time,” and the region’s producers “can find plenty of gas at those levels.”

Still, wildcards could upend the game. Analysts question the amount of production coming online from shut-in wells as prices increase, along with the timing/supply magnitude of drilled but uncompleted (DUC) wells and curtailments. Also to be factored in are newbuild pipeline costs, E&P cash flow available and the growing pushback — regulatory and environmental — against proposed pipelines.

Despite the obstacles, more gas — and more takeaway — is a given.

“Fortunately, the U.S Midwest, Mid-Atlantic, Southeast, and Eastern Canada are all moderately growing end markets,” and midstreamers are adding capacity and redirecting existing systems.

Raymond James has identified 21 proposed gas pipe projects with “true” 16 Bcf/d of takeaway potential from the region by 2020. Last year 3.5 Bcf/d was put into service. By the end of this year, another 3 Bcf/d is set to be online. In 2018, a staggering 6.5 Bcf/d of capacity is expected to be added in.

“As the build-out happens, we think Northeast wintertime gas could actually receive close to ‘premium; pricing as the combination of winter in-basin demand, and ramping takeaway capacity could leave a few pipes somewhat underutilized,” said the Raymond James analysts.

For its purposes, Raymond James assumed a differential near zero in the winter and weighed the region’s transportation costs by volume to determine summer differentials.

“We’d expect to see annual average differentials move from $1.00-plus in 2015 to nearly 60 cents by 2019,” Horowitz and Freeman said. Of course, the question as always, can producers fill the pipes?

Wide differentials in the past few years have led some to assume that new takeaway would be filled quickly but regional drilling activity has stalled. Besides, there’s no guarantee that E&Ps have enough capital to ramp up. Industry sources also suggest that the “abnormal” DUC inventory is falling.

“Given our gas demand growth assumptions, gas supplies will need to come from these Northeast DUCs, along with more drilling activity from the producers that are in a position to spend (and restarts of shut-ins and curtailments),” analysts said.

New pipeline takeaway capacity thus should be able to do its part to debottleneck trapped gas and lead to regional production growth.

“We cannot lose sight of the fact that yes, we expect incremental takeaway capacity to facilitate basis differential tightening in the Appalachia region, but it also carves a path for production growth given many operators are able to generate sizeable returns well above hurdle rates on their core acreage at the very least.”

Tudor, Pickering, Holt & Co. (TPH) analysts on Monday said their 2018 outlook for gas may be too bullish at $2.75Mcf “as associated growth and dry gas production may outpace our current model assumptions next year.”

Analysts have yet to update their supply review, but “the overall U.S. rig count is handily outpacing our expectation” and E&Ps are outspending more than expected. Rig Data estimates there are 777 rigs working, while Baker Hughes Inc. puts the count at 717. TPH had estimated an average rig count in 2017 of 658.

As expected, the Permian Basin is leading the charge, with 249 rigs spot versus a TPH estimate of 228 for the full year. “Additionally, the Haynesville Shale is now hovering around 34 spot versus TPH estimate of 25 average full-year 2017,” the TPH team said.

“Combining these factors with ongoing risk that Northeast production exceeds our current forecast as E&Ps ramp to fill new pipes, likely pushes our supply outlook higher and commodity price lower.”