At an industry conference Wednesday in Canonsburg, PA — what some think of as the Northeast’s little Houston — the story remained the same: there is too much natural gas in the Appalachian Basin and not nearly enough ways to move it to market.

Since June 2014, when oil began its rapid fall ahead of 2015, which has been marked by sub-$3 gas, Appalachian production has increased by more than 3 Bcf/d, according to one estimate presented at the Penn State Natural Gas Utilization Conference. This, even as production during the same time declined in every major onshore basin with the exception of fields in the Rockies, which have gained less than 1 Bcf/d in the last 16 months.

“If you can’t move natural gas, you can’t use natural gas,” said Tony Cox, director of UGI Energy Services Inc. midstream business development.

For about 10 years now, the Marcellus has boomed. Over the last five years, the Utica has risen to new heights, propelling the Northeast gas juggernaut higher. Yet the infrastructure rhetoric continues. Canonsburg is a regional home to many of the basin’s leading operators. In addition to UGI, representatives from Williams and Spectra — two of the Northeast’s leading midstream companies — told the crowd that most of their projects in the region have been prompted by strong demand pull.

While the downturn has forced the Northeast’s gas growth needle backward only slightly, Williams Director of Engineering and Construction Glenn Koch said his company still predicts that Northeast supply will reach 35 Bcf/d by 2025.

One industry analyst estimated that there are more than 2,000 shut-in wells in the basin — representing “billions” of cubic feet of stranded gas — hindered by a lack of takeaway, markets and depressed prices. A casual observation would seem to tie-in to that estimate; many of the basin’s leading producers have talked recently about a backlog of 25-50 or more wells that they’ll use to ramp production next year while drilling rigs await better times in the industrial dooryards of the downturn.

Cabot Oil & Gas Corp. curtailed 500 MMcf/d alone in the second quarter, mainly over a lack of takeaway in Northeast Pennsylvania (see Shale Daily, July 24). It produced 142.1 Bcfe in the third quarter (see Shale Daily, Oct. 23). Spokesman George Stark said the company is currently capable of producing another 2.2 Bcf/d of natural gas.

A component of today’s prices is obviously supply, said Eclipse Resources Corp. VP of Investor Relations Douglas Kris. Liquefied natural gas (LNG) exports; Mexican gas exports; coal-to-gas switching; the petrochemical industry, and, most importantly, pipelines were among the options discussed to work it off.

A precursor to new and expanding markets is pipelines, Kris acknowledged, saying it remains unclear if the Northeast bottleneck would start to break beginning late next year and heading into 2017 as more infrastructure is expected to come online.

The political and regulatory process has in some ways hindered coal-to-gas switching, he said, noting the apprehension that surrounds the Obama administration’s Clean Power Plan. There’s more and more opposition to pipeline projects — risking delays — and gas growth projections have been upended by the uncertainty of the downturn.

Dominion Senior Policy Advisor for Federal Affairs Bruce McKay noted the hurdles his company has had to jump over to even get construction started on Dominion Cove Point LNG, saying 250,000 comments were filed with the Federal Energy Regulatory Commission in opposition, while just 100,000 were filed in support.

“We need a better ‘why,'” Mckay said of the midstream process, adding that the “dynamics have changed in dealing with landowners.

“You have to be ready to answer the same questions over and over again. The playbook to delay [projects] is out there for anyone to see.” He added that the industry needs to focus on landowners who have not made up their minds about the possible dangers of fossil fuel projects.

“You’re just not going to convince extremists,” said another attendee who spoke about the escalating pipeline opposition across the country.

But the markets do exist, and others appear to be growing. TRC Companies Inc. VP Mitchell Bormack said Shell Chemical Appalachia LLC’s proposed ethane cracker for Western Pennsylvania would, on its own, consume about 85 MMcf/d of natural gas. He urged attendees to consider Philadelphia’s depressed industrial complex as the next horizon for the petrochemical and LNG export sectors (see Shale Daily, Oct. 28).

Director of Northeast Business Development for Spectra Energy Corp. Erin Petkovich said 75% of her company’s U.S. transmission projects are based on demand pull. Expansions and tie-ins, she said, would ultimately increase Texas Eastern Transmission’s capacity by 4 Bcf/d by 2017. The Marcellus Shale is currently flowing about 5 Bcf/d into the 10.38 Bcf/d system. About 30% of all Appalachian supply flows into Texas Eastern, she said.

Appalachian gas has uses at all four points of the map, presenters said. McKay said 96% of the proposed Atlantic Coast Pipeline, which has been designed to move gas to the Southeast, is subscribed by power generators and utilities.

Small things could help, too. Bormack added that efforts are being considered in Southeast Pennsylvania to build up the virtual pipeline to help store and move more LNG and propane by road. That, he said, could help eat some supply and prevent the propane shortage and wild price spikes that occurred during the brutal winter of 2013-2014.

“As we think about the year we’re walking out of, there’s been a number of challenges. No. 1 in that is lower prices, I think most would agree,” said Penn State Marcellus Center for Outreach and Research Director Tom Murphy. “But it also speaks about the number of opportunities we have for creating better markets…This is very much a global area, too.”

Nearly 250 people attended the fifth annual utilization conference. That was up from last year, reflecting interest in end-use markets — even during the commodities downturn — according to organizers.