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11 Bcf/d of Greenfield Appalachia Projects Face Challenges, Some Delays

Even as the Federal Energy Regulatory Commission greenlighted a slew of natural gas pipeline projects last week that would bring online more than 5 Bcf/d of takeaway capacity, infrastructure development will face headwinds amid ongoing regulatory uncertainty, drilling location availability and slower production growth, according to BTU Analytics’ Matthew Hoza, senior natural gas analyst.

Speaking in Houston at BTU’s annual “What Lies Ahead” conference, Hoza said that while the Federal Energy Regulatory Commission’s recent pipeline approvals were welcome news, other projects -- such as Spectra’s Nexus Gas Pipeline, EQT’s Mountain Valley Pipeline and Dominion’s Atlantic Coast Pipeline -- remain in limbo as the retirement of former Commissioner Norman Bay leaves the FERC without the required quorum necessary to approve such projects.

Some 11 Bcf/d of takeaway capacity has been proposed in Appalachia, including the projects approved last week and others still awaiting approval. Three commissioners are needed to approve pipeline projects and to make other important decisions. FERC has a total of five seated positions.

FERC’s approvals last week included Energy Transfer'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.

Even with FERC approval, however, Energy Transfer’s 3.25 Bcf/d Rover Pipeline will likely be delayed a year to November 2018 as the tree clearing window for that project ends March 31; the pipeline would need to receive its notice to proceed within the next two weeks in order to make that deadline, Hoza said.

But FERC has indicated that notice would not be issued until a satisfactory conclusion is made regarding an issue related to the Stoneman House in Ohio. Rover's review hit a snag when FERC learned last fall that the company had demolished the historic Stoneman House without notifying the Commission. The home was near a proposed compressor station and would have fallen within the visual area of potential effects for the project. FERC is now corresponding with the Advisory Council on Historic Preservation on how to address the situation.

“It’s out of their hands,” Hoza said regarding Energy Transfer’s timeline for building Rover. “Where we are now, there is too much risk to bump that in-service date up [from BTU’s expected in-service date of November 2018].”

Nexus, which is about only 60% committed, also could be delayed by a year or more as FERC did not OK that project, despite it having received a favorable environmental impact statement in November. The 1.5 Bcf/d pipeline would deliver gas from receipt points in eastern Ohio to existing pipeline system interconnects in southeastern Michigan.

Meanwhile, EQT’s Mountain Valley, Dominion’s Atlantic Coast and PennEast Pipeline are among those whose futures are up in the air as approvals have yet to be granted, and some of the projects face strong opposition.

“PennEast is public enemy No. 1,” Hoza said. “There is heavy regulatory and public opposition. This is definitely a project in the eyes of the wider public where they are being vocal about it.” PennEast was expecting to receive a FERC certificate of approval in July.

If these projects ultimately move forward, wellhead economics will be challenging as much of the high-quality acreage in the region is depleted. “Previously delineated inventory is finite and will play an increasingly important role in production growth and setting U.S. natural gas prices,” Hoza said.

Producers could turn to portions of Pennsylvania, West Virginia and Ohio that have not been developed and could increase inventory. The dry Utica also offers some possibilities, although drilling results from this area have thus far proven inconsistent and cost prohibitive, he said.

But even under a scenario where Nexus, PennEast and MVP are all cancelled -- effectively taking 4.5 Bcf/d of takeaway capacity out of the picture -- production would continue to grow, Hoza said. Pipeline utilizations would be higher in this scenario, he said.

Appalachian production receipts (over 20 Bcf/d) have quadrupled in the last five years, thanks to takeaway additions in the Northeast, increasing Appalachian demand and displacement of inbound gas. BTU expects Appalachian production to reach 32 Bcf/d by 2022 as the market is on the cusp of a rebound in drilling activity after a downturn because of lower prices.

Marcellus/Utica activity declined some 75% after gas prices fell to some of their lowest levels in years. And while producers turned to drilled but uncompleted (DUC) wells to bring on production at a lower cost, that inventory is all but exhausted, Hoza said.

“We saw a fast drawdown in excess backlog. Numbers have fallen off so steeply that you don’t have DUCs to turn to in order to turn on production quickly,” he said.

As such, Hoza said that when future pipeline projects come online, the market won’t see a big jump in volumes as it did when DUC inventories were higher. He noted the Rockies Express pipeline zone 3 expansion as an example where production took on more of a “meandering growth” trend once the expansion entered service.

And while the gas rig count is increasing, Hoza said additional drilling activity is needed to meet demand. “If we take current rig counts, 62 rigs, and take it forward, it doesn’t get us to where we need to meet our forecast. But we expect drilling activity to continue to pick up,” he said.

In fact, even as drilling slowed in 2015 and 2016, the number of permit filings did not, he said. As of January, there were about 4,000 outstanding permits. Hoza did not perceive the number of outstanding permits as a constraint, though, as drilling permits typically have a shelf life of a few years.

So what does this mean for gas prices in Appalachia? As more takeaway capacity is added into the market, Hoza said Dominion South basis will 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 NGIdata. The same day, Dominion South’s basis price for March sat at minus 45 cents, NGI’s Forward Look shows.

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