Source: Energy Intelligence Group, Tom Haywood, June 8, 2020
Sponsors of two long delayed Appalachian gas projects -Mountain Valley Pipeline (MVP) and Atlantic Coast Pipeline (ACP) are inching forward, armored by a conviction that their combined 3.5 billion cubic feet per day of capacity will find a ready market in the Southeast.
But both were conceived in a much different world, and their ultimate success could depend as much on global oil and gas supply dynamics as regional demand.
US LNG export terminals have pulled the US deeper into the global gas market, which has proved much more mercurial than LNG advocates expected a decade ago. US facilities can liquefy and export almost 9 Bcf/d, and once all the projects under construction come on line, capacity will grow to 13.7 Bcf/d, or more than 17% of current US gas demand.
This fact alone would seemingly buttress a growing call on more capacity to move abundant Appalachian supply to those terminals. But LNG feed gas demand has and should continue to prove lumpy -surging to 9.5 Bcf/d in midMarch and then plunging to 3.7 Bcf/d early last week in step with gas market developments in Asia and Europe (related).
And that adds a new layer of uncertainty to the prospects for ACP and MVP, which would feed gas into an expansive grid that ultimately serves various export projects.
But the biggest wild card centers on associated gas in oily US shale plays, which has flooded the market in recent years only to have volumes plunge as global crude demand and prices tumbled. It’s not clear how long crude prices will stay at levels that discourage associated gas growth, but it is certain that the burning need for MVP’s 2 Bcf/d and ACP’s 1.5 Bcf/d of capacity could hinge on the speed of that recovery (NGW Jun.1’20).
“Both projects are needed if the forward curve of oil is between $35 to $40,” East Daley Capital Senior Director Matthew Lewis told Energy Intelligence. “Then, you very likely need more egress projects to grow the Northeast to meet US demand. If one or both pipelines don’t happen, you have to rely on other basins to meet US natural gas demand, like the Haynesville Shale.”
A forecast for robust Appalachian gas output in 202123 should allay any concerns about supply availability to fill MVP and ACP. Energy Intelligence’s Research & Advisory (R&A) unit estimates show gas output rising modestly to 32.4 Bcf/d next year before climbing to about 34 Bcf/d and 36 Bcf/d in 202223, respectively.
Those increases depend on regional prices rising into a $3 per million Btu range they have been trading at half that level this spring and that would require a continued pullback in associated gas and improved global LNG demand, R&A Director Abhi Rajendran said.
“Producers can give you a lot more gas if you can build access to consumer,” University of Houston Economist Ed Hirs said.
That’s especially true for ACP, Hirs said, as it would deliver gas to the Virginia market. ACP is led by Dominion Energy and backed by other utilities notably Duke Energy making it something of a rarity since the anchor shippers and key customers are one and the same.
Also, there is little doubt that they are looking at that supply to boost efforts to eliminate coal generation as they work toward goals to radically reduce carbon emissions by midcentury (related).
“Virginia has made great strides in building gasfired plants and pushing out coal plants,” Hirs said, adding that netzero carbon goals do not preclude gas in the capacity mix. “Utilities also have offsets and carbon remediation investments they can make. Zerocarbon does not imply they are going to stop burning natural gas.”
Another key advantage is that both lines would connect to the Transcontinental Gas Pipe Line (Transco) system. This gives Appalachian supply new access to Southeast markets, as well as the Northeast, Lewis said. In the process, it could back up gas into the Gulf Coast region where it can serve rising LNG export and industrial demand.
Ken Medlock with Rice University’s Baker Institute also highlighted what access to Transco zones 4 and 5 could mean. “That gives you access to more than the utilities,” he said. “The ability to get to the Transco system opens up optionality of delivery.”
That includes to Dominion Energy’s Cove Point LNG terminal in Maryland, which can export as much as 0.7 Bcf/d of gas, and current LNG export constraints created in part by the coronavirus pandemic might not dampen that advantage long term, Medlock said. “We’re living through a black swan event and it’s hard to extrapolate that for the next 20 years.”
Will ACP Finish the Race?
Still, time hasn’t been a friend to either pipeline project, with each mired in years long regulatory wrangling and fierce green opposition. However, the 300 mile MVP project is 90% done and could open late this year if it can clear two regulatory snags, according to sponsor EQM Midstream Services.
ACP is not so fortunately situated and grows more vulnerable to cancellation as its budget balloons and a regulatory morass makes its completion date ever more opaque.
When ACP was first proposed, it was to cost $4 billion and be in service in 2019. The cost of the stalled line has since doubled to $8 billion and operations won’t begin for at least another year and a half under the most optimistic scenario.
ACP is awaiting a US Supreme Court ruling that would allow it to cross the Appalachian Trail and, like MVP, needs the US Fish and Wildlife Service to complete a review of how to mitigate harm to endangered and threatened species along the pipeline route. That action brought construction to a hard stop on both pipes as they work to restore the vital federal permit (NGW Dec.17’18).
ACP “was under active construction throughout most of 2018 until we suspended construction just before Christmas of that year,” Dominion spokeswoman Ann Nallo told Energy Intelligence. “During that time, we made good progress across 300 miles of the route with tree clearing, digging trenches and laying pipe, and building associated infrastructure such as M&R stations and offices. We anticipate resuming construction later this year and being inservice for consumers by early 2022.”
But Lewis still gives ACP a 50-50 chance of being canceled if costs continue to climb and regulatory delays persist.
“It’s a bit of a different scenario than Mountain Valley, where most of the capital costs has been spent and it’s more a time issue,” Lewis said. “Since ACP is not as far down the path I think there’s a bigger question on if the sponsors
want to continue this process just because there’s a lot more money to be spent going forward.”
Medlock agrees ACP could be vulnerable to cancellation just as any infrastructure project would energy or not.
“If your actual physical construction cost begins to climb because of legal delays and other things, those delays become expensive because you have to take out debt to build these things and the banks just don’t disappear and give you a holiday,” Medlock said. “So there comes a point when you start looking at what’s the cost of ceasing because at some point if you’ve already spent a big chunk of money it’s not as simple as saying the rates aren’t going to cover the cost, it really is how much of the overall cost am I going to recoup if I can get this thing finished so I can service that debt.
“At some point, you’re not so much concerned about profit as you are about avoided costs, which is why sometimes these things just hang on,” he said.