The other hardest part of building a new pipeline

Permitting is only half the story — the commercial model broke first

Everyone blames regulators for blocking new pipelines, and with good reason. But permitting isn’t the only intractable constraint, and sometimes not even the most important one. The commercial model that underwrote the shale-era build-out broke quietly years ago and hasn’t been replaced yet. Understanding why that happened explains as much about today’s pipeline development challenges as any court case or NEPA fight.

How pipelines used to get built

For years,¹ utilities — and by extension, ratepayers — backstopped natural gas pipeline capacity development. That changed in the mid-2000s, when high gas prices brought two major changes in the market:

1. Flat demand, meaning utilities no longer needed incremental gas pipeline capacity

2. A supply shock, as horizontal drilling and hydraulic fracturing unlocked the Barnett and later Rockies tight gas plays

As shale volumes grew, producers needed to backstop pipeline capacity to avoid selling into depressed regional markets. They contracted for the expansions that moved growing Barnett volumes; for Fayetteville Express and Texas Gas’s Fayetteville Lateral out of Arkansas; the Arkoma Connector and MidContinent Express out of Oklahoma; and most significantly, the $5+ billion Rockies Express.

In these cases, producers didn’t necessarily expect their pipeline commitments to make money on their own terms. Once you debottleneck a basin, then basis differentials reflect the variable cost of transportation. But they backstopped this capacity nonetheless, because the upside on their in-basin sales, with narrower basis differentials, more than outweighs what they would lose on netbacks for the gas moving on the new pipeline.

Why the producer-backed pipeline development model broke

And that model would have worked forever if it were just about the collapsing basis spreads. Much more pernicious for E&Ps was that the gas price level across the continent was falling. And the combination of fixed FT commitments and a falling Henry Hub price contributed to several E&P bankruptcies.

In the case of Rockies Express, the commercialization of the Haynesville and Marcellus on the left side of the gas supply curve brought Henry Hub prices down sharply. Paying $1.65/MMBtu in demand on REX is one thing if Henry Hub futures are more than $7.50/MMBtu, as the 2010-11 contracts traded in 2006, when REX began construction. It’s another at ~$4.25/MMBtu, the average Henry Hub cash price those years, once REX was fully in service. Ultra Petroleum, on the hook for 200 BBtu/d, was a casualty.

In the case of Rover Pipeline (and other, smaller Northeast debottlenecking projects), it was both:

• The commercialization of a newer, lower-cost gas supply source—in this case, associated gas from the Permian

• That Rover’s in-service itself reduced the equilibrium gas price across the continent

When EnergyTransfer filed Rover’s FERC application in February 2015, 2018-20 Henry Hub prices traded at ~$3.75/MMBtu, versus the ~$2.60/MMBtu they ultimately averaged during this period. Here, Gulfport was a casualty.

Some producers² smartly anticipated that Rover’s in-service would not just collapse Appalachian basis differentials but also weigh on Henry Hub prices; they hedged long-dated Henry Hub prices alongside contracting for Rover capacity. But Rover capacity commitments last 15 years, whereas the market is only liquid for about five, much of it during construction. Even Antero, with its pristine hedge book, teetered on the brink of bankruptcy. Its bonds traded at very distressed levels, and the company sold an overriding royalty interest to survive until gas prices shifted structurally higher.

What it means for the future

Some producer-backed pipeline capacity has been commissioned in the years since, but the key difference is that none of it carried demand charges of $0.75/MMBtu or more. In other words, producers can afford to pay $0.25-0.35/MMBtu to move their Haynesville gas to a better market, or even $0.50-0.60/MMBtu to move their Permian gas to the Gulf Coast. But the two lowest-cost gas basins — Appalachia and the WCSB — are so far from market that even a compression expansion likely would require demand charges north of $0.75/MMBtu.

The pre-2005 pipeline development model was viable in all basins, with producers taking the commodity risk on gas prices and utilities owning the risk on spreads. The 2005-17 model worked only as long as:

• No new low-cost supply sources were discovered and

• Debottlenecking projects themselves didn’t structurally shift prices downward in delivered markets

Ironically, those latter two conditions are likely to be in place over the next 10 years, in a way they weren’t for the last 10. But producers have learned their lesson,³ leaving that new model of producer-backed long-haul pipeline development fundamentally broken for the two lowest-cost gas basins.

And that is the immediate challenge for new pipeline development out of Appalachia or western Canada. A Rover expansion — or the Borealis project currently on offer from Texas Gas — wouldn’t face stiff environmental opposition in Ohio, Indiana, and Kentucky. But producers with lots of inventory in constrained basins don’t expect that capacity to deliver returns over the life of the commitment. Utilities, meanwhile, see their existing pipeline portfolios as sufficiently well-diversified and low-cost.

It is, of course, true that New York State’s refusal to grant water-crossing permits for Constitution was an egregious abuse of the Clean Water Act. And the environmental left indeed weaponized the National Environmental Policy Act to put MVP on its deathbed, until Joe Manchin more or less singlehandedly resuscitated it.⁴

Bigger picture, it’s true that gutting NEPA⁵ is critical to both the long-run viability of the US energy system and, for that matter, to the US economy more broadly. And it’s even true that gutting NEPA could have a significant enough impact on pipeline development costs to potentially move some projects from the “too expensive for producers” category to the “maybe we can stomach it” bucket.⁶

The problem now, though, is that gas demand is growing again, and quickly. But the two main sources of growth — merchant LNG and merchant power — don’t have a rate base to backstop expensive pipeline development either. And it’s this commercial model, at least as much as regulatory challenges, that has made long-haul transmission development so difficult in North America for the last eight years.

If you’re seeing this because it’s circulating in your inbox or Teams channel, you can subscribe directly at www.measureddepth.com. In the next part of this series, we’ll explore some signs of a new economic model emerging.

1. Decades, actually

2. Most significantly Antero

3. Maybe over-learned it

4. Even though everyone agrees with this, I’ve not heard anyone acknowledge the readthrough, which is that the industry was better off with a West Virginia Democrat in the Senate than it would have been with another West Virginia Republican. Or, more relevant in the future, whether the industry might be better off with, say, a Democratic senator from Texas, Louisiana, North Dakota, or Alaska.

5. Some say “reform,” but let’s be honest about what we’re talking about here

6. I thought the point Alan Armstrong made earlier this year, that even for a pipeline that isn’t extensively litigated, permitting can cost twice as much as steel, was the most interesting and under-discussed quote of the year.