Never Been Any Reason, Encore Edition - Why Oil, Gas and NGL Infrastructure Investment is Soaring While Production Growth is Flat

Monday, 05/27/2024 Published by: Rusty Braziel rbnenergy.com

Excerpt, link to full article: https://rbnenergy.com/never-been-any-reason-encore-edition-why-oil-...

There’s never been any reason to question the drivers for energy infrastructure development — until now.  Historically, the drivers were almost always “supply-push.” The Shale Revolution brought on increasing production volumes that needed to be moved to market, and midstreamers — backed by producer commitments — responded with the infrastructure to make it happen. But now things seem to be different. U.S. energy infrastructure investment is soaring across crude oil, natural gas and NGL markets and, as in previous buildouts, midstreamers are bringing on new processing plants, pipelines, fractionators, storage facilities, export terminals and everything in between. We count nearly 70 projects in the works. But crude production has been flat as a pancake, natural gas is down, and lately NGLs are up — but as you might expect, only in one basin: the Permian. So what is driving all the infrastructure development this time around? In today’s RBN blog, we’ll explore why that question will be front-and-center at our upcoming School of Energy: Catch a Wave. Fair warning, this blog includes an unabashed advertorial for our 2024 conference coming up on June 26-27 in Houston. 

Anemic Production Trends

Let’s start with the first part of our basic premise — production of what we refer to as the three drillbit hydrocarbons has been mostly flat. As shown in the left graph in Figure 1 below, U.S. crude oil production today stands at 13.1 MMb/d. In fact, it's averaged 13.1 MMb/d for the past 10 months. Lower 48 natural gas production (middle graph) inched higher last year, up to an all-time record of 105 Bcf/d in December, but has steadily declined this year to about 96 Bcf/d (dashed green circle), back to where it was two years ago, in May 2022. The one bright spot is NGLs (right graph), up about 7% from the first half of 2023 to an average of 6.7 MMb/d over the past 12 months.

What explains these production trends? Well, it’s different for each commodity group. For crude oil, the blame goes to the Permian. Ever since the first Shale Era oil price crash in 2015, the Permian has been the only growth engine of U.S. crude. All other basins have been flat or down. So when Permian growth flatlined last year, so did U.S. crude production. As we discussed in All My Rowdy Friends Have Settled Down, no single factor is responsible. Capital discipline is still a thing. Hand wringing about the possibility of acreage depletion — i.e., declining inventories of Tier 1 acreage — is a factor too. And industry consolidation is certainly another culprit. But the issue that’s in the face of many Permian producers is natural gas takeaway capacity. You can’t grow crude oil production if you can’t move the associated gas.

U.S. natural gas production is not just flat — it’s down. Again there’s more than one reason. For one thing, pipeline takeaway constraints and local opposition to pipeline construction has effectively neutered the most prolific gas-focused basins in the U.S. — the Marcellus and Utica. On top of that, for the past year a slowdown in LNG terminal development has constrained natural gas export capacity and contributed to very low gas prices since Q1 2023, which in turn has discouraged drilling for dry gas that does not come along with much crude or NGLs — the Haynesville being a prime example. And then there’s the problem with Permian gas takeaway. It’s pretty easy to see what that has done to the market. The price of gas at the Waha hub in West Texas has averaged -$1.25/MMBtu — that’s a price below zero — for the past six weeks due to lack of capacity out of the basin.

And then we have our bright spot, NGLs, which are growing even though natural gas production is down. That’s because the gas production declines are mostly in dry gas basins with little NGL content (again, like Haynesville and, to a lesser extent, Appalachia). Associated gas production is growing in the crude-focused Permian, where the production is getting gassier, NGL content is increasing, and midstreamers are building a lot of super-efficient, deep-cut gas processing plants that yield increasing volumes of NGLs. NGL production in all other basins is flat or down.

What’s happening with NGLs is a great example of what’s going on in all of the drillbit hydrocarbon markets: All energy infrastructure is local. It doesn’t matter if production is declining elsewhere. If there are pockets of production growth that exceed local takeaway capacity, midstream development will advance. And that is just what is happening in a number of important regional markets. Enabled by the dose of reality that energy infrastructure and security will continue to be of paramount importance for decades to come, there has been a renewed interest by investors in the midstream sector.

Catch a Wave of Energy Infrastructure Development

We are not kidding when we say that there are a lot of energy infrastructure projects in the works across North America. As shown in Figure 2, we are tracking 67 major projects, mostly concentrated along the Gulf Coast, but not entirely. Our database includes 34 pipeline projects: four to provide crude oil service, plus 21 natural gas pipes and nine NGL pipes. There are 12 LNG and NGL export terminal projects either under construction or with final investment decisions (FIDs) in hand: five in Texas/Louisiana and three in Western Canada. We're also tracking six new fractionator trains — all in Mont Belvieu — as well as 13 gas processing plants (mostly in the Permian) and two petrochemical crackers, one on the Gulf Coast and another in Canada. Beyond that, we also have new gathering system expansions, underground storage projects, and natural gas-consuming industrial projects.

For the most part, local market conditions are driving the new energy infrastructure development. Almost all energy infrastructure gets built to relieve a capacity constraint. The constraint might exist today, or the market might expect that a constraint will develop in the future. Those constraints are different for each commodity group and for each geographic region. For natural gas, the leading constraint today is quite obvious: Permian natural gas takeaway. But contributing to the upside-down Permian market are weak gas prices across the U.S. due to constrained LNG export capacity. There are a slew of pipeline projects targeting those LNG exports, concentrated in Louisiana and East Texas but popping up all along the Gulf Coast.

For NGLs, it is production growth that has created capacity constraints all along the value chain. But again, the problems are very localized — here we mean the run from the Permian to Mont Belvieu and on to Gulf Coast ethane and LPG export facilities. New and expanded NGL pipelines out of the Permian are in the works, along with fractionators to handle the liquids and export facilities to ship the purity products to global markets. Even more localized constraints are impacting crude oil infrastructure development, such as the currently constrained Permian-to-Corpus Christi corridor, which will be addressed by an Enbridge-led project that just went open season earlier this month but could be erased when and if Enterprise’s deepwater Sea Port Oil Terminal (SPOT) comes online.

Understanding these developments and all the other projects we cited in Figure 2 are what energy market fundamental analysis is all about. It is what makes price differentials move, which in turn is what drives energy infrastructure investment. Bottom line: These relationships determine which assets get built, what trades get done, and ultimately who makes money. It’s what we cover in depth at RBN’s annual School of Energy.