At recent commodity prices, Lower 48 natural gas production will zoom past 100 Bcf/d over the next five years, leading to an oversupply that will drive down prices in the volatile Western spot markets as exports out of the Gulf Coast pace demand growth, according to RBN Energy LLC.
In a webcast for clients this week, RBN’s Rusty Braziel took a look back at the recent extremes in the natural gas spot market -- including $200/MMBtu gas at Northwest Sumas and negative $9.000 gas in West Texas. He also laid out the firm’s projections for the years ahead, as rapid growth in both supply and demand foretell big changes for pipeline flows and pricing dynamics.
The rapid expansion of liquefied natural gas (LNG) export capacity this year figures to bring “huge changes” to a North American market already experiencing unprecedented price events.
“Over the next year, we’ll see the largest increment of export capacity ever added. That will come online with 5 Bcf/d of capacity being added at five facilities all along the Gulf Coast,” Braziel said. “Most of that capacity is going to fill up within a few months of start-up, resulting in the most rapid rate of growth in natural gas exports we’ve ever seen.
“Those exports are going to drive huge changes in flows, pipeline capacity and, of course, pricing. And that’s coming behind the winter 2018/2019 gas market, which I would argue has been one of the most chaotic we’ve experienced already.”
Based on RBN’s outlook, the market may need every bit of that export growth to help soak up the supply set to come online over the next few years.
RBN projects that at $2.75 Henry Hub and $55/bbl West Texas Intermediate prices at Cushing, Lower 48 dry gas production will climb to 108 Bcf/d between now and 2024, averaging out to 3.6 Bcf/d of growth each year.
The start-up of projects like the Rover Pipeline, Nexus Gas Transmission and Atlantic Sunrise have helped debottleneck the Marcellus and Utica shales, as evidenced by narrower basis differentials at hubs like Dominion South and Tennessee Zn 4 Marcellus.
“Marcellus and Utica producers have successfully pushed their oversupply into the Gulf Coast and Midwest, at least for now. What about over the next five years? All that depends on the trajectory of production growth, and we see more production growth coming,” Braziel said.
According to RBN’s projections, that growth will come in part from the Bakken Shale, the Denver-Julesburg/Niobrara, the Anadarko Basin and the Eagle Ford and Haynesville shales. But the “big increases” will come from the Permian Basin and the Marcellus/Utica, to the tune of 7.4 Bcf/d from the former and 9.8 Bcf/d from the latter.
“That means 70% of all natural gas growth is going to be coming over the next five years, by our numbers under that pricing scenario, from those two basins,” Braziel said. But it’s also important to note that “the economics for five of those seven basins are being driven not by gas prices but by oil, and that has the potential to wreak havoc with gas prices if for any reason gas demand does not cooperate.” This could lead to “the same kind of thing we’ve seen in the Permian.”
In a clear illustration of the potential inverse relationship between crude oil and natural gas prices amid supply growth in the U.S. onshore, the glut of associated gas output has continued to crush spot prices in the Permian. Prices this week have descended to previously unimaginable lows, reaching negative $9.000/MMBtu in Wednesday’s trading.
RBN’s modeling shows Permian gas production rising to close to 10 Bcf/d in recent days. This is up sharply over just the last few years, from just around 5 Bcf/d in 2016. That figure climbed to 7 Bcf/d by January 2018 before “astronomical growth” of close to 2 Bcf/d last year.
“And that is happening regardless of capital spending cuts you hear so much about,” Braziel said. “Yeah, they’re spending less, but they’re producing more. That’s clearly what we’re seeing in the market today.”
All this production has to compete for space on four pipeline corridors that, even after accounting for flaring, have left the West Texas market far from balanced. These include:
- 3.0 Bcf/d west on Transwestern and El Paso Natural Gas;
- 1.8 Bcf/d north on Natural Gas Pipeline Co. of America and Northern Natural Gas;
- 3.7 Bcf/d east on Texas intrastates;
- And 3.1 Bcf/d south to Mexico, but flows closer to 0.4 Bcf/d due to constraints south of the border.
“Total all that up, and there’s about 8.9 Bcf/d of capacity out there for around 10 Bcf/d of production that’s crossing the meter into all of those pipelines,” Braziel said. “Even with 1 Bcf/d of local demand, it’s obvious that capacity out of the region is absolutely maxed out.”
There is some good news on the horizon for prices in the Permian, a basin that “needs some good news.”
“Relief is coming, in the form of new pipes,” Braziel said. “Unfortunately, not right away.”
The next major natural gas pipeline expansion is expected to come from Kinder Morgan Inc.’s 2 Bcf/d Gulf Coast Express (GCX), slated for start-up in October.
“GCX is going to take a lot of pressure off Permian pipes, but it’s not going to last long,” Braziel said. “We expect that the pipe is probably going to fill up within the next nine months, maybe sooner. At that point, there’s a pretty good chance the Permian’s going to be right back in the same fix that it is now.” After GCX, “there’s another pipe that is expected to come to the rescue.”
That would be the 2 Bcf/d Permian Highway Pipeline (PHP), a project of Kinder Morgan Texas Pipeline LLC and EagleClaw Midstream Ventures LLC that is set to come online in the second half of 2020.
EagleClaw on Wednesday also pulled the trigger on Delaware Link, a pipeline with at least 1.2 Bcf/d of capacity that would transport residue gas from the Permian to the Waha hub, with access to downstream takeaway connections. Interconnections would include direct access to PHP.
Once online, PHP could take the pressure off of Permian gas constraints for another one to two years, according to Braziel. Eventually another pipe likely would be required, and there’s a list of potential projects in the works.
“Who gets built and when that gets built is going to have a big impact on the Permian market,” Braziel said. “The implication is that there’s going to be a continuing roller coaster for Permian basis, Permian prices, as far as you can see.”
As associated gas growth wreaks havoc in the Permian, and as supply pushes out of the Marcellus and Utica, this stands to back up production from the Rockies and Western Canada, according to Braziel.
“The West is going to be dealing with a lot of downward pressure on prices...all of that flow from the Marcellus/Utica needs to go someplace, and a lot of it will be moving into the Midwest, which is already served by gas from the Rockies,” he said. In turn “gas is going to get pushed back into the Rockies, and that’s going to drive western prices lower. The Permian is going to continue to grow. Granted, a lot of that gas is going to be moving to the Gulf Coast on new pipes, but there’s still a lot of molecules that are going to need to move west into California, just like it happens today.
“Unfortunately, California doesn’t want any more gas, at least not over the longer term...and that’s going to make it difficult for both Rockies and Permian gas in order to get incremental supply into those markets.”
And then there’s Canadian supplies.
“They’ve already been pretty much pushed out of the Northeast, and they have nowhere to go except to markets that are otherwise served by Rockies and other gas supplies in this area,” he said. “Bottom line: Western gas prices are going to be under pressure for a long time, assuming all their infrastructure holds up.”