Teri Viswanath: As both U.S. natural gas production and consumer demand for the fuel grow, the need for pipelines increases. A lack of pipeline development creates difficulty in moving the fuel across different regions, and this constraint is a primary contributor to regional price differences. The regional difference are becoming more pronounced, with deviations over the past two years the largest we’ve ever witnessed.
Hello, I’m Teri Viswanath, the energy economist at CoBank and your co-host of Power Plays. For this conversation, we reached out to the principals at RBAC, a leading software and energy consulting company. In fact, RBAC’s GPCM software is perhaps the most recognized software for predicting future regional natural gas prices—the prices that have the most influence on your cost of natural gas.
For this conversation, you are going to hear from Bethel King, she is a research manager at RBAC along with the founder of that company, Dr. Robert Brooks. As always, I’m joined by my co-host and a managing director here at CoBank, Tamra Reynolds. Hey, Tamra.
Tamra Reynolds: Hey Teri. The last time we had an opportunity to discuss the U.S. natural gas market was during the fall of 2022, when we faced very different market conditions. During that year the average price of spot delivered natural gas in the Gulf was roughly $6.50. In 2023, Henry Hub prices averaged around $2.50, and this year (barring any extreme event) we see similar prices. But this all begs the question of whether we might be experiencing the last innings for very low-priced natural gas.
Viswanath: That’s right. I’ve been thinking about that question for some time, wondering if we are going to face structurally a higher fuel price market in the future. In a comment I wrote last year, I noted that there were simply less opportunities for fuel-switching in the power sector. And, that supply bottlenecks, from a light gas pipeline development cycle and under investment in production acreage, would ultimately contribute to very tight natural gas marketplace and much higher energy bills.
Reynolds: And another important contributor to future scarcity pricing might be the amount of natural gas being exported and increased demand for power to address the insatiable appetite of data centers.
On the export front, the U.S. has mostly operated as a natural gas island. The domestically produced supply was sufficient (or nearly sufficient with help from Canada) to meet the nation’s requirements. The limited international trade that took place mostly was cross-border pipeline balancing within North America.
From a pricing perspective, domestic consumers only experienced brief periods of sustained high prices, like the one I mentioned in 2022. But the rapid shale production boom has led to the equally large development of LNG export facilities to absorb the excess. That development will fundamentally change the way domestic gas is priced. But when?
Viswanath: You're right. In a more constrained energy resource world, we are going to see greater nuance — that is, volatility and high prices. And, even though we have a market that is currently well supplied, there are important regional differences that consumers need to pay attention to.
FERC identifies five distinct regions of the country: the Gulf (really Texas and Louisiana, historic supply states, that are also going to be in the future important export states); the Midwest (both a supply region with mid-continent production but also a very important heating demand region), and then the mostly demand-centric regions of the Northeast, Southeast and Western states.
Tamra, our conversation on the regional gas prices begins with your question to Bob about whether we are seeing the last innings of low prices and he focuses in on the nation’s regional epicenter for price weakness, which is West Texas. Following Bob’s comment, you are going to hear Bethel chime in about the particulars. Here is that conversation.
Reynolds: Do you think that this might be the last chapter of really low-priced shale gas?
Robert Brooks: I think most eyes these days are on Texas and in the Permian in particular, which is, strangely enough, not shale gas. It's actually tight oil and associated gas being produced from tight oil. So it’s actually a different thing, that is I think, the main reason for low prices and even negative prices at times, which is that oil prices are so high right now that producers, they want to produce oil and they want to move oil into markets because they can get very high price for oil right now.
But the scene is that there's a lot of gas that gets produced with the oil. This is called associated natural gas, and there's nothing you can do about it. The producers would just soon not have it, but it's there. In the old old days, they used to just either vent it or flare it, because it didn't really have any particular value. In today's environment, you cannot do that, legally you cannot do that. That means you are stuck in this situation where you want to get the oil out. You've got a bunch of gas, and the amount of gas that you have is possibly and likely to be more than what the market needs, which means that its price goes down, down, down. It even at times gets to the point where you have to pay people to take it away.
Bethel King: In particular, we've seen not only negative prices, which we've certainly had that historically over time, different ups and downs in the market. What's kind of unique lately is that we've gone negative for the entire month. Not just a few days, cold snap, or some outage or something like that. Part of that has to do with so much associated gas out there. That gas to oil ratio is just getting larger as that field matures. That's the normal life cycle.
In addition to that, we've had some bad timing as far as, well, I say bad timing if you're a producer out in the Permian areas, bad timing but some outages, some big maintenance, Permian Highway, Gulf Coast Express, and then it's some normal stuff too, El Paso, NGPL.
What's happening is even though some of these outages are short-lived, one week, two week, they're pancaking on top of each other. They're overlapping, and it's just constraining an already constrained area.
Reynolds: As we are wrapping up our July podcast, the Gulf Coast (Texas coastal counties in particular, Brazoria, Galveston, Harris, Montgomery) are all recovering from Hurricane Beryl with more than a million consumers currently without power, but some of the largest energy consumers on the Gulf Coast are actually these LNG export facilities. Our guests reflected on the pricing implications for these mega-loads and how they impact pipeline flows in the region.
King: I think one of the things that's really unique that's happening in the market right now is we're finding a null point along the Gulf Coast. We've got Permian and East Texas, Western Louisiana gas coming over to serve that coastal LNG export market, which is growing and everybody's trying to thread the needle on timing of production versus those starting. We're also seeing gas coming down from Appalachia.
That's another constrained area. They're wanting to get that gas down south. What we're seeing is we're seeing this null point move back and forth along the Louisiana, Mississippi, East Texas area. That's an area that we've really been trying to focus on. When we saw Freeport go down before, what we saw is it pushed the East Texas, Waha prices, and even some of the Western Louisiana prices down. Then we saw the Eastern Louisiana prices pop. Because you can't get there from here.
Brooks: Freeport is one of the biggest LNG export terminals in the Gulf Coast. It had two out of the three trains there were down at one point, and I think the third one was down at another point. The feed gas that it could take from producers was essentially zero for a while.
The more of these LNG facilities that you get, just think about this, the more that there are, just on the basis of probability, you are going to get situations that occur from time to time. If that is true, if one of them goes down and you're already on that knife edge of just maybe too optimized in terms of the feed gas into these terminals, then you could get into that situation again, where essentially you back it up because the demand is not there and there's no place to put it. If storage is basically full, then you are getting this situation where that marginal gas is worth very little or even negative to get rid of.
Viswanath: Tamra if you consider the Gulf region a few decades ago when Hurricane Katrina and Rita struck, there was a terrific rally in natural gas prices on the Gulf, because of the disruption in offshore supply. In fact, as a result of that period of really high prices and volatility, a number of new natural gas storage facilities were built to act as a supply buffer or supplement when offshore production was offline. What Bob and Bethel are talking about is the fact that these facilities can now act to absorb some of the gas when these LNG facilities are not available. The more flexible characteristics of these storage facilities really meets a ‘use case’ that was not envisioned when they were built.
But, more generally, the domestic market looks vastly different than it did before the shale boom. The country produces almost double the amount of natural gas it did back in 2006 and total exports now account for one-fifth of that production. In the next five years, upwards of 90% of gas demand growth could come from LNG exports, with perhaps as much as one-third of U.S. domestic production reserved for international trade. This means that all production basins will attempt to flow gas to the Gulf. The Marcellus Shale is the nation’s largest natural gas basin, lying underneath about 90,000 square miles of Pennsylvania, New York and West Virginia but it is pretty far afield from where the incremental gas is going to be consumed. Bob reflects on what’s happening here.
Brooks: As Bethel indicated that some of the gas that feeds these projects in particular, the ones in Louisiana, but in Texas as well originates in the Appalachian area, so this is Marcellus gas or Utica gas. But, the problem is that the pipeline takeaway capacity from north to south is limited. And because it crosses state boundaries, that means that in order to increase that, you would have to get permits from national government agencies. We know that is very difficult these days. The industry is not particularly interested in even trying to do that anymore because it's very costly and they can spend hundreds of millions of dollars and then have the thing stopped. There’s you know, a lot of things that are bad.
One of the things that I've noticed is there's at least some interest in trying to get around this by intrastate pipeline development. This is something, of course, in Texas that happens a lot. That's one reason why you are able to develop a Gulf Coast LNG export industry fed by Texas gas, because you don't have to go outside of Texas to build your supply and your supply chain. So that’s good. Something similar in Louisiana between Hainesville and other sources in Louisiana and the Gulf Coast facilities in Louisiana.
There is a company that is trying to do something kind of similar to that in Pennsylvania. I'm not sure if they're going to be very successful, but basically they're talking about building a liquefaction facility, not right on the Delaware River, but actually a little bit inland, and feeding that facility with Pennsylvania gas, making LNG, and then trucking it to an LNG export facility that they would build on the Delaware River south of Philadelphia.
Delaware River is huge. I don't know if you've been to Philadelphia and that area. It's a great export area, potentially. There's a lot of industry there, and has been in the past, oil-based, but theoretically you could build an LNG export facility there.
Viswanath: This idea that you're teasing out there, which is you're talking about hyper-regionalization. We're seeing a dearth of interstate pipelines, but the intrastate activity in Louisiana and Texas is off the charts. Bob, you mentioned a great opportunity that may be occurring and unfolding in Pennsylvania. We used to talk about coal plants. These are mine mouth coal plants, right on top of supply, and we're seeing something interesting occur because of this.
With this idea lens on regionalization, let's talk a little bit about what's occurring in other areas. If we look at the Midwest, all of the gas is the Chicago area becoming a weigh station for excess Canadian, Appalachian, maybe mid-continent gas has two different areas that they can sink. What's happening in the Midwest?
King: Years and years ago, Chicago was a huge market area and everybody was trying to get there. That was the one that, you had like New York prices would blow out, you'd have Chicago prices and then Cal border. Those were three big market areas. Then when you started seeing pipelines come down from Canada into Chicago, Chicago essentially became a big hub. Just like you mentioned, lots of gas from lots of different regions can get to Chicago and then from there go other places. REX is bi-directional.
I think that, I recently, in the last year or so spoke with a lot of mid-continent producers. One of the things I brought up to them is like, yes, you have some mature fields, you're bringing in some of the new technology and revitalizing some of this stuff. But one of the advantages that the mid-continent producers have is that they're very well connected. They can go north, south, east or west. They have a little bit more flexibility versus the Permian producers. They're landlocked, for lack of a better word. Some of that's not quite as exciting just because we're not seeing quite as big of numbers from those guys. There's certainly a very robust community of producers in the mid-continent area who are really trying to optimize those fields, whether they're associated or not associated. Tight sands is being revitalized because of scoop and stack and the different plays within Permian as well.
Viswanath: We used to think about the basin economics setting the dispatch order. Now we have something interesting occurring. Where the mid-continent when compared to the net back on Marcellus might be lifting costs are a bit more expensive out of that basin. All of a sudden, it's really about infrastructure, takeaway capacity, which regional markets you can touch. It looks like it's the cards have already been set on the table and you've got to play the hand. It's a very interesting dynamic.
Brooks: Yes. I think also you need to look at the demand dynamics in those areas. If you're talking about Chicago, of course, leading into Michigan and Detroit and Minneapolis and all of these population centers, the problem is that as far as growth in this area is that population is not growing in these areas. I think there's been a substantial move towards the South as far as people are concerned. You don't have as much demand in these areas as you used to, in particular Michigan, but also Illinois. You've got plenty of supply, I’m mean you’ve got lots of Canadian gas still gets into that area.
Something that's happened since the development of Marcellus and Utica is that there's gas in the East pushing also westward. There's more supply available to the Midwest, but you've had to some degree also a reduction in industrialization in these areas and industry has moved South also. I think demand is down, I think that has created a situation where, let's say the Chicago hub and some of the other hubs there, though well supplied, they're not as important in the overall picture as they were maybe 10 years ago.
I think, where it's happening from what I can tell is has been moving further South in lots of different ways. The South used to be largely rural but think about where these companies. Where are they putting auto plants? They're not putting them in Michigan anymore. They're putting them in South Carolina and Tennessee and other places in the South for various reasons, mostly economics. You're getting a larger industrial demand growth in these other places.
Reynolds: There is an interesting but important complementary story unfolding in power, that amplifies the moving target for natural gas demand. Data centers are one of the fastest-growing industries worldwide. While the national-level growth estimates are significant, it is even more striking to consider the geographic concentration of the industry and the local challenges this growth can create. Today, 15 states account for 80% of the national data center load, with data centers estimated to comprise a quarter of Virginia’s electric load in 2023. That mega-load for power plants is also moving South. What are the implications for natural gas of growing power demand?
King: A few years ago, everyone was predicting that gas-fired electric gen demand was going to go down because of renewables and efficiencies. I think that the dynamics have changed not just from a population standpoint but also just the usage. Of course, one of the hot topics we're seeing is data centers and artificial intelligence. You know, years ago we heard a lot about data centers, and we didn't really see a big impact on that because things got more efficient. As technology got better, they offset each other. My question is, are we going to see the same thing for this big push for artificial intelligence and electric needs that it's going to have at the same time that we're trying to retire some of these inefficient plants?
Reynolds: Teri and I have talked a lot about some of those aspects, especially the electrification piece that you mentioned. There's varying degrees of efficiency when it comes to gas plants from the power supply side. I think ultimately the only thing that we're seeing right now getting built in the co-op space has been gas-fired units and I think you're seeing less combined cycle units just because they're a little bit less flexible than you might see a single cycle unit or maybe a reciprocating engine type unit. I think that is definitely what people are planning for as they think about how they meet some of that growing demand and think about what the next several years look like, of course, barring any limitations from proposed or pending EPA legislation.
Brooks: If you have some co-ops out there in West Texas, I think there's a source of gas that you could use for those units, by the way, and that might keep those prices from going negative, but it's probably pretty cheap gas for anything you might have out there in the Permian.
Reynolds: Yes, that's a great point. Maybe a year ago, early 2023, a lot of producers had internalized the idea of peak fossil fuel demand, and I know Teri and I had talked about that at length. Are you guys seeing a reversal on this view, or what's the outlook there?
Brooks: Our longer term forecast is even with a growing population and growing GDP over the next 30 years, we basically have all of the sectors except for power to be more or less flat. The question is, as a result of Bethel's group's research in some of these new demand centers, how might that affect electricity demand in general and then how much of that new electricity demand could be and might be and likely would be actually satisfied by using natural gas.
Mexico is still a growing economy and so demand in Mexico is increasing. But, this is just North America. Once you start talking about the world, you get into a very different picture and a very interesting picture because it's actually not that different and maybe even more the trend of lower demand growth and so forth and lower demand in total in Europe is pretty well established as far as natural gas is concerned.
China has a middle income economy and a lot of demand for gas and they produce a lot of their gas. They get some pipeline gas from Russia. They might get more gas. They get some pipeline gas from Central Asia. They also have 20 or so import terminals for LNG. I think they're planning on building another 15 or 20. They've got LNG terminals all along the coast of China. They are really building an energy economy which is based on security of supply. They're going to have the gas that they need from whatever. They have great optionality, and security of supply are more important to them than price.
Look at India. India is doing really well. We project in the long run that India is going to be as big an LNG market as China. It's going to grow enormously.
The price in Asia and Europe are not that far different. They're usually within a dollar or two per million BTUs. It's not that much different.
Both of them are heavily dependent on LNG. Europe basically is not probably ever going to get large volumes of natural gas from Russia anymore. They had relatively inexpensive gas by pipeline from Russia for a long time. It has been going down over the years as I think mistrust and missteps between Russia and Ukraine and currently the war and it's pretty clear that pipeline gas capacity into Europe is drying up.
Europe is getting the gas that it needs. A lot of it is LNG. Because Asia has so much LNG, shippers basically can choose where they're going to send the gas. That creates a competitive marketplace where the price is not that much different between the major marker in Europe called TTF and the major marker in Japan called JKM. Those are usually, again, within a dollar or two of each other.
Viswanath: So, this is the very thing that keeps me up at night. While the U.S. can already boast more LNG capacity than any other producing nation, the country’s liquefied natural gas shipping armada is about to get bigger, potentially doubling in size. This LNG growth will convert a mostly captive market to one that is at least partially exposed to world prices. A hint of this connection occurred in 2022 as Tamra mentioned earlier in this program with U.S. natural gas spot prices rising to their highest level since 2008, walking back all of those post-shale discounts.
Brooks: I think it's domestic issues that are determining Henry Hub price and other prices, and they're not being determined by these international prices and are not going to be determined by these international prices probably within the next several decades.
King: You've got big pockets of very prolific production, and then you've got a moving target population, electrification going on with these different regional markets. I think people are trying to say, what brownfield development, what gathering systems, what intrastate systems can I either build or utilize in order to serve these markets that are close to me and save myself, some of this pancaking of rates to go such long distances. Right now we're a little bit ahead on the supply curve as we wait for some of those international markets to come in.
Viswanath: Good to be in infrastructure these days, for sure.
King: Yes, it's swinging back to that, I think. I think that's the exciting area in the next couple of years is the infrastructure. Transportation, processing, and storage, I think are going to be interesting in the next few years.
Reynolds: So, basically there is still a window of opportunity for domestic consumers to enjoy low prices. But that window could potentially narrow as the twin developments of increased power plant demand from data centers and global exports begin to accelerate. I do hope that all of you have enjoyed this deep dive into the factors that will influence natural gas prices.
Viswanath: And, that all of you will tune in next month when we talk about right-sizing the distribution system to meet future needs. Bye for now.