FactSet Research Systems Inc. (FDS) Earnings Call Transcript & Summary

Hello, everyone, and thank you for joining today's webcast: Are U.S. Natural Gas Prices Poised to Crash? I'd like to welcome our speaker today, Connor McLean, who is a senior energy analyst at BTU Analytics, a FactSet Company. In this role, he focuses on natural gas market research and modeling and is responsible for publishing two of BTU Analytics' gas-focused reports, the Henry Hub Outlook and Gas Basis Outlook as well as contributing content for BTU's other product offerings. He also develops and maintains BTU Analytics' natural gas pricing and fundamental models with a focus on LNG exports and regional basis pricing dynamics. Before we get started, I'd like to cover a few housekeeping items. Today's event will last approximately 30 minutes. We encourage you to submit your questions at any time via the Q&A box, and we will address them at the end of the presentation. However, should you have any technical questions, we will address those right away. And lastly, the webcast is being recorded, and you will receive a link to the recording after today's event. And with that, I will turn it over to Connor.

All right. Thank you so much, Amanda, and thank you again for everyone joining us for the webinar today. We're going to be talking about Henry Hub and really talking about what Henry Hub is going to look like as we enter the market in 2023. Now before we get started, we'll do a quick rundown of the presentation agenda before we actually get into our content. And so we'll start with talking about Henry Hub pricing and really about how volatile Henry Hub pricing has been in 2022. We've traded -- in the cash market, Henry Hub has traded in really a $6 range in 2022. Now that started with the runup in the summer and the spring as a result of the conflict in Ukraine and then recently has come back down to where we are today, below $6 an MMBtu. But when we look at gas pricing, that fall that we've seen in the last few months isn't that surprising when we look at historical analogs. U.S. gas pricing has divorced from U.S. storage inventories. And certainly, the energy market is undergoing change. In fact, we did a webinar on this very topic earlier this year and talked about the potential for higher energy prices moving forward. However, when we look at where storage sits today, we see that pricing is far in excess of what we'd expect when we look at our natural gas fundamentals. And when we look at fundamentals, when we look at production, in particular, U.S. dry gas production has been growing since bottoming out during the pandemic in 2020. And after adding over 3 Bcf a day of production in 2022 alone, we expect growth to continue in 2023. But unlike in previous cycles where we've had increased production growth, we are not seeing new demand come online to counteract that growth. In fact, when we look at demand growth outside of LNG, a lot of our fundamentals are flat in our 5-year forecast window. And although we have a lot of LNG demand growth in our forecast, most of it is not expected to materialize until at least late 2024 and in reality probably not until 2025 and beyond. And so if we don't have new LNG demand coming online in 2024 and 2025, then we won't have enough demand to counteract the supply that's coming online. And so assuming a normal winter in 2023 and 2024, balancing the market is going to require a cut in production activity, which will likely require a sharp drop in gas pricing. So let's start with talking about the spot price for Henry Hub. And when we look at Henry Hub, as I mentioned, pricing has run up, really coinciding with Russia's invasion of Ukraine in late February. So starting in February, gas pricing has run up over 140% from where we were in February, around $4 an MMBtu, running up to over $9 an MMBtu in May and June. And after a brief falloff in mid-summer, we came back up above $9. We approached $10 in August. But since then, we steadily declined, and we've lost nearly 50% in the Henry Hub spot market. Now this fall in gas pricing, as I mentioned, was foreseeable. When we look at gas pricing in the -- compared to storage, whether on an absolute basis or even on a 5-year average basis, we see that Henry Hub has far outpaced storage relative to the 5-year average. And when we look historically at storage versus the 5-year average, today's levels of storage relative to where we were in, say, 2018-2019, are not nearly as bullish as pricing would indicate. And the same is true as we look at storage as the deficit to the 5-year average narrows. We see that Henry Hub pricing over a variety of time frames, whether that's in the spot market, whether that's in the front month futures or even further out, the 2023 summer or the 2023 calendar year strip, we see that pricing today is well in excess of what we would expect from natural gas pricing at the storage level. So if we dive down even further, even if we eliminate some of these historical analogs in '15 and '16 or '19, when the market was different than it is today, we see that natural gas storage is about where it was at this point in 2021. Now obviously, 2020 was an outlier in the middle of a pandemic. But when we look at 2021, just a year ago, storage deficit to the 5-year average was about where we are today. And so as we look forward, if we remember just 12 months ago, natural gas pricing was not $6 to $8 an MMBtu. It wasn't even $5 an MMBtu. And so the price we see today in the forward market is not representative of what we would expect in the U.S. gas market compared to where we were just 12 months ago. And although the market is changing, we have new pressure from investors and new focus on environmental and social governance metrics, and we have an increased cost of capital from supply chain constraints, all of that combined is putting increased pressure on Henry Hub pricing that doesn't reflect what we see from our other fundamentals outside of storage because storage is not a perfect proxy for what we're seeing in the gas market. So if we dive into our fundamentals and we talk about production, U.S. gas production over the last 3 years has really been concentrated in 3 regions: the Permian, the Haynesville and then the Marcellus and Utica in the Northeast. But as we look forward, we expect production growth to really focus in, in the Permian and the Haynesville. You'll notice that outside of those two regions, we have very limited production growth in 2023 in the Northeast and in the Rockies, in Eagle Ford, in Oklahoma. And really regions outside of these basins, we have production declining through our forecast window out through the next 5 years. So not only do we have production growth in the near term, but as we look out to when LNG demand comes online in 2025 and 2026, we expect the Permian and Haynesville to continue to drive production growth in those years. But I should mention that future production growth in these two regions is dependent on the build-out of additional pipeline infrastructure. I don't want to dive too deep into it today, but when we look at the Permian, just last month, we had outright pricing at Waha go negative. So certainly, takeaway capacity out of the Permian will be crucial to support this continued production growth. And the same is true in Northern Louisiana. Bases in Northern Louisiana is $0.80 to $1 back at Henry Hub right now. And Henry Hub pricing at $6 an MMBtu, that's fine. But as pricing begins to fall into the $4 and $3 per MMBtu range, even acreage in low-cost basins like the Haynesville are going to feel pressure from declining gas prices, potentially enough to cut activity. And when we look at production growth, production growth as we have it modeled today, around 3.5 Bcf a day of production growth year-over-year moving from 2022 to 2023, that's not an unprecedented level of production growth. This is not a level of production growth like we saw in 2018 or 2019, where you might expect pricing to collapse rapidly after seeing that much production growth. But when we look at 2023 compared to other years where it looks similar, 2014 and 2015 provide a nice analog, where supply was outpacing the additions of demand. And indeed, when we look back to '14 and '15, we saw gas prices collapse back below $3 an MMBtu once all that supply came online. Now the difference, of course, in 2023 versus 2015 is we have now become much more dependent on LNG demand growth relative to where we were in 2015. In fact, we didn't have any LNG export growth in 2014 and 2015. But when we look at 2023, in particular, you'll notice that we do have demand growth, nearly 2 Bcf a day. But a lot of that demand growth is really just the return of demand that disappeared in 2022. In particular, that demand growth is going to be from the return of Freeport LNG, which went offline this summer and is expected back in early 2023. One of the reasons we are not bullish on demand for 2023 is that the ability for the U.S. to respond to international pricing increases like in Europe or in Asia is severely limited. We saw that this year. You can see here that even when TTF, the European benchmark; and JKM, the Asian benchmark, approached $80, $90, $100 an MMBtu, U.S. LNG demand was basically flat. And that makes sense. U.S. LNG is in the money at $30 an MMBtu. So there's no reason for them to run at reduced capacity when they can -- when the netbacks are still positive. And certainly, as the price runs up, there is no room to increase demand as those prices increase. And that dynamic is going to continue in 2023. In 2023, we should get Freeport back, but the next round of facilities really won't start coming online until the end of 2024. And that's not to say that we don't have LNG demand growth in our forecast. It's just not in 2023. You can see here that we have over 12 Bcf a day of new LNG capacity coming online through the end of 2027. But you'll also notice that, that demand is heavily concentrated in 2025 and beyond. In reality, the only facility that has added incremental capacity in 2022 is Calcasieu Pass. And that facility is already running at a really max utilization. And if we look beyond LNG demand to some of our other fundamentals, whether that's in the power market, whether that's in the industrial sector, we had demand either flat to declining through our forecast period. Whether that's due to the build-out of renewables, whether that's increased efficiency in home heating, we do not see the other major demand [ centers ] in the U.S. driving growth. It is almost exclusively dependent on export demand growth out of Mexico and via LNG. Now if we take all of these components together, right, our growth in production and our inability to grow demand over the same time period, we're left with a storage scenario, the blue line here, that puts us on track to hit 4 Tcf by the end of 2023. Now 4 Tcf, while technically feasible, is much higher than the average summer exit. It actually puts us back into 2020 -- into the range of 2020 when we approached 4 Tcf and gas pricing was sub-$2. Now in order to balance this market, if we can't add demand, we must cut production. And in order to get back to just a normal end-of-summer number, around 3.7 Tcf, we would need production to be cut by -- production growth to be cut by about 25% relative to the current BTU forecast. And as I mentioned, we're only adding 3.5 Bcf a day of production in 2023. But if you cut production in the near term, if we do see low natural gas pricing result from this oversupply and you see a cut in production, you could be left with a whipsaw effect, where the market is left short entering 2024 and 2025 as new demand comes online. And that's what these scenarios highlight here is that under our current forecast, we are oversupplied. But it doesn't take a ton to cut our market into where it's in a short market, where then gas pricing needs to rebound in our out-years to support new production growth to meet LNG demand. So how far, though, does production need to fall? And really how far does pricing need to fall to incentivize that production? That's kind of the base question here. And when we look at breakevens and economics for gas plays, right now, everything is in the money. When we look at breakevens in the Haynesville or in the Northeast, you're really looking anywhere from $2 to $3 Henry Hub in that breakeven, even at a higher cost of capital. And as I mentioned, there are headwinds to production. Whether that's capital discipline, we've seen falling reinvestment rates as operators return, increased capital to shareholders as they pay down debt, as they increase dividends. And we've seen a commitment from public E&Ps to not growing production. But from private operators, we're not seeing that same behavior. And so -- but even with that sort of a headwind, increasing our internal rate of return from 10% to 20% IRR still leaves a lot of this acreage in the money. You actually need pricing to come down pretty substantially, right? The current forward curve is around $5 Henry Hub. Even if it fell to $4, you would still be left with over 80% of locations above your natural gas breakeven. Now that means that we really need gas pricing to come down below $4 and realistically, probably needs to come down to around $3 to $3.50. And that pricing is a lot like what we've seen historically. When storage was close to the 5-year average, [ with ] production was growing and when demand was not, we see pricing retreat back to this $4 to $3 level, and that's still below what we're seeing in the forward market. And so when we revisit the initial question, right, are U.S. gas prices poised to crash, truthfully, when BTU Analytics and FactSet planned this webinar, natural gas pricing was much higher than it was today. And we've already seen a little bit the impact of increased storage injections weigh on natural gas pricing. But as we look forward to 2023, we still think that there is significant downside risk for Henry Hub as we enter really summer of 2023. Now I should mention here, though, that all of this is dependent on what happens this winter from a weather perspective. In a normal winter, as we model, that would put us in this oversupply scenario where pricing falls. But in a situation where we have a really cold start to winter, we could have pricing run up this winter and support pricing potentially into next spring. But that doesn't change our underlying dynamics, right? It doesn't change how much production is going to come online and how little demand is going to come online. Conversely, if we have a warm start to winter or even a warm end to winter, we could see pricing come down much faster than we currently model, and we could be in that $3 to $3.50 territory as early as next summer. And so with that, I'd like to wrap up the presentation with talking about how we think about Henry Hub in the short term versus kind of a longer term, right? Obviously, as we enter the winter season, we continue to expect Henry Hub to be volatile. Henry Hub pricing could run up in excess of what it is today. And we could see pricing return to that $8, $9, $10 range, especially if LNG remains expensive in Europe and Asia like we expect it to. But as we enter summer 2023, we expect pricing to correct quickly and fall to these levels that we talked about, where pricing is more reflective of the fundamentals we're seeing and is not be reflective of what we're seeing overseas. And so with that, Amanda, I'd like to turn it back over to you and see if we can answer any questions that have come from our attendees.

Awesome. Thank you so much, Connor. Yes, let's now dive into some Q&A. All right. So let's see here. The first question that we have from our audience is, how would a cold winter in Asia or Europe impact Henry Hub pricing?

Sure. So I don't think a cold winter in Asia, or Europe for that matter, is going to have a huge impact on our forward-looking Henry Hub forecast. As I mentioned, if you do have a cold winter in Europe, you could see TTF pricing spike and you have higher LNG. But as I mentioned, the ability for the U.S. to respond to higher pricing internationally is really limited. And so to the extent that prices run internationally, you could see Henry Hub rise in sympathy. But from a fundamentals perspective, we should not see increased demand as a result of a cold winter. But in the U.S., right, a cold winter, obviously impacts our domestic demand much more and offsets some of that production growth we've seen this year and also puts us in a more bullish storage situation as we enter 2023. I will add, though, that a warm winter in Asia or Europe, I know this wasn't the question, but in a warm winter scenario where LNG prices collapse, you actually have even more downside risk for Henry Hub, if LNG prices would have to come down substantially from where they are today. But a warm winter that puts Europe on track to survive next winter as well would certainly weigh on U.S. netbacks and potentially cause U.S. LNG demand to fall, which, of course, would result in weaker Henry Hub pricing.

Great. Thank you so much. All right. The next question, do any current infrastructure constraints in the Haynesville have the potential to limit production and soften the decline in pricing that you're forecasting for next year?

Yes. So it's a good question. So when -- I talked about infrastructure constraints a little bit in production, but there was really more longer-term focus, right? We do need infrastructure to support production growth in the out-years out of Louisiana and the Permian. In the near term, we have enabled Gulf Run project coming out of the Haynesville early next year, and that will add some takeaway capacity. And then we probably enter a period of tightness again in terms of capacity until we reach 2024, when a lot of the new North to South Louisiana pipelines come online. Now when we look at the Permian as really the same way, Permian pipeline constraints today, like we saw with pricing going negative, if oil pricing remains strong, that may be enough to counteract it, but we have seen before that Permian constraints can impact Permian production. And we don't expect new Permian pipeline capacity to come online really until the end of 2023 when we get expansions to Permian Highway and Whistler. So I do think that there is some risk that infrastructure constraints prevent production from growing and potentially soften the pricing decline we're looking at. But in the grand scheme of things, I don't think that that's going to be enough to support pricing at the level we're seeing today in the forward market.

All right. So the next question that came in, how does coal pricing affect your outlook?

Yes. So coal pricing right now, it does -- weaker coal pricing, right, is going to impact how much natural gas generation we can get in the power sector. Certainly, one of the benefits, I guess, you could say, of falling natural gas pricing is that natural gas becomes more competitive in the generation stack. But from a coal price [ view ], we would need to see coal continue to stay at really elevated levels to support the kind of gas generation we saw this summer, right? This summer, we saw gas generation at record levels despite high commodity pricing. And so if commodity pricing continues to come down, gas isn't becoming more competitive if coal pricing stays high. You would really need to see a reversal of fortunes where coal pricing gets much, much cheaper to displace additional gas out of the stack. So I don't think coal pricing, in general, is going to have a huge impact on our balances unless it remains way more expensive than where we see gas prices going.

Awesome. Thank you, Connor. So we'll ask one -- or I'll ask one more question. The last question, do you expect any natural gas demand for manufacturing, industrial, agriculture to spill over to the U.S. in 2023 and given the [ probability of ] high gas pricing in Europe.

Yes. I do believe that you could see some increase in the industrial demand sector from the relatively stronger higher pricing in Europe as it relates to competition with the U.S. We've seen BASF is planning on shifting some of their industrial manufacturing operations away from Europe, although that is going to be relocated to Asia, so that's not a benefit to the U.S. You could see the build-out of manufacturing in the U.S. support some industrial growth. But again, like LNG, it does take time for industrial demand to ramp up, right? Whether it's the passage of the IRA, whether it's company shifting operations from overseas to the U.S., it's going to take time for that demand to materialize. And just like LNG, it's unlikely that that materializes in 2023 in time to support pricing. So I think that's more of a longer-term benefit is that higher commodity pricing in Europe supports industrial demand growth. But in the near term, we model very minimal demand growth as a result of high energy prices in Europe.

Okay. Great. Thank you. I -- let's conclude the presentation now. So if we weren't able to get to your question today, we will follow up with you directly after this webcast concludes. And if you would like to learn more about FactSet's energy-specific data and analytics, please reach out to either your local FactSet sales rep or e-mail us at [email protected]. Thank you all so much for joining us, and please enjoy the rest of your day.