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

Thank you for joining today's webcast. Will oil pricing dictate U.S. LNG facility utilization, I'd like to welcome our speaker today, Matthew Hagerty, who is FactSet's Senior Manager of Energy Analysis. 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 window, and we will address questions at the end of the presentation. [Operator Instructions] And lastly, this webcast is recorded. You will receive a link to the recording after today's event. And with that, I will turn it over to Matt.

All right. Thanks, Amanda, and thank you, everybody, for joining me today. Before we get started, we just have a quick cautionary statement in the beginning that you guys can all read over when we send the slides after the presentation. But for today's agenda, as discussed, we are going to talk about the impacts of how associated gas could dictate U.S. LNG facility utilization. So first, we'll walk through BTU Analytics' current outlook for natural gas demand and how that is expected to be met. What sources of supply will feed that growing demand? Next, we'll adjust that forecast to talk through how the impacts of a low oil price environment could impact that natural gas production. And then we'll move on towards how do we meet that gap. If oil prices are low and associated gas production falls, and what other sources of supply could realistically meet that decline in forecasted supply. And then lastly, if that is of supply is not enough to meet this new demand, what sources of demand destruction would be necessary in order to balance that U.S. natural gas market. So as we get talking here, first, just to give a quick highlight of BTU Analytics, a FactSet company and the opportunities that we give our clients in order to improve their knowledge within the energy markets. And so as highlighted here, BTU Analytics has a wide range of products, including everything from [indiscernible] level data to oil and gas market outlooks available on the FactSet Workstation. And so in my presentation today, the majority of the data and analysis that I'll be highlighting is actually from our Henry Hub and Gas Basis Outlook reports, which coincidentally just published yesterday. So both of those are available to BTU clients as well as workstation for FactSet clients. And now kicking off to the presentation itself. So within the U.S., we model that natural gas demand is expected to grow above 110 Bcf a day by 2028. However, the majority of this growth is coming from LNG, which is expected to more than double our consequently further consolidating U.S. natural gas demand along the Gulf Coast. And so that will be a key factor as we started discussion today on supply. Other than the demand sources -- or other demand sources are combined, our forecast to fall over this period, driven primarily from residential and commercial and competition for power with renewables build out. So as we think about those other sources of supply -- the other sources of demand, that demand that is spread across the U.S. We're seeing declines, net in those sources while localizing a lot of LNG demand growth right along the Gulf Coast. And then so next, thinking about how we actually meet that demand forecast. So let's quickly talk through the sources of supply that will be available. First and foremost, associated gas represents the lowest cost option since the economics of these plays are driven by oil pricing. Based on our current oil price forecast, these plays are expected to add nearly 12 Bcf a day through 2028, a majority of this focused in the Permian. And so in addition to its dependence on oil pricing, the Permian, in particular, will require significant pipeline and gas processing infrastructure build-out to meet this forecast. Now on top of that, you also have your major gas plays and noncore plays. And so those are left to fill the void to meet that demand. So those will add a combined 5.6 Bcf a day of supply through 2028. Now this represents the inherent problem in today's webcast. While the associated gas growth is certainly a major factor in today's pricing dynamics, what happens if oil prices disappoint, and this forecasted associated gas growth doesn't materialize. So let's first talk about that and talk about how important our current forecast is for associated gas and the pricing outlook that builds it. So BTU Analytics currently forecast the WTI price will average about $79 per barrel through 2028. Now the majority of the higher portion of this pricing outlook is built in over the next couple of years where oil pricing responds to rebounding Chinese demand and then also declines in Russian supply. However, really beyond 2024, that supply-demand balance globally for oil markets begins to balance out and actually turn a little bit long. And so that oil price forecast turns to about $75 in the out years. And so this outlook produces effectively steady growth through the major associated gas plays when we think about how those oil economics impact activity in the place. However, this outlook is bullish, the WTI strip. The WTI strip currently is averaging about $67 per barrel through 2028. And using our proprietary cash flow-based production model, this lower oil price scenario produces a drastically different outlook for volumes with associated gas production stalling in early 2024, leaving roughly 7 Bcf a day of supply to be made up elsewhere in our demand forecast if our demand forecast is to remain unchanged. Now turning to how that impacts the supply-demand balance in the U.S. specifically. So this dearth of associated gas creates an untenable amount of undersupply. Now I want to highlight that this supply-demand imbalance shown here in the red bars is not realistic, but it's illustrative of the level of importance that associated gas truly plays in the U.S. market. So in order to balance the U.S. market in this environment, let's move on to the sources of supply and demand that could change, starting with supply. So first and foremost, it's always important to talk about the Northeast. And so in our Northeast view, the lack of sufficient natural gas takeaway is expected to cap the amount of production that could come from the region. We do not model the MVP or Mountain Valley Pipeline will enter service in our forecast window or the other planned projects currently reach far enough into the supply region to allow for production growth. And additionally, considering that point that I made earlier on how the localization of LNG demand on the Gulf Coast makes it really hard for the Northeast to really serve any of that in addition to what it's already serving. So that would require significant expensive projects crossing numerous states and jurisdictions that certainly all have their own politics to keep in mind. And so whether it's our base case forecast, as you see here, or in this alternate case, they're roughly equal. We do not model significant growth in [ Appalachian ] production. So now flipping towards this chart that I brought up earlier that shows the base case demand growth that we have as well as the base case supply growth that we model, let's think about under this new supply scenario how we could realistically meet that demand? Because now adding in the new associated gas that we model here, followed by BTU's base case for gas directed and noncore plays, we can see the huge shortfall that exists in supply. And so now keep in mind that in BTU's base case, we already model a combined 8.5 Bcf a day of production growth in the Haynesville, Dry Eagle Ford and Gulf of Mexico. But in this new case, the amount of growth from these gas plays isn't enough. So pricing would need to rise above our forecast to encourage that growth. So to meet the shortfall, we modeled that there would need to be an additional 3.9 Bcf a day of growth from the Haynesville alone. That's in addition to what we're already modeling as well as another 3.1 Bcf a day from the Dry Eagle Ford the Gulf of Mexico and the noncore plays in Texas and Oklahoma. And so the important piece of this is that just taking alone all of this growth built in to those plays is significant, and that is already on top of the amount of production that we already have modeled out of those plays. And so that certainly creates some tensions in the system. And these plays, these major plays like the Haynesville and Eagle Ford are already under some stress. So this additional growth doesn't just occur in a vacuum, and there are several risks that these new production levels would create, namely on inventory and infrastructure. And so inventory in the Haynesville. This chart here shows the level of undrilled inventory in the play graded by the relative breakeven. And so in the Haynesville, undrilled inventory at low breakeven prices is already a risk in our forecast. Adding significantly more drilling activity to the basin speed up this process of depleting the best acreage. So in order to get to these higher levels of drilling activity in the basin, it requires a higher price of Henry Hub in order to get there, which will certainly have knock-on effects later on in this presentation, which I'll certainly touch on. And then considering the Dry Eagle Ford. So the same occurs in the Western Eagle Ford where an acceleration in activity would drill through the core of the play at a more rapid pace. So taking just these 2 regions combined, this scenario would drill through the most economic inventory roughly 1.5 years faster than BTU's current forecast in just a 5-year period. So a significantly faster rate of inventory depletion over a relatively short period of time. And then next, on top of the inventory issues, infrastructure poses a significant risk to this localized growth scenario. So in this chart, in the Haynesville alone, this chart is showing the incremental growth that we would see from our base case in the blue line in terms of production. And then the red line is showing this new production scenario when we need just even more growth out of the Haynesville. And so in the Haynesville alone, the alternate production scenario far outpaces the incremental capacity that is modeled to come into service over the next 5 years, therefore, requiring more investment, more planning and additional time to increase the amount of pipeline capacity that is available in these plays. And not to mention, this incremental production in the Haynesville ignores any of the growth from other regions that also flow through this corridor. This corridor reaching from Northern Louisiana and East Texas down to the Gulf Coast, also includes flows from Oklahoma, Barnett and then soon, potentially with Energy Transfer's Warrior pipeline could also include increased Permian volumes that flow into the [indiscernible] market. So as we add in all of these supply sources, there needs to be significant more build-out of infrastructure along this corridor just to meet this new supply case. Now that we've kind of established the risks facing some of the supply regions, let's switch to demand. And the majority of this analysis here is going to focus on LNG. But first, we'll touch on power, industrial and res for a second. So in theory, demand for gas from power generation should be elastic. When gas prices rise too high, other fuels can operate at a more economic price. But over the last 16 years, roughly 110 gigawatts of coal has been retired, leaving 115 gigawatts remaining. This reduction makes gas-fired generation much less elastic to higher prices. Additionally, BTU already models risk to natural gas demand from renewables adoption. And then so when you think about power, we're taking in some of those risks of renewables, and there's also much less ability for fuels to interchange between gas and coal now. And those coal retirements are only expected to continue. On the res com and industrial side, those have proven much less elastic to pricing, even during the high price environment this past summer. So that leaves LNG. And as the chart here shows, LNG capacity is expected to more than double by mid-2027. This wave of demand growth, especially given the location of the majority of these facilities could fuel the primary arena or demand destruction in a low oil price environment. In order to understand how LNG demand in the U.S. could be curtailed let's establish the costs that go into LNG exports. So first, this red line of TTF here represents the price received for LNG once it's been delivered to Europe. So once costs start to cross this threshold U.S. LNG cargoes risk being canceled. The first component of the cost would be the price of natural gas and after accounting for the fuel used by LNG facilities, that represents 115% of Henry Hub. That's these 2 shaded areas that I just added into the slide here. Next would be the shipping cost, which has certainly fluctuated considerably since the Russian invasion of Ukraine and can add considerable cost. These make up these 2 pieces of 115% of Henry Hub and as you add in that shipping cost to Europe, those represent the variable costs or the majority of the variable costs. And then so lastly, adding in the fixed cost that is the liquefaction fee for shipping to Europe. For shipping to Europe if the TTF price can't at least surpass the variable cost, then U.S. LNG demand risks being curtailed. However, at the current strip price for both Henry Hub and TTF as are shown here, that doesn't occur over the next 5 years. So the shaded area below represents the cost of -- based on current Henry Hub strip pricing, the cost of exporting LNG to Europe and then the red line shows, obviously, the price of TTF for a strip price. So given that current strip pricing doesn't exactly factor in or call for a curtailment of U.S. LNG. Let's talk about what price that would actually require. Because in order to cross through that threshold of not even covering your fixed costs, that is what triggers a lot of these LNG cargo cancellations. So lastly, let's assess that price that would drive the decline in U.S. LNG at the current TTF strip price. This chart shows in the red line, how that threshold price for Henry Hub fluctuates at the TTF strip as the TTF strip declines over time. While Henry Hub currently is far from reaching the threshold in the near term, the Henry Hub strip price and the threshold coverage -- converge in 2026 and beyond. So on average, that threshold is roughly $8/MMBtu in 2026. So $8/MMBtu, I just want to put that in mind. I mean as of today, that is far and above what the price is that we need currently to turn on new supply from gas regions in the U.S. $8 is certainly a level that would add a lot of activity in the Haynesville and in plenty of other plays. However, we've already discussed this that the pace of development in some of those major plays like the Dry Eagle Ford and like the Haynesville could significantly step some of the undrilled inventory and even stress some of the existing infrastructure in those regions. And so as we think about $8 now versus $8 in 2027 and 2028, that might be a very different environment. And so that level of pricing could actually realistically be reached in order to start turning off demand from LNG instead of turning on supply from the U.S. basins. So lastly, I'd like to end with some of the key takeaways here. So as we've discussed, LNG exporters have robust plans for growth through the next 5 years, but meeting that demand requires a significant reliance on associated gas and therefore, oil plays in the U.S. and oil prices. If oil pricing disappoints and that oil-driven activity falls with it, the lackluster growth that comes from that creates an untenable divergence in natural gas supply and demand. And then finally, as we think about what supply could come to meet this level of demand imbalance and also what demand might need to be taken out of the overall stack in order to meet this. We've talked through how some of that could come from the major plays, but there also might be a significant call on some of the noncore plays such as Oklahoma, Texas and a region that's recently seeing some new investment of the Gulf of Mexico in order to meet some of that new demand. But a lot of this is going to come down to how quickly LNG facilities can come online in the U.S. because our outlook for capacity in the U.S. is certainly aggressive, and there are countless facilities that are under development currently, but the pace at which those can actually be constructed and constructed on schedule will be a significant factor and how fast LNG demand actually rises through the next 5 years. So for now, I'd like to turn the presentation over to Q&A. And as Amanda highlighted, if you have any questions, please feel free to type them in the chat.

So the first question that I'm seeing in here is how much of a risk is there that LNG demand does not reach your forecast. Is there a downside upside that makes this problem better or worse? So I would say, in general, I kind of touched on that towards the end there on the key takeaways, but to a certain extent, a lot of our forecast really requires LNG facilities being built on time and obviously on budget as well. So given the level of inflation that we're seeing currently as well as low -- unemployment across the U.S. and just the sheer number of facilities that are under development, getting those built on time is going to be a significant task at hand. And so we've seen with some of the larger LNG facilities in the past. Those have been brought online a little bit later than they were initially planned for. And so that can certainly slow the rise in our overall LNG outlook. And then next, what other fundamentals could move in a high-price environment, would we lose significant power or industrial demand? So yes, so in a high-price environment, again, I touched on that a little bit here. But as we think about those 2 pieces of demand, specifically power, our power forecast is -- forecast is modeled to decline by about 7% between now and 2028. And that power -- obviously, it's demand for natural gas for power generation. That is driven by a much faster adoption of renewables through our forecast. But some of this is lumpy as well. A lot of the renewables that are slated to be built out. A lot of those projects haven't even been announced yet. Those can operate usually around a 2-year time frame or lead time in order to build new solar, new wind -- new wind capacity. So if we think about how fast some of these renewables could maybe accelerate that pace, it becomes a little bit muddled because when you look at the pace of development for renewables now and that's already fueling our forecast for roughly 7% decline in natural gas power demand. In order to speed up the development of renewables and if natural gas pricing is going to be the primary driver of that, it still requires a multiple year period where natural gas pricing is high. So that can make some of the power, as I mentioned, a little bit less elastic to pricing than where it has been historically. And then on the industrial and res com side, we've seen those be relatively inelastic in the past when we were looking at last summer when natural gas pricing was hitting above $9 and got close to $10. We saw some of the industrial demand in the U.S. turn off, but not anything really substantial to significantly impact that overall forecast. And then thinking about I guess the last question here. How do you think about the feedback loop between gas prices and associated gas production? So if gas prices are $8, doesn't that mean that Permian-associated gas ramps back up even in a low oil price environment. That could be the case. There are certainly pieces of the Permian that become -- gas prices that high. Obviously, 1 that comes to mind would be Alpine High. And then as you continue to move west across the Delaware Basin. Some of those areas could come into the money. And we would certainly expect some of this development, but those are plays at least from a gas perspective, that have somewhat fallen out of favor over recent years. We've seen Alpine High production either pulled flat or decline over the last several years. And so that's an area where it would take significant investment in order to get those areas back up and running. And at the same time, as we think about the Permian, a lot of this development that we're seeing in terms of natural gas pipelines in the region, are dependent on continued development. So there are certainly several projects that would -- that are under development now. One of those being Matterhorn that's reached FID. There's also expansions that we model from Whistler and Permian Highway. But after those, none of the other projects have reached FID. And so those would need to see significant growth out of the Permian, a lot of that growth that would come from an oil price standpoint -- would -- that's what would drive those new pipelines. And so whether or not the Permian would actually get some of that investment, if the gas-driven activity or if the oil price-driven activity is holding flat. That's hard to say. One gas play out of a sea of oil-driven activity is potentially not enough to warrant a new pipeline out of Permian. And then so what downside -- I guess last question here, what downside price levels for the balance of the year and also for the 24% to 30% range. Should we expect to see supply pullbacks $1.50, $2, does that change rolling forward? Yes. So for this question, I think the -- see, I think there is certainly some additional downside pressure for the balance of the year. Some of the production growth that we're currently seeing out of the Haynesville and as I was just talking about it out of the Permian. We expect to see that there's certainly additional pricing pressure in the near term for Henry Hub. That's kind of how we're modeling it because the rigs that we're seeing pulled off currently in the Haynesville don't have just an immediate impact to overall supply. A lot of the producers that we're hearing are pulling back on rigs. They still have wells to complete. And so we model that Haynesville production is going to continue growing for at least the next couple of months before flattening out and ultimately declining later on this year. And then at the same time, we are also modeling continued production growth out of the Permian. So this all comes at a time when there is relatively little growth in overall natural gas demand in the U.S. So through our really next 2-year time frame, we're modeling that natural gas pricing is certainly going to be pressured through that time frame. And then it's really not until that late '24 into 2025 time frame, that's when we really view that natural gas pricing will start to improve. And so we actually get a little bit more bullish the Henry Hub curve in the out years of our forecast than where things are currently. And then that is just about time for us. I think that there's 1 more point I could make here on a question, just talking about the impact of Mexican exports and how those service LNG exports in Mexico. And so that is potentially 1 other area that could be pulled back on if pricing suggests -- if pricing continues to rise in the back half of our forecast. So for that, there are certainly LNG projects built out or that are under development in Mexico. And we include some of those facilities in our forecast. And that is fueling, overall our Mexican exports to rise over time. That was one of the other pieces in our natural gas demand forecast that actually is growing and offsets some of the other growth -- or some of the other declines that we're seeing from residential, commercial and natural gas power demand. So those are other facilities that similarly, if the time lines on those are pushed. We've seen infrastructure in Mexico relatively fairly delayed in the past, especially when you think about the pipeline infrastructure that needs to be built in order to get there. And so those are additional projects that could be pushed or delayed or ultimately not constructed. And then on top of that, those become -- similar to U.S. LNG, areas that are ripe for some of this price competition in those out years as Henry Hub price really extends out. But with that, I know we're just about out of time here. So with that, I'd like to thank you for taking the time to sit with me today. And as Amanda mentioned, we'll be sending out the recording and the slides later on.

Yes. Thank you so much, Matt, and thank you, everyone, for joining today. If we did not get to your questions, we will follow up with you directly. We will also send a link to the recording directly via e-mail. And if you have any additional questions or would like to learn more about FactSet's Energy Solutions, please e-mail us at [email protected]. Thank you all, and thank you, Matt, and have a great day, everybody.