The growth potential is exponential from the Marcellus and Haynesville, coupled with associated gas, untapped U.S. “deep gas” and the Gulf of Mexico plus the gassy fairways of the southern Permian, southern Eagle Ford, Midcontinent and D-J Basin.

Jay Young, President & CEO, King Operating Corporation

Zack Van Everen, Senior Capital Markets Analyst, East Daley Analytics

Jay Young (00:19): My name is Jay Young, King Operating Corp. Thank you so much for having me. And we also appreciate all the sponsors that we have, so we're really excited about that. King Operating is an operating company, and we've been around since 1996, where we founded and we buy prospects and drill. We raised an $80 million fund last year, and we're deploying assets and five different assets that we're drilling at the moment. So we are very active and look forward to this run. Hey, this could be my last as a fourth generation of my family. So we're excited about that, but we're not as excited as our next or our speaker with East Daley Analytics. From my understanding, it is all about analyzing data. Data, right? Everybody talks about data, everybody talks about, hey, how do you gas forecast, and what's LNG, and what's about all the different information that you have to do in regards to running numbers? So this is the bachelor of the year - no, I'm just kidding, he's not really the bachelor of the year - but he is a good looking guy. Zack, please come to the stage.

Zack Van Everen (1:47): Thanks Jay. As Jay mentioned, my name is Zack Van Everen. I'm a senior analyst with East Daley Analytics. Today we're going to talk mostly about short-term supply forecast and long-term LNG demand forecast,

(2:05): So I won't go through all these notes, but for those who don't know, [at] East Daley, we focus on the infrastructure side of the commodity market. So we started by modeling cash flows on a asset level. We actually rolled those up into full midstream equity models. To do this, we realize very quickly you have to be extremely good at volumes to be accurate on the cash flow forecast side. So we built out a commodity team, we have a commodity suite of products and we're going to focus on the natural gas side of that suite today. So two key takeaways I want everyone to walk away with today is East Daley forecasts a significant amount of dry gas hitting the U.S. markets from now until the end of December, 2023; around 4.6 Bcf/d is what we currently have forecast from September 2022 through December 2023. Longer term, we all know there is more demand in the horizon as far as LNG goes. So we'll touch on our forecast and our wedge of new LNG projects we have coming online and what that means for gas markets 2024 and really beyond. We combine these dynamics to really highlight what could be a wild ride for not just production, but also prices and basis across the U.S.

(3:21): So let's start with the shorter term outlook. So looking at how we got to where we are today, back about 12 months ago in the blue curve there you can see where WTI was - pretty grim outlook. We had a few things at play. We had ESG in the tox. We had capital discipline by the producers. What this really resulted was low production when a lot of demand came back to the market. On top of a Russian invasion of Ukraine, we got the spike you see in WTI. The result of this was producers taking action. So the chart here shows the six major basins that you'll hear people talk about. Between January 2022 and August 2022, Permian added 41 rigs, Anadarko 14, Eagle Ford 22, ArkLaTex 10, Appalachia five, well 12. 104 rigs between these six basins between January and August 22. Of course, let's not forget about the other basins altogether; U.S. increased rigs by 122 just from the beginning of 2022.

(4:26): So when we put this in our forecast, what we really look at is how does this affect the gas markets on both supply and demand side. So as mentioned, four of those basins are oil-driven basins, so you're getting associated gas out of those basins. Looking at the same list, we highlight those same four basins. You can see the significant amount of growth that we forecast, and this is in MMcf/d, between 2022 and December 2023, tolling that 4.6 Bcf/d we mentioned. So a ton of gas coming online, and a lot of it's coming from oil-driven basins. So it's not necessarily gas price driven, these rigs are drilling for the oil. Of these basins, ArkLaTex, Appalachia and Anadarko are the ones you would see swinging if there is gas price or production swings. These are the gas-focused basins that we do have growing significantly. If the market were become over constrained or oversupplied, these would be the basins to watch out for.

(5:28): So what we do is we take this, and we put it up against our demand forecast. So shown on this chart is the five year average of the EIA [Energy Information Agency] storage. The blue line is East Daley storage balance. As you can see, the straight horizontal lines today around April, May, 2023, that line blasts through the five year average, going up past 4 Tcf total. So obviously that's not possible. The capacity of storage is capped. It's never been that high. What we want to highlight here is when we let our models run based on current and future strip prices, current activity and all these basins and the current demand, assuming a relatively normal winter and normal summer, what you get is storage filling and markets becoming unbalanced.

(6:21): We get a lot of questions. What if there is a really cold winter? What if there's coal-to-gas switching, gas-to-coal switching? Would that change your story? Sure, but it's not gonna bring down that line all the way to a balanced market. So it might bring it down slightly, but what we really are going to likely see is lower gas prices. Once this happens, you're most likely gonna see some deferred growth in those three basins highlighted, mostly gas-centric basins. If the price drops significantly, you'll likely see producers building a duck inventory, shutting in wells until gas prices improve. And then longer term, at least until demand returns, we forecast overall rigs to decline in these gas-centric basins. Together, this will rebalance the market as the free market generally does.

(7:10): A lot of people ask, it's a very bullish forecast, how do you guys monitor this? What do you look at? So since we come from an infrastructure lens, we follow the molecule all the way through the midstream. So we're able to look at the wellhead production, and then we flow it through a GMP system, and then we actually flow it through egress pipes out of every single basin. So between all those data points, we're able to watch production pretty closely in various different points. So this is Permian Basin dry gas production compared to the pipeline sample. So the pipeline sample is simply pipes that cross state lines have to report their daily flows to FERC [Federal Energy Regulatory Commission]. So you're able to see flows on all the pipes and get a sense of production in every basin. The problem is highlighted in this chart on the right side is the percent the sample shows continues to decline as more intrastate pipes are built.

(8:05): So as they build more pipes that don't cross state lines within Texas, we lose visibility in what used to be the best realtime data you could get. What that means is you have to rely more and more on production forecasting like ours to really understand what's going on. Recently there has been uptick in production, a notable uptick, and we got a lot of questions on, is this real? There's a lot of noise. Is this intra-to-interstate switching? We'll go through that. In this case, we do believe this is real. This these flows are on El Paso and NGPL, and I'll explain why that's important in just a second. So as I mentioned, we model all egress out of the basin. So once we do our production forecasting, we flow this through every single pipeline and every single basin. We do that because we do model these companies on an equity basis and to forecast those cash flows, we have to know what volumes are going through every pipe.

(8:58): This is a stack of eastbound flows out of the Permian. This is the red mark will stand for today, throughout all these charts. Eastbound we assume is flaw of the Permian. No surprise there. Westbound, kind of have a few interesting dynamics here right now. Kinder Morgan's El Paso line has been out for a while now, and that's limiting flows to the westbound. So you can see that dip there. Even when we assume this line comes back online in 2023, you won't see the flows hitting capacity. This is a demand dynamic pipeline where, based on California demand, it'll flow gas to the west. So if you get a really hot summer in California, you do get some egress relief, but generally you can't push more gas over or at capacity through the westbound pipes out of the Permian. Similar, I don't have a chart, but for the Mexico pipes, the capacity of those pipes is actually, the volumes will run well below the capacity. Similar dynamic there, it's really based on the demand in Mexico, and it's not a supply push pipeline. So those are effective constraints that we model into our basins.

(10:09): So northbound, generally the last direction we'll see fill out the Permian. And lucky for us, it's mostly interstate pipes, so we get to see those real time flows. So we've seen those start to ramp up and that's why we believe that uptick in the sample is actually a real uptick in production. But as shown by our forecast soon enough, northbound's full. We have seen Waha prices trading back the last few weeks. We forecast the basin to be completely full by beginning of 2023, might be happening a little bit sooner based on where Waha is trading. So we also track on the midstream side all the storage across the U.S. and we can see what storage has capacity. We assume right now within the basin, producers are sending as much as they can into storage. Once that ends, you'll likely see Waha continue to decline as it does indicate the basins are pretty full. So all of this together really indicates the production we're modeling is showing up. We also look at this through a midstream lens. When we forecast this in the beginning of 2021, a lot of folks said that we are well above, way too bullish. The next quarter, I believe midstream companies, five or six of them announced processing plan expansions. Now there's over 3 Bcf of processing expansions over the next two years. So that's just another way we use our equity coverage of the midstream combined with our production team to really validate our forecasts.

(11:38): Another map I'll flash up is the basis across the U.S., a pretty red story. A lot of the basis is trading back from Henry Hub. There's a lot of dynamics causing that. We won't get into that today. But what we really want to highlight is over the U.S., this is incentivizing producers if they can to send their guests to storage. We're in the shoulder season. This allows for storage to be at a healthier spot coming into the winter. So major hubs you see, they're all trading back, including Waha. This really incentivizes storage to fill. So last week, we saw a 100+ Bcf build in storage, didn't surprise East Daley. We've been calling for significant storage builds coming into winter. The dark blue line here is EIAs weekly reported number and then the red dots are that same forecast of ours that we showed prior. So as you can see, it's tracking in the right direction. We expect big builds the next few weeks as these producers continue to inject into storage.

(12:42): So that really summarizes our, say today through December 2023 view. We have a lot of production coming online, and when you look at the big picture, really no new demand. You could have colder winter, you could have a warmer summer, but LNG, there's no new projects coming online for a few years. So you have this production, a lot of it driven from associated place coming online and not a lot of places for that to go. Longer term, let's take a look at the LNG side of things. So 2019, beginning of 2020 we saw a few contracts signed. So these are contracts with third parties that sign with these LNG facilities, which helps facilities get FID [final investment decision] and built. 2020 internally, we call it the COVID cricket. Nothing happened, no contracts were signed. And then 2021, things really started to pick up. And these circles are just highlighting Europe as that's topical of, there's a lot going on with that energy crisis.

(13:37): But even before the invasion of Ukraine, you can see a lot of contracts are being signed. We believe this is just the realization of the world that natural gas isn't going away. It's actually the best transition fuel while we sort out the renewable side of things. So they come to the U.S. to get this gas, it's cheaper than the market right across the world. So we're seeing more and more contracts sign, and East Daley tracks this, and we come up with our own stack of LNG projects we would assume to be likely. So that's this stack here. So on the bottom we do have details and I believe these slides will be sent out, but really what we want to highlight is from 2025 and beyond, you have a significant call for gas once again. Circling back to the first part of the presentation, this is the next time slot I was really speaking of in the short term; supply going up inevitably due to the activity we're seeing in all the basins, and weather aside, which is a big, big part of it, demand stays relatively flat.

(14:42): After that, you do see a massive ramp in demand, and you'll see a call for more gas into the markets. So when I said this is going to be a wild ride, you'll see probably prices come down and then in the outer years they'll come back up as there's a call for production to feed this 12+ Bcf of gas. And of course this is our likely list of LNG. There's the LNG Mexico facility that was mentioned in the intro video. There's a few others in Mexico that would actually help Permian egress because it would pull more demand that way. So this is a, I'd say a low end number for long-term LNG out of the U.S.

(15:21): Another question that we ask is, besides the Permian, the ArkLaTex in the Northeast, these contracts are generally 20 years long. That's a long time to call for gas out of the U.S. out of just one or two basins. So the next scenario I'm going to flash up is where could we get gas from now through 20 years from now? So northeast, no shock here, MVP, fingers crossed. But after that, hard to see long haul infrastructure getting built out of the northeast. That basin is one of the largest gas plays in the U.S., but unfortunately it's capped by political regulations across the board. So you'll see smaller projects on existing infrastructure, but a 2 Bcf plus pipe coming out of Northeast just isn't likely in our eyes. ArkLaTex, massive basin. We have heard drilling location inventory issues 10 plus years out. So I'm not talking the near term, I don't wanna freak anyone out, but it is a smaller location.

(16:23): We have heard the core 10 plus years is kind of a time horizon we've seen. So the X is dramatic, but you could see less gas coming out of the ArkLaTex. Permian, before everyone jumps on me, this is on a situation where oil goes below say $50 or $40. So I want to highlight this because the biggest basin in contributing to our gas forecast right now is the Permian, but that basin, they're not drilling for gas. So when we're looking at LNG and risk of where you're getting your gas from, if oil were to drop or have a swing down, you would see gas out of the Permian drop significantly. And that could be a problem if you're looking to source your gas from there. So longer term, what could this mean? You have the Eagle Ford oil and gas play, you have the Rockies, you have SCOOP/STACK.

(17:15): So there is a lot of infrastructure that we look at that is running empty that used to be key infrastructure, but as these basins have just been in natural decline, they don't have volumes going through them. And if it comes to a situation where you're looking 10, 15 years out, it might make sense to source gas from other regions of the U.S., which would allow you to utilize old infrastructure. Top of mind, there's pipes that run down from Colorado, so on the west side of Colorado that run down into the San Juan; you could pipe those over and come through the Permian even if there's less gas flowing through those pipes. So what we really wanna highlight is there's a ton of options as far as where to get gas from. A lot of people focus on the Northeast Permian, ArkLaTex, but it's key to look longer term and think through as gas will be a play for 20 plus years out of the us.

(18:14): So circling back on the key takeaways that I really wanted to highlight today, we believe based on current activity, current production models on the natural gas and crude side, that the markets will see a significant amount of supply hitting the markets in the next, call it 12 to 18 months. To take this supply in the short-term, there's not a significant amount of demand. We have looked into coal-to-gas switching scenarios and overall it doesn't affect our balance significantly enough to make a dent. We've actually heard talk of switching from gas back to coal based on coal production coming into 2023. Longer term, we will see a new demand source coming online throughout the years. 12 Bcf and new LNG on the conservative side, which will be a call for all the gas and oil basins out of the U.S. to feed the global demand for gas as that continues to increase throughout the years. And like I mentioned, this could result in some ups and downs over the next year in prices in production of gas and oil. So really what I wanted to hound home is our forecasts are based on strictly the data that we pull in, the activity we see, the wells that we watch, and this results in a mismatch market in 2023 with supply and demand on the natural gas side. So with that, that is the end of my presentation.

JY (19:51): So what odds do you put at Mountain Valley?

ZVE (20:11): Yeah, so that's a topical one. We do model it in our northeast egress stack as well as our equity models to come online. So internally, I would never say a 100%, but we say more likely than not to come online and there's been more political, I'd say help there, which helps out, but it's got a few more water crossings from what I understand and we believe they can get it done.

JY (20:40): So Zack, prediction on natural gas price average for 24 to 30?

ZVE (20:53): 24 to 30. Well that's a tough one, to the cent. Well I don't know what the Ford curves at right now. I would say 24 to 30, it depends on what production's doing. I know that's a roundabout answer, but the markets are good at asking for more gas production to come online and I'd say if we see more LNG facilities start to FID, you could see I'd say above four. It's hard to say, but 2023...

JY (21:28): Where do you see the bottom? Maybe that's a, where's the bottom?

ZVE (21:33): I think we could see sub two in 2023 if production comes online like we're looking at it to. Really?

JY (21:39): Will the major use of hydrogen green or blue in the future be energy storage, backup power or primary electricity generation or other.

ZVE (21:58): I would say that there's a few people here I've seen that are more experts in hydrogens. That might be a question for them. We're really focused on the natural gas long-term side of things, so I don't have a great answer there for that one.

JY (22:15): Hey, a lot of people take the fifth, right? So you mentioned Waha basis blowing out any thought on near term price forecast until new pipes or expenses come online or if Permian products will need to cut production until there's enough egress capacity or demand?

ZVE (22:33): I can do that one. Good. Yeah, we get a lot of questions on Waha. As I showed on the map, it's $3 back from Henry Hub currently, which does hint at the basin being tight on the egress side of things. It looks like it's been tight for a while. We looked at flows to Mexico, and they had a hot summer just like the U.S. did. So flows south were actually the highest we've ever seen July through August, so that was probably helping relieve some of the basis there. But what people forget is, I like to look back to 2019, the last time Permian was truly constrained, we saw Waha back $3. So I think in people's heads and in my head, when you see back $3 you say, oh it's constrained again. It was 2019 was when it was at $3. But Henry Hub in 2019 was also around $3. So trading at $7, $7 plus, when you look at the outright price of Waha in 2019 and then in 2020, it went negative a few times in 2019 and it was around zero to 38 cents in 2020. We have more room to drop, I would say. If you assume it gets as tight as 2019, you could see it $6, $7 back from where he hub currently is trading around that true zero price.

JY (24:00): So when do HH, TTF and JKM become linked and will one remain premium to the others?

ZVE (24:16): Yeah, personally I don't think they'll ever be a 100% linked.

JY (24:21): What is HH? Maybe I'm the only one here that doesn't HH, TTF and JKM, what point are those?

ZVE (24:29): It's really U.S. prices versus international gas prices, you could think of it. So when is the U.S. market gonna link with say Europe gas markets?

JY (24:39): Henry Hub is HH. TTF is... But they can't be linked probably because of... Why don't you think it'd be linked?

ZVE (24:54): Well right now you see in the news a lot of times where they talk about Europe and then they talk about US prices and that's just not right because they're disconnected. We export 10% of the total gas we produce, so we're already maxed out on our LNG facilities. So whatever Europe does right now price wise, it shouldn't affect the US prices cause we can't send them anymore gas. Longer term, the more LNG facilities you do bring online, the closer that connection becomes because if there is a point when the LNG facilities aren't running at full capacity, you could see some more parity between the prices. I don't think it'll ever be a direct correlation, but more so than it is today for sure.

JY (25:36): Did you mention last night at dinner about how much more we're going to transport or the NLG or LGS over? There a quote somebody said like, we're doing so much now and we're gonna increase that in the next three to five years. Like three times or four times or something?

ZVE (25:59): Yeah, no, we're around 10 Bcf/d or 11 Bcf/d exporting, and I think our model has it going to 25 or around 23 by 2030. And then you imagine that continues to grow. There's a significant amount of international countries that still rely on, I would say older school sources of energy, not even coal in some nations. So the amount LNG exports could grow as significant after 2030.

JY (26:30): Regarding Alpine Hyde, do you see a ramp up in production from APA?

ZVE (26:48): Yeah, so there is a rig on their system again, it is a gas focused play so I would expect that to ramp. The problem with that system is, and I haven't looked at their hedges, so if someone is here from APA, but it's very gas-focused, so based on our forecast of being oversupplied next year, you could see that rig drop off once gas prices start to come back down. So I know there is a rig operating on the system right now, and so you will see probably an increase of volumes coming into the end of the year as prices drop. Historically we've seen rigs drop off that system.

JY (27:28): Do you think Permian growth stalls from here or does the basin continue to grow and flare gas?

ZVE (27:37): So our view, and some murmurs from being around Houston the last week, is they appear to be flaring already. So for better or worse, our assumption is crude oil still gets out and they flare the gas that they can't get into storage or on egress pipe. Now I don't think that's everyone, but it does appear they're starting to flare stacks back up as they get constrained.

JY (28:06): Is Mexico building LNG facilities?

ZVE (28:27): They have one connected to the North Baja Pipe. It's Sempra facility. That one is under construction, it's reversing an import facility. They also have another one down the coast. It's a Pacifico project by Sempra as well, also an import facility. I don't know if that one's FID or moving forward yet, but they do have it proposed and they do have pipeline capacity to get gas from the U.S. to those facilities. So that would be a bonus for U.S. producers and gas cause we could feed those LNGs.

JY (29:01): How much is our policies that we're doing today going to affect prices in the future, like Europe and bad policies there 10 years ago affected the price. What about in the United States? Do you think we're good policies, bad policies? Not to get too much in the politics, but do you think, and do you it's going to be good or bad for prices?

ZVE (29:31): Depends on what side of it you're on.

JY (29:36): What are your thoughts?

ZVE (29:41): Yeah, I mean it seems like personally, the more the government gets involved, the higher prices go. But keeping that aside, I think the biggest issues right now are in the northeast. We really got to watch that because Pennsylvania, that area is typically a blue area where they still don't believe in natural gas even though it's one of the biggest basins in the U.S. and holds most of our natural gas under that ground. So one state could swing our natural gas production significantly.

JY (30:12): Now Pennsylvania's 38% of our natural gas or something. Some people Marcellus the guy from Chesapeake was some...

ZVE (30:20): I know he took up his point. Yeah, he stole it from him. But that that's where I see concern. As far as exports, things like that, I don't see as much of a concern. It's really on the east coast. We have so much gas up there. Those few states and few governors could change the whole outlook of the gas market if they really took a strong position.

JY (30:43): It's so sensitive. The price is so sensitive, based on just one or two...obviously Biden has heard us in five or 10 different ways coming out of the gate. What do you see happening with Mexican demand?

ZVE (31:06): So our forecast doesn't have an increasing a significant amount. I think over the next, call it seven or so years, a Bcf of increased demand, and that's really just being able to take more natural gas, switching over to natural gas is more of a fuel source. So the LNGs would help that. But overall Mexico demand coming from the Permian or different parts of the U.S., we have it increasing kind of at a slow, steady rate.

JY (31:33): How can everybody here help you in your East Daley Analytics experience?

ZVE (31:41): Well, like I said at dinner, we're kind of here because I walk into a room, we've been around for seven years and a lot of people say East Daily who? So we're really trying to get our name out there just to show that we do fun fundamentals analysis on all the commodities as well as look at the midstream infrastructure. So really just reach out if you ever have a question on infrastructure, we guaranteed to have data on it.