House Finance, 5/26/26, 1:30pm

Okay, I'm going to go ahead and call this meeting of the House Finance Committee to order and let the record reflect that the time is currently 1:37 PM on Tuesday, May 26th, 2023. 2026. And looks like our seating is a little changed up here, so I have to get used to the ordering when I call the roll here. I've got Representative Stepp and Representative, uh, let's see, Bynum, Representative Co-Chair Shiragi, Representative Co-Chair Josephson, Representative Jimmy, Representative Galvin, Representative Tomaszewski, Representative Hannan, and myself, with Chair Foster. And let's see, before we start, if folks could mute their cell phones.

I would also like to recognize that we have a number of legislators in the audience here today. Thanks for joining us. We've got Senator Gray Jackson. We've got Representative St. Clair. We've got Representative Mears, Representative Sadler, Representative Eichide, Representative Colombe, Representative Underwood, Representative Holland.

Did I miss anyone? Senator Giesel. Thank you for joining us, Senator Giesel. And I've got St. Clair. So, so with that, I think we've got everybody covered.

Thanks for being here today. And so what we're going to do today is return to House Bill 381. That is the gas line presentation by Gaffney line. And so if I could invite up Mr. Nick Fulford, Senior Director of Gas, LNG, and Energy Transition. If you could please come to the table, put yourself on the record.

And I guess maybe I might just look around to see if we've got any questions before we get going. I think what we'll do is go ahead and allow for questions during the presentation for committee members. If you have any, feel free to jump right in. So with that, welcome, Mr. Fulford.

Thank you very much, Chair Foster, and good afternoon, committee members. So for the record, Nick Fulford, Senior Director at Gaffney Cline for gas and LNG. So before we start, I know it's been a little while before— since I've been in front of this committee, so I just wanted to briefly talk about our basis of opinion. So—. I'm so sorry, Mr. Bulford.

I believe we also have Representative Allard online, and so I just wanted to recognize her as being part of this committee. And so with that, please proceed. Thank you. So just briefly on page 2, I wanted to, in the interest of full transparency, point out that Gaffney Klein is an indirectly owned subsidiary of Baker Hughes Corporation. Baker Hughes manufactures equipment for LNG projects worldwide.

I think their equipment is in 95% of projects, and I'm sure, as you've noticed, they've been mentioned as a supply partner by Glenfarm. So in the context of today and the advice that we provide for the legislature, I just wanted to make it abundantly clear that the work that we do in our consulting activities through Gaffney Klein are completely ring-fenced from the work that Baker Hughes does more on the, on the LNG side. So there are just named individuals who work on the project with myself, and there isn't any communication between us and the parent company. So happy to answer any questions about that now or any other time. But with that, I'll move on.

So as part of the history with Gaffney Clyne, I think not me personally, but certainly somebody from Gaffney Clyne has been working with the legislature, with state agencies for probably over 20 years now.

And my own involvement with the legislature and with state agencies and indeed with the LNG projects started in 2013 with the passing of Senate Bill 138. So at that time, I worked quite extensively with Department of Revenue, and under Governor Parnell, a body was created, the Municipal Advisory Gas Project Review Board, and I had the pleasure of working on that with many of the borough mayors at that time on substitutions for property tax, including a PILT, a payment in lieu of tax. So for me personally, it's been quite a journey over the last 10, 12 years, and so obviously very happy to be talking to you today about this particular topic and where it sits currently.

So I think it would be true to say that property tax has been a major hurdle to the development of the project since its early days. It's been clear that some kind of suitable alternative acceptable to all the stakeholders has been needed for all that time. So in that regard, I wanted to just offer up a few general comments as we think about the materials in more detail and indeed what's transpired over the last several weeks in the legislature. So I think the first comment is that I've worked on probably dozens of LNG projects over the last, well, 40 years really, often in situations like Alaska where the impact of a single project, particularly in a kind of a resource-based economy, has such a profound effect on the future of the state and its citizens that it obviously engenders a lot of dialogue. And this question of appropriate split between project stakeholders and the project sponsors, it garners a great deal of attention.

And I would say that what we've seen over the last months, indeed over the last few years in Alaska, is not in the least unusual. It's a very hotly debated topic. There's a lot of different points of view on where it should be set and where it shouldn't be. And so I— you know, in terms of what's been happening the last few weeks, it's not unusual, and it's part of the process. Of reaching an accommodation on a project of this scale.

The second thing I wanted to say is that the Alaska LNG project is certainly the biggest gas infrastructure project under discussion today, and even looking back in history, there's a couple of the Australian LNG projects that probably get close, but at the end of the day, it is a huge undertaking on a global scale. And in that sense, it's not so dissimilar to TAPS. You know, it's a project that if it went ahead, it would define Alaska in, in terms of this sort of, um, engineering ambition and, and outcome. And so again, that's another reason why the project and how it's taxed is, is, is attracting such a lot of attention. You know, British Columbia, a great example in this respect.

It took about 5 years for the project and its host government and indeed the Canadian federal government to finally come to an accommodation on tax of various descriptions. But when it did so, obviously it enabled that project to go ahead. And today, as I'll mention later on in the presentation, they've got an operating project. They're, I think, about to announce an expansion to phase 2. So all that preparatory work and all that concern about the split between, you know, government take and developer, you know, that's at a point now where that project is starting to generate billions of dollars in earnings.

And indeed in tax revenues.

I'm sorry, Mr. Fulford, maybe if I could go ahead and jump in and entertain a few questions. We've got Representative Galvin and then Hannan. Representative Galvin. Thank you, Co-Chair Foster. Through the Chair, I do appreciate that your vast experience in looking at gas line and various projects worldwide and even in Alaska.

You had mentioned your work with Governor Walker, and what I'm going to ask is throughout your presentation later, if you would weave in when you get to the part— I know that AVT is not a new concept, appreciate that— and if you could share with us at that time, I believe there was a little bit of a different way of looking at impact and the dollars that would go to Alaska. And I'd like to hear your comparison of that when we get to that point. I think that's important for us to have a little bit of that history and I guess context, if you will. And the other that I wanted to ask you is if you would, as you're again deeper into this presentation, when you get to the point where you're talking about comparative numbers with Texas and Louisiana. If you would give us a bit more context there too, as it relates to Alaska and this project, which is, is quite different, and also share with us where— how Glenfarm is doing on those projects, where they really are in terms of getting to export or to market.

Thank you. Okay, thank you, Representative Gellin, and certainly through the chair, I'll be sure to make those comments. And before we go to the next question, the layout of this table is a little different than Juneau. It's a little harder to see folks on the sides. And so I'm wondering if maybe if we put our mics down and then if you have a question, then if you just raise the mic, then I can— I can see folks have questions.

So that'll be an easy way to do that. Rep. Hannon. Thank you, Chair Foster. Mr. Fulford, in the Gaffney Klein report to the legislature that was done in December, Number. One of the charts that you include in that is the tax incentive for other U.S. LNG projects.

And one of the more common things I see through it, that chart, both from property tax and sales tax, is a 10-year abatement of taxes, not permanent or in perpetuity. So when—. Talk to me about how come in Alaska we're looking at longer abatement than that, or is 10 years work? And it —seems to work in Louisiana, Texas, and maybe Maryland. Can't quite tell from the Maryland bullet.

But for most of the tax abatements that you're looking at there in U.S. Competitive projects, it's 10 years. Thank you, Representative Hannan, and through the chair. It's actually an excellent segue into one of my other introductory comments.

So for a capital-intensive project of this sort, You know, which, which is even bigger than a typical LNG project because of the pipeline, the gas transmission. Really, the, the make or break for really any project of this sort is, is in that first 10 years. And equally, these projects— one of the most difficult things with an LNG project is, is to get it over the line to FID.

And in doing so, it usually comes down to sort of pennies per MMBTU in terms of the delivered price and the cost. So the reason that these 10-year tax holidays are common is that it has a disproportionate effect on the project economics. So with a sort of discounted cash flow approach, as these projects typically will have, for example, you know, if you get out 10 years, the effect of a property tax or whatever it happens to be is about a third of what it would be from the outset. And, you know, if you think with this project, once everything's in the ground and the project starts, right from day one, they're probably paying about $1.8, maybe $2 billion just in debt service.

So as time goes on and the debt gets paid down, the project becomes depreciated and so forth, that's when the project can afford to pay higher taxes and so forth. And the impact on that initial hurdle rate is a lot less. So in Canada, for example, they did a tax deferment. So it wasn't a reduction or an abatement, but all the sales tax due was pushed out 20 years, uninflated. So effectively they have a sort of a 20-year window to essentially get ready to pay that tax that was due right at the outset of the project.

So it can't really be overestimated— overemphasized, I think, that it's that first 10 years of revenue and financials that really determines whether the project will move or not. And that's really why they do the 10-year holiday in Texas and Louisiana. Follow-up? And in your analysis— thank you, Co-Chair Foster— Mr. Fulford, is there any scenario where Alaska could take that risk at 10 years? But because most of the documents we— the bills we've seen have a much longer time abatement for it.

And I guess as a policymaker, when I look at other jurisdictions, you go, okay, we can kind of predict out 10 years, but when we're getting in the 20 and 30 years, we start having some real risk for return on our investment, or how do we figure out the price that it's going to be to consumers in 20 years if they're still carrying a high debt service and we don't know the total construction costs, etc. But I can wrap my head around sort of a 10-year window. But when I start thinking about a 30-year, that's a real struggle for me. So in your guidance to us, do you see Alaska being so different that we have got to look at a 20-year abatement for the investment price that this project is because it's a gigaproject. Thank you, Representative Hannon.

And I think through the chair, what I would offer up is that the whole perspective around this project is completely different if you look at it from a developer or a government, host government point of view.

Many LNG projects, and you know, Brunei is interesting because Brunei, the LNG project there started up just a couple of years after the original one here in Nakiski, and it's still going. It's produced billions of dollars of revenue, not just for the Sultanate, but also, you know, for Shell. And equally, you know, cost of capital for the government, for any government, is very different to the sort of urgent need to pay dividends by a developer.

So in 10, 20, 30 years, this project could be generating billions of dollars in free cash flow, and the way in which it's taxed in that time frame. I wouldn't say it makes no difference, but it makes little difference to how you look at that project today from a developer's point of view because those cash flows are so heavily discounted, they make almost no difference.

So in that sense, I would suggest that alleviating the tax burden on the project for that first 10, 10 years or so is of far more importance than what you do after 10 years.

And obviously, this will all hinge around the developers and how they perceive the returns and so forth, but, you know, returning to what's considered a— what you may consider an appropriate level of taxation after 10 years, I think, is— is less important to the developer than giving them a break in the first 10. I hope that's helpful. That is helpful. Thank you. Okay.

Also, I'd like to note that we do also have online Representative Moore, and I know at the beginning we had Representative Dybert on. Looks like she's not right now, but probably will be back on later. Representative Stap, question? Thank you, Chair Foster. Through the Chair to Mr. Fulford.

Mr. Fulva, thanks for being here and all the work you've done for the state in the last decade or so. So I heard you talk about a few, I think, really important things for the public to hear. You have lots of experience, 40 years in this industry, and projects all around the world. And I know we're going to get into the nuts and bolts of this in a little bit. But through the chair, I feel like I should ask you maybe the foundational question here, which is very simply, in your experience, Can a project of this magnitude and the complexity and really on a global scale be financed and developed for our state without some sort of large-scale abatement that is designed to deliver stability and predictability for the developer to get the financing and capital that they need for the project?

Through the chair. Thank you, Representative Stapp. And through the chair. In a way, I'd pick up on my last response a little bit, in that in very basic terms, there are 3 things wrong with property tax as it stands today.

One is the magnitude of it, and I, you know, obviously it was written with a very different kind of project in mind. I don't think it was ever conceived that it would be used on, on a $50 billion investment. So, so number one is the, the magnitude. Second, um, is that it, it provides a, a financial burden right on the front end of the project, which, as I pointed out, is exactly the wrong time for a project of this sort, which has precious little headroom to support a tax of that sort. And the third element is its unpredictability.

You know, the— obviously there's a very carefully written framework around property tax, but at the end of the day, taxable value and how it's determined can vary. I think we're, we're seeing that with TAPS at the moment. And so from a, from a fiscal stability point of view and, and being able to predict what's going to happen, you know, 5, 10, 20 years down the road, that's the other problem with property tax is that you don't really know what that tax is going to be. And as lenders and other people look at the project and they look at that degree of unpredictability, effectively they'll assign a risk to it and the cost of capital or the cost of debt will be higher and the project will be less competitive. So it's those three factors which mean that some kind of revision of property tax I think will be essential.

Thanks. Okay. Also, I'd like to note Looks like I'm not seeing Representative Costello on my iPad here, but looks like she's been online since the very start. So, Representative Costello, thanks for joining us. And we have a question, Representative Galvin.

Thank you. I appreciate your giving us this context of how important it is to jumpstart a project such as this one. And I'm just going to put it in very simple terms. I know that there's been a lot of questioning around two things. One is, why 10 years?

And the other is, why wouldn't it— the abatement go away, or the tax breaks, if you will, go away after the exporting begins? Are we waiting on that so that we can maybe modulate the price? Is that one of our concerns, that there may need to continue to pay for this— a project this large? Or is there something else that is coming into play that we need to better understand? Do you have the modeling of it?

Is another big question I have around that question. Because I really want to know why 10 years, why was that being bantered around, and if there is more information for us to know that helped us decide that. Thank you, Representative Galvin, and through the Chair. I'm going to start with the last part of your question, which is on the modeling.

I know in this committee you have seen a lot of data from Department of Revenue. And, um, again, I don't want to hark back to 10, 12 years ago too much, but at that time, um, there was a, a common economic model that was used between the 4 participants in the project, and it was used to create a kind of a common understanding of project economics and enabled each of the four parties to try out different assumptions around gas price, interest rates, or whatever it happened to be.

So I think over the years that same economic model has been developed. It's been looked at by various counterparties, a number of consultants, but at the end of the day it's what really is what's been being hosted by DOR today.

So I would put a great deal of faith in the DOR modeling and the model that kind of sits behind it. We've done similar models for other projects internationally. It's sometimes called an open book economic model, or OBEM. But ultimately, the purpose of that model is to enable this kind of understanding of project economics and the different effects. So picking up another part of your question about when the project starts to export, I mentioned that, you know, so the project will probably be about 60, 70% project financed.

So let's say it's $50 billion, about $30 billion of that will be debt from a consortium of banks, probably led by many of the major industrial banking giants that are familiar to you, I'm sure. The cost of that debt will probably be 5, 6, 6.5%. It partly depends on whether federal loan guarantees are available, If you do the maths on that, it's about a $2 billion debt service, not even including the payback. Those debt instruments for LNG, they can be 6 to 8 years, sometimes a little longer, but it will take the project 6, 8, 10 years to begin to sort of catch its breath breath, so to speak, after paying off that debt, which is again another reason why this first 10 years is so important. And then the other part of your question, which relates back to some of my introductory comments, is, well, do you want to bring back property tax or do you want to bring back something different, which may pay a similar level of tax?

Because, as I say, one of the difficulties with property tax is that it's not predictable, whereas the volumetric tax is. And, um, you know, so, so a tax that's similar order of magnitude maybe, but more predictable, is, is probably better. Might be even better for the state too, compared to going back to property tax.

Thank you. I appreciate that context. I think a lot of people are juggling in their minds what the advantages of each of those would be. I especially appreciate you better articulating that volumetric may be more predictable. Of course, there's some assumptions there about the, the amount of throughput and all of the things involved with Alaska purchase versus international purchase and how we're going to make sure the price here stays low to Alaskans.

Whole nother story. But related to that, there was a real question that I had with the volumetric— okay, I know now. This is important to me.

You had mentioned that the banks would likely be— or investors would likely be coming from larger banks, and that's how a lot of this will be. And I think we were told the assumption was 70% of that was from the Department of Revenue. And so in the back of my mind, I was thinking about other projects and that had investment by producers. So that's entirely possible here too, I assume, right? That it could be, um, Conoco— any of the large producers up there may decide to invest here.

And, um, can you share with us how, uh, we would ensure that Alaska is still keeping the right knobs on knowing the real price of throughput to consumers will stay looked after if we know that the producers are also the ones who are, you know, let's say co-owners of the pipe. It may change how this whole equation gets worked out. And can you share with us what what that might look like, and if you know of other projects that have been put together in that way, how will that be— how will that change this up? Uh, thank you, Representative Galvin. If I may briefly clarify, we're talking about in-state customers, correct?

Yeah. Yes. Thank you. But it could be for the state of Alaska too, right? Because if the price changes according to how industry says it's costing them to do the infrastructure that's necessary, because if they're part of that build, they also all have the control over the price.

And so maybe this hasn't come up in any other project in the world, but I would guess perhaps it has. And, you know, we have two things we're looking after: Alaskans and how much they pay. And then the other thing is our duty to make sure that our revenue is in place and looked after. So those are the two things I'm kind of keeping in mind here. And, and that gets a little tricky when we have perhaps investors who are also producers.

Thank you, Representative Galvin. And I can assure you that There are many projects around the world where this comes up, um, and, um, there, there are a variety of ways that people typically go about addressing it. Um, so certainly for, for quite a number of LNG projects, they, they offer the opportunity to sort of gasify the, the host economy. So sometimes we're talking about countries that have no they have huge gas reserves, resources, but no developed gas industry. So obviously here that's a little different in that the Cook Inlet has been providing gas for decades.

But how gas resources are really reserved for the purposes of in-state use and how consumers are charged very often will be part of this initial sort of project development framework. So sometimes there would be, for example, a domestic market reservation, which perhaps could be 10% of the gas being produced, depending on what country you're talking about. And then, you know, that 10% would be assigned to power generation or to industry, etc. So then you get the secondary question, well, what should people charge for that? And sometimes it's an explicit number.

It's, well, you know, we think that, you know, $5 is a good number for domestic demand to make it work. So in that situation, the project developers have to invest in enough infrastructure to provide that domestic market gas. And conceivably they might have to subsidize the gas, um, for, for a period of time. But as I say, you know, we're talking about host governments that typically are at the beginning of their gas journey. So, so I think the, um, the main answer really to your question is that this often comes up, and this balance between what, you know, residents and sort of citizens charge versus what the project charges for LNG.

You know, it is something that often gets dealt out at the beginning. And again, you know, we're talking about 3 BCF of gas that will be exported and maybe 3, 4, 5, 600 eventually that is for in-state usage. So the— in proportional terms, the LNG will dominate for the economics.

And maybe just for the committee, we haven't made it past the first slide, which is the agenda slide, and it would be— it's good to have kind of the big picture. I know that folks have kind of jumped to the end, which is kind of the big picture questions that we have, but I think for some of the folks who might not have a good foundation built up, it would be good to maybe get through the slide deck and then we can kind of get some of those other questions. So, Mr. Fulford, if you can continue with the slide deck. Of course. Thanks, Chair Foster.

So this first slide, it summarizes perhaps some of the discussion over the last few minutes.

And really what we have on this slide is is the ingredients, the key ingredients to what I would call the principles and the fiscal architecture of a project, of an LNG project here in Alaska.

And from the lens of kind of stability and predictability, most of the features on this list are, if not defined, then they operate within a fairly good structure. So for example, you know, upstream tax and royalty, there's been a kind of an ebb and flow over the decades to account for different types of reserves, different types of technology. But at the end of the day, it's a proven mechanism that people can look at and predict and subject to being reviewed, I'm sure, will apply to the LNG project. Same with corporate income tax. And indeed the federal income tax.

You know, these are mechanisms which are well defined. Federal support is an interesting one because I mentioned that the existence or not of federal loan guarantees is quite a key feature for the project. It makes quite a difference, not quite as much as property tax, but it's comparable. But even there, there's federal legislation which allows for that type of activity.

Fiscal stability, I've mentioned a couple of times, and there's much more written about that in the report that we did back in December. But suffice to say that for the reasons I've already outlined, fiscal stability is pretty important. For both developers and lenders.

And then in terms of in-state supply, obviously some discussion as to which features of the pipeline might be regulated by FERC and which by the RCA. But ultimately, consumer prices in Alaska are governed by the RCA. Now whether their scope and regulatory regime might need adjusting or extending for, for the LNG project. I think it remains to be seen, but at the end of the day, it's there. So, so the one you're left with, um, which for the three reasons I've, I've mentioned is, is a critical one to address, will be the, the property tax, uh, which is really why we're here today.

So property tax has two, um, features to it. Um, some of it rolls back into the state, but quite a lot of it rolls back into the municipalities and the communities that are affected by the project. So what I thought would be useful to do is to sort of, um, look at what examples we can find internationally of a similar impact fee mechanism slash property tax which we could perhaps learn from. The ones that I've been able to convert into cents per MCF I've converted, some of them work on a different level. The highest one that I could find was Hammerfest in Norway.

It's a community of about 11,000 people and they're hosting the shore-based aspects. Of the Snøveg project. It's a relatively small project in, in Norway, but the property tax that goes to the municipality there works out as $0.07. Then we've got quite a series of Canadian examples which are mainly directed towards the indigenous communities that are most significantly affected by the LNG facilities. Um, so, you know, certainly for Kitty Mat, it's, it's a relatively small community.

The levels of property tax are a couple of orders of magnitude less than what we're talking about here, so it comes out about 1 cent per MCF. Similar for, um, the, the broader BC fund. And then for wood fiber, it's a little bit more, it comes out to 4 cents. Um, Gorgon in Australia has a conservation fund that, that is a similar category. But maybe the most interesting one is Papua New Guinea.

Um, there are two projects there. Um, the, the first project, which kind of paved the way for both a community funding and also equity in the project was the project developed by Exxon and Santos, obviously two companies that you know very well here in Alaska. Some of the benefit there comes from a 2% royalty on the gas, and quite a number of the impacted communities have— well, were offered equity in the project. So out of, I think, 19% government equity, about 4% of it was through boroughs and impacted municipalities. So that kind of compares to the 25% option that the state has here in Alaska.

But anyway, those are some examples that, that might be relevant. Representative Sharagi. Thank you, Co-chair Foster. I don't see equity listed for any of these other projects. Is equity a nonstandard third form of compensation.

And I know that there's been a lot of discussion on equity and it being problematic in terms of local municipalities, in terms of the North Slope and the Kenai Peninsula. Can you speak to that at all at this point? And keep your remarks on the lighter end, I think. Thank you. Thank you, Representative Schroeder.

So most, most LNG projects involve a state oil or gas company. And so equity— government equity in the project is usually done through that agency.

And the way in which that's negotiated and costed is typically managed fairly directly by the host government. Um, it's very common indeed for that state oil or gas company to be given a carried interest to start with. It's, it's usually of a 10-15% level, and it's paid for over, over the years with project revenues. So as the LNG starts to flow, the payment for the equity is is— it comes from that. But what it does mean is that the state has a seat at the table.

It sees all the LNG disbursement. It notes, you know, really where the financials are heading. And so it— that's one of the main benefits of that structure. Follow-up? Thank you, Kucher Foster.

You said that the state typically foregoes revenue to pay for the equity. Is that what I'm hearing, is that rather than receive royalties on the front end, some of that would be captured for a short period to pay for the equity? Can you clarify that for me? Thank you. Thank you, Representative Schrag, through the Chair.

It varies, but the carry arrangement, you could perceive it as being a change in royalty or tax, but typically that side of things is left completely intact and it's more of a— it's a bit like a mortgage with the main project sponsors. So it's an independent financial arrangement which is used to pay for the equity as opposed to any kind of direct tax concession. Thank you. Okay. Our representative staff.

Yeah, thank you, Co-Chair Foster. Through the Chair, just to kind of piggyback on Rep. Schraggi's question to Mr. Fulford. So we heard pretty specifically from the developer that the equity arrangement did not work for them based on their capital raising perspective, right? That was pretty clear that they made it on the record. And I'm curious your thoughts on that because, you know, it makes sense when you're trying to raise capital for a project, that if you were going to give ownership interest and defer that ownership for basically payment in lieu of a tax later, that you would struggle to raise the capital for the construction costs.

I'm curious if you can comment on that through the chair. Thank you, Representative Stap. And through the chair, my understanding is, is a little different in terms of what the developers have have indicated. My understanding is that the feature of equity that they weren't comfortable with was the idea of exchanging it for some kind of property tax concession. But equity in principle by the boroughs or state government, I think, is a relatively straightforward item.

Again, I don't think a carried interest is being discussed, so it would have to be funded. But, you know, here in Alaska, obviously, there's many ways in which that could be done. So that was my understanding, that in principle, equity in the project is acceptable, but just not as part of a property tax exchange.

Please continue. Thank you.

So this next couple of slides, these numbers on here are courtesy of the model hosted by Department of Revenue. And what I think is helpful to show is really the the order of magnitude of the— and this is version T, which came through resources. But— and the AVT, I should say, the local AVT here is a combination of both the strict volumetric tax and the locally imposed property taxes. But I think, again, coming back to my comments about the first 10 years, you can see that Really relatively quickly, we ramp up to about a $600 million tax requirement. And as you look at these slides, the way I like to look at it always is in the effect that this has on delivered gas, because ultimately that's the kind of competitive framework you're looking at.

And the project is— it works very nicely for us that way because give or take it's about 1 billion MMBTUs per year that the project delivers. So if you look at the numbers on the left-hand side, if you divide them by 1,000 you get to dollars a million BTUs. So for example, by the sort of late 2040s you're getting up to $1 billion combined state AVT, corporate income tax, and local tax. So that equates to about $1 a million BTU in terms of delivered price. It's not quite as direct as that because there are various other, you know, trade-offs that happen.

But nevertheless, I think this graph is quite useful to illustrate that we're talking relatively big numbers that show up in, in the delivered cost of the gas. Um, the, the other thing which is interesting from this slide, I, I've, I've split out state corporate income tax on the assumption that they'd either be C corps or certainly paying state income tax. And I think one of the interesting features of this is you can see how Corporate income tax, which is obviously profit-related, is very significantly smaller than the ABT. So the next slide shows really the same thing. It shows a cumulative— about a $27, $28 billion revenue up to 2062, so that's a 30-year period of time.

And of that, you can see that only the blue is corporate income tax. So again, 1 billion MMBTUs per year, 30 years, it's about 30 billion MMBTUs. So you can see there that it's the best part of a dollar if you average it out on the revenue. So just simply a way of illustrating really the order of magnitude and how it fits in with things.

Representative Galvin. Thank you, Co-Chair Foster, through the chair. So these numbers which you're taking from— it says hosted by DOR, Gaffney Klein.

Some key questions here are like where they're getting these numbers based on what project costs and financing assumptions.

And I just wanted to make sure that you feel like you vetted this so well that you feel comfortable with this. It's hard to know what the assumptions are here and how your assumptions from Gaffney Klein compares with DOR's assumptions. As you know, there are some, you know, clear assumptions made based on some pretty old data that I— from what I'm familiar with, and wondered if you would comment on that. Thank you, Representative Galvin, through the chair. There are kind of four— first of all, perhaps addressing the model itself, because there are two facets of the modeling.

You know, one is the maths and the Excel and how it all works. And as I say, I've deliberately referred to it as the model hosted by DOR because it has a lot of history and it's had a lot of people look at it. And so from the point of view of the Excel and the way the model works, I think we can take a great deal of comfort from the fact that so many people have looked at it and tested it out and audited it. But, but then—. Follow-up.

Representative Galvin. Thank you. Could you be a little more specific when you say a lot of people? Does that mean other economists? Does it mean folks related to this particular project who would be able to validate whether or not they were close or in the ballpark?

Just some sort of— what do you mean by other people? So again, and I was going to continue, Representative Galvin, to the rest of your question. Thank you. Through the chair. So the mechanics of the model, and I would— I think I'd invite DOR to comment more specifically because I think it's probably more appropriate for them.

But certainly it's been looked at by I think most of the major producers from SP138 days, so that would be, you know, Exxon, BP, ConocoPhillips in the original thing. I think other— well, in fact, Gaffney Klein was involved in this modelling back in 2014, '15. I remember sitting with Mr. Stickell even at that time.

And subsequently, I think other consultants have looked at it, maybe Gas Strategies, another London-based consultant. But the more telling question comes into what you put into the model. That's, that's really, I think, directionally where you are, you were asking. And so there are, in my mind, there are probably 4, 4 drivers, um, the things that make the biggest difference in terms of what you put in the model. Um, one is the gas price, because what we're talking about here is, is purely the midstream project.

It's, it's the treatment plant, the pipeline, and the LNG liquefaction. Um, of course, the economics that happen upstream are completely different, um, and I'm sure will garner a lot of discussion. So, so where the gas price is set, um, makes it— has a fundamental impact on the numbers that you're seeing here. Well, maybe not so much these, but certainly the corporate income tax. Um, the, the other one is federal loan guarantees.

Um, order of magnitude, it's with and without the loan guarantees, is probably about half the impact that property tax has. Um, then, then of course you've got the sort of main unknown of the capital cost. And so the DOR numbers I think have taken the most recent— and I think Mr. Stickell has testified in front of this committee exactly the same. They're basically taken from the most recent published estimate. Which I think came from Wood Mackenzie, and it's been inflated just by inflation over a couple of years.

So I believe the number they have is $46 billion, and the sensitivities that they did around that using the breakeven matrix, which I find personally really useful in terms of illustrating the, the economics of the project, um, so they've built on that with a 20, 40%, and so forth addition.

So really, those are the key things. So it would be gas price, capital cost, upstream cost of the gas, and the property tax.

Thank you. Okay, I'd also like to note that we have in the audience with us Representative Johnson. Thanks for joining us. And next up, I've got Representative Hannon. Thank you, Co-Chair Foster.

Mr. Fulford, my questions are about the two models that we were just looking at, this page and the page previous. And I first, I guess, I want to just make sure that the models are done on the current rendition of the Glen Farm project, not prior versions. No. Okay. Through the chair.

And then specifically, Thank you, Chair Foster. When it gets to corporate income tax showing in the first slide shows it in 36 in the bar graph before this. Who are you having show as paying that? Because the developer and the primary engineer are both LLCs or privately held, so they're not paying corporate income tax in Alaska. So who starts showing as corporate income tax payer on the project starting in '36.

Thank you, Representative Hannan. And through the chair, that gives me an opportunity to perhaps clarify. So I— in order to put the AVT and the property tax in the context of sort of wider tax regime for the project, I've specifically assumed for the purposes of this graph that the owners of the midstream would be C corps who would pay state corporate income tax. So I fully accept your comment that currently there are a number of stakeholders around the project that would not be paying corporate income tax to the state, but for the purposes of illustration, I've assumed that they would be. But I have no other sort of insight or rationale for saying they would be paying tax or not.

Follow-up? And so, thank you, Chair Foster. If the largest midstream producer partner became, say, Hilcourt, would that corporate income tax line just go away if our— if we don't make the assumption that they're going to be corporate income tax holders, that they are the largest operator on the North Slope and therefore I presume one of our larger gas producers, and then maybe they take over the midstream?

Yes, Representative Hannon, my understanding is that depending on the status of the companies that own the midstream, that it's possible that no corporate income tax would be paid. Thank you. Please continue.

Thank you, Chair Foster. So on this page, again, it's maybe one of my introductory comments that I didn't quite get to, so I'll just deliver it now. As you think about competition, really for Alaska, there's two elements of competition you need to think about. One is the, the Gulf Coast, U.S. Gulf Coast, which continues to be the source of many different projects that are either operating, under construction, or approaching FID. And I think, Representative Galvin, you'd asked earlier about the Glenfarm project.

So they have They have a project in Texas, Texas LNG, and they have one in Louisiana called Magnolia, which is at an earlier stage of development. I believe from what I've read in the public media that Texas LNG is still moving towards FID, but I don't believe it's got there yet. But there's a whole list of other projects that are either capacity increases, like Venture Global, for example. They've just announced a big capacity increase at both their main LNG export terminals.

And one of the good things about Gulf Coast LNG competition is that you, you know exactly pretty well what it is. The, the pricing for it is fairly transparent, and I think it's unlikely to change very significantly. The other element of competition, of course, is Canada, because the economics of the Canadian projects mirror pretty closely what you're seeing here in Alaska. Most of them involve a long pipeline. They involve either fixed plant, or in fact most of the, the Canadian projects are moving to floating LNG.

But ultimately, the, um, those two elements of the investment are similar. The Canadian projects don't have to invest in the gas treatment plant, but the source of their gas is more expensive. So really the difference between Alaska and Canada is really— you're almost swapping the cost of the GTP with the extra cost of the gas. So other than that, they're very similar. So that being the case, this slide is a useful reminder that, you know, capital deployment is globally competitive and that you've got a lot of projects south of here that are competing for that same capital.

Ultimately You know, the LNG is agnostic, you know, to where it goes. It's the same commodity. Um, so I think it, it's helpful to look at Canada and look at the tax regime there and consider how it might affect your, your decisions here. Um, interestingly, in the sort of last round of federal and provincial tax discussions that went on prior— just prior to FID for LNG Canada, one of the concessions introduced was a natural gas credit, which effectively brought their corporate income tax down to 24%. Here it's 28.4.

And obviously then, if you look at that in the context of the AVT, you can see that there's another very high potential tax burden there that, that would have Kosterdamm.

Representative Stout. Yeah, thank you, Co-Chair Foster. Through the Chair to Mr. Fulford, thanks for the slides. So last week we talked with Revenue regarding kind of comparative of this project specifically with basically total government take, state, federal, and local, and it seemed as if that the Canada LNG project was far more competitive in terms of total take, even as they look at going into their own Phase 2, than we currently sit under current law. And I'm curious if you could expound upon that through the chair, if you know.

Thank you, Representative Stapp. And through the chair, just to clarify, I heard most of the testimony, but I think your question is that they operate under a more favorable tax regime to the producer. Correct. Thank you. Well indeed.

And the, you know, the way in which that project evolved is quite interesting and perhaps has some learning for the project here.

That when that project, and in fact 3 or 4 other major LNG projects were conceived around the same time. And the British Columbia government were looking at wholesale prices in northern British Columbia, Station Two and Aco are the sort of reference points, and they were comparing it with the delivered cost of LNG to Japan. And they were seeing this huge price arbitrage between the two. And so the perception was that the project was highly profitable and would need to attract a special tax. So they passed a bill to apply a special LNG project tax on LNG Canada.

I forget exactly the numbers, but it was a fairly material addition to regular corporate income tax. They also applied a CO2 tax, which again was a relatively high tax burden.

But coming back to what I was saying about the challenges getting these projects across the line, I think there were two things. There was a sort of strategic premium for the federal government in Canada of securing a Pacific outlet for their gas. So the federal government were very much behind the project and gave it a kind of a national importance. Equally, I think, as the BC government became more engaged with Shell and the other developers, they could see that the economics were a lot less robust than perhaps had initially been thought. So the upshot was that the LNG tax was repealed, the CO2 tax was reduced quite considerably, and as I've said on this slide, there was a 3% natural gas credit applied to the project.

There were other measures such as the 20-year deferment in, in sales tax. Um, but yes, the, the, the LNG project in, in Canada was able to benefit from quite a bit of, um, uh, government abatement of, of tax. And it's interesting now, you know, any day I think they'll probably approve phase 2 of the project, be another 14 million tons, uh, And at that point, of course, the corporate income tax, although it's lower than it might have been, will start to generate quite significant funds for the provincial and the federal government.

Representative Hennan. Thank you. Mr. Fulford, because you mentioned it as a side note, and I've heard this, that Glenfarm has two other LNG projects that they're waiting on final investment decisions on, one in Texas, one in Louisiana. And I guess I'm curious as to what you speculate is holding them up, because they don't have the same pipeline logistics that we have holding our project up. And two, if one of those projects gets to FID before us, does that— I mean, that seems to me to put more into the same market that we're trying to sell to.

Um, give me your thoughts on those other two projects, why they're not already at FID, and if they get to FID before we do, does that screw us? Uh, thank you, Representative Hannon. I think, uh, through the chair, um, I, I'd probably limit my comments to, um, U.S. Gulf Coast producers more generally. Obviously Glenfarm perhaps might want to comment themselves. But, um, until early March, the, the, the sort of trend in LNG prices, supply-demand globally, was, was one of this kind of wave of additional production coming from the U.S. Gulf Coast and relatively stagnant demand in Europe.

It's a growing demand in Asia. Um, and as a result, you know, on a spot basis and equally even around oil index contracts, there was this kind of erosion of price. And in, in that environment, additional capacity from the U.S. Gulf Coast, I think we're probably facing a number of headwinds in terms of, you know, buyers keen to sign up for long-term supply and also the price they're willing to pay. Now, obviously, all that changed, you know, given what we've seen in, in the Middle East and specifically Qatar, where, you know, at a stroke, you know, a significant slice of global LNG capacity was removed and still not back. And indeed, some of it will take years to come back.

So Um, so I would expect, um, that trend of sort of lesser interest in LNG from the US Gulf Coast maybe being abated, and perhaps a bit more interest now in, in new projects going to FID. Um, in terms of competition, it, it costs a lot of money to move LNG from the US Gulf Coast to Asia, which is essentially the market that you're looking at here. The, the Panama Canal is limited in capacity. The Suez Canal is unusable. It even was unusable before March.

So you're looking at maybe $2.40, $2.60, maybe even $3 to move gas, and it takes a long time. As well. It takes, it takes about a month to get there. Um, so, so although I'm not familiar with the, um, you know, sale and purchase agreements, um, that Glenfarm have signed up for Texas LNG, it is a much smaller quantity, I have to say. I think it might be 4 million tons.

Uh, so in short, I don't think if that project goes to FID, I don't think it'll change the competitive position for Alaska. Thank you. Okay, please proceed. Thank you.

So, um, we're getting into a little bit more detail on this slide in terms of pricing, and it's perhaps worth explaining a little bit how this grid works. So you'll be very familiar with the this breakeven matrix that was produced by Department of Revenue using that same model we referred to.

And, you know, I think Mr. Stickel has explained very effectively how this matrix works in that the area of the matrix towards the top left, i.e., with a $46 billion CapEx number and a $1 upstream price that produces naturally the lowest breakeven cost of gas delivered to Asia. Um, for the purposes of this exercise, um, the, the first thing I've done here is to say, okay, well, what— looking back, what was the 10-year average LNG price paid in, in Japan, and how does it compare with the breakeven matrix, and what difference does it make with the— with and without the property tax. So if you look back, the, the average over the last 10 years is $10.41, and if you compare that $10.41 with the matrix, you can see that the area that I've outlined in red represents the cost-effective breakeven where effectively the project would attract investment and would pass muster economically speaking. So I'll perhaps pause there for any questions. Representative Gelman.

Thank you, Mr. Fulford. I appreciate you taking the time with us. So this This is a fantastic bit of data for us, but it is predicated upon one very important assumption that you just mentioned, and that's a $46 billion price tag. The, the last price tag that we had that I think was more publicly available was the one from 2015-2016, which was at $44 billion. So we're 10 years later and for whatever reason, the Department of Revenue has settled in on $46 billion.

Maybe you helped them with that, I'm not sure. But when I look at cost adjustment just using CPI, just a straight cut through, that brings us to $57 to $60 billion. So instead of it being $57 to $60 billion, we're looking at $46 billion. So it's a difference of perhaps up to, or at least minimal, $11 billion difference. And now maybe things have changed, maybe prices came down, something happened, labor came down somehow, or the design just in and of itself changed.

But it, you know, from what I've learned, special size pipe, all these different things that seem or feel very expensive. So this is a very key piece of information for us to understand because it's kind of the major assumption that this is— this whole bit of information is based on. So how different would it look if we just CPI-based that cost as opposed to what we're looking at here?

Thank you, Representative Galvin. Through the chair, obviously there's been a huge amount of speculation about what the capital cost might be. I would say it seems highly likely that it would be more than $46 billion given the general inflation that we've seen in, in the upstream sector and more generally. So the, the main question really is how much bigger and how, how much more capital cost can the project support before it just becomes, you know, uneconomic. So there's two, um, there's two, two ways of looking at that.

One, one is to, you know, look at this matrix, which I think is, is very helpful. And then the other point is, well, you know, we can look back easily and, and we can see where the $10.41 number comes from. But looking forward is a little bit more tricky, um, and in fact on the next couple of slides I've, I've done a little bit of that to sort of see where things might compare. But, um, but I think it's, it is likely that LNG prices and the sort of marginal cost of LNG into Asia will also go up. So the question is, well, you know, if the price of LNG goes up and if the capital cost goes up, then where's that sort of tipping point where the project can still go ahead even if it's a much higher capital cost?

Follow-up. Thank you, co-chair. So in your professional opinion, Would you be able to give us what you would estimate the cost would be today?

Thank you, Representative Gallin. I wouldn't want to hazard a guess because there are so many facets to it. And as you pointed out, you know, one of the questions is, well, you know, is the project concept similar to what it was back then? You know, for example, you know, we're seeing this move towards modular LNG, which brings costs down quite a bit. The operating expenses are a little higher, but it can be, you know, the cost of the modules, they can be installed much more quickly.

They're more appropriate for Alaska given the, you know, construction window. And I know that's one of the things which has led perhaps less inflation in, in those numbers that you just quoted than you, you might otherwise have thought, because they have moved to different types of concept. Um, it would be very typical at this stage, as, as the capital costs are coming in, for the project to reevaluate, to re-examine, to, to really think outside the box in terms of how can you achieve what you want to achieve, but maybe in a different way to, to really bring that cost down. And I imagine that's what they're busy doing.

Representative Galvin. Thank you. I appreciate it if you would continue as you're going through this, giving us that context, that bit of, well, it could be $11 billion more, and if so, this graph would look like this. Something so that we understand that when we see these sorts of things, sometimes we take them straight up for what we are looking at and we don't appreciate that the most major, let's say, assumption made is based on that price. And if that price changes, this, I believe, changes substantially.

So I think it is important that I understand that and that the public understands that so that we make good decisions. And I love your hearing about— your giving us ideas of how we might then build in different triggers so that it still may be a workable and viable project. Thank you, Representative. Thank you, Representative Galvin. And perhaps through the chair, I will offer up one more comment, especially because I have been involved in the project for such a long time.

And, you know, it is Occasionally, it's, you know, you'll see a press article or something which will basically, you know, claim that the project is uneconomic, it'll never happen.

Putting my professional hat on, what is clear to me is that the project can be economic, and particularly when you compare to those Gulf Coast economics and Canada.

If you look at these variables, as I say, you know, property tax, gas price, federal support, and so forth, you can create a set of assumptions that, you know, create a very strong economic proposition. But equally, if you apply huge inflation or if you change this or that, then yeah, of course the project looks uneconomic. But it's, you know, it's a useful opportunity to perhaps counter that theory that the project is basically uneconomic, because I think the next few slides perhaps help to put that into context. Okay. And next up I've got Representative Schraggi and then Representative Stout.

Representative Schraggi. Yeah, thank you, Coacher Foster. If we could go back to slide 11.

Thank you. I just want to make sure I have an understanding of this, and hopefully I do have somewhat of an understanding, and you can verify that for me. This slide is really showing that we largely have 3— there's many, many variables, but we're boiling this down to really, I think, 3, or maybe you could say 4 variables on this slide. The price that you're expected to be able to sell your gas for, the cost of your project, that's the base CAPEX, The cost of the supply gas, that's the $1, $1.50, $2 across the top. And I would argue the fourth variable is kind of all the behind-the-scenes structure of the legislation, the tax scheme that you have.

And I think this partly explains why you see so much criticism in the public of Glenfarm and other companies, that we want more information. Because if we could eliminate some of these variables and have a known, it would really help us in figuring out where this might be going. But we don't have that right now. What this is ultimately showing is that under our current tax structure, there is a very small window of breakeven profitability for a developer. And that is with a base CapEx, so the known old cost of the project, or potentially up to a 20% increase.

And then within that range from $1, $1.50, $2 in-state gas supply. Under the proposed legislation, you could potentially tolerate a slightly larger project cost, up to a 40% cost escalation. I think that's the $65 million approximately— excuse me, $65 billion that we've heard floated around is what we think the new project cost might be. But if it's any more than that, then we're likely no longer profitable. They no longer break even.

The project is uneconomic. Alternatively, at that 40% cost, we stay at that 40% cost increase on the project cost, you could tolerate up to $1.50 in in-state gas supply. And that's where— this is just demonstrating that as you tweak those variables, it changes your break-even for the project. And if we would like to be able to have this project go forward at a 60% cost escalation or at a higher in-state gas supply price, we would need to further tweak our project economics, our tax scheme in Alaska by lowering the AVT or some other intervention. Is that all that accurate?

Does this graph essentially demonstrate how we might be able to make this project go forward even if the project costs are higher than what is currently documented and out in the public realm? Is that correct? Thank you, Representative Schrunk, through the Chair. I would say your explanation there is broadly correct. And if it turns out that the capital cost of the project is a lot higher than it was thought it would be, the ways to combat that would be to secure a lower cost of gas into the project.

And obviously that's, that's something that Glenfarm, I'm sure, are busy discussing with the upstream producers. The other lever would be potentially federal. Measures. I mentioned the federal loan guarantees, that there are other things the federal government could do to counter that higher price. And then the third one is, as you say, it's state fiscal policy that could be used.

Thank you. Okay, next up I've got Representative Stapp and then Bynum. Representative Stapp. I think Co-Chair Foster Mr. Fulford, I was just going to— I mean, Representative Schragg basically said what I was going to say, but I'll just kind of summarize that. Basically, the project overall under existing tax structure has challenging economics, and the point of the bill introduced by the executive is to give us the ability to have more flexibility in having a project as opposed to not having a project, right?

So I— there's been a lot of comments on cost and projections and producer price and stuff like that. But I think blowing it down to the fundamental premise is kind of important, that hey, there's a narrow window here, and having a volumetric structure is better than imposing a property structure, because property structure, when you have a capex overrun, is just stacking a cost-based tax upon a cost-based overrun. That's probably not what we want to do if we want to have a project. So I guess you can make a comment on that. If not, I have nothing more to say.

Thanks. Thank you, Representative Stapp. And through the chair, maybe one additional comment. If you look at what typically happens with LNG projects, they get built based on performance guarantees in the EPC contracts. They usually perform a little better.

Um, so you've got a little bit of kind of additional revenue from that. And certainly in Alaska, the temperature environment is such that the, the LNG plant should work very efficiently. Um, after 2 or 3 years, typically, um, they'll look at the project operationally, look at what's working well, what isn't, and there'll be what's called a debottlenecking. And it involves some degree of extra capital, but on a proportionally much less, you know, per additional ton of LNG. So, so right there you've got another little enhancement to economics.

Um, then particularly for Alaska, where the gas supply— that there is no question about the gas supply, that there will be sufficient gas for decades to come. And, and then if you look across to Canada, you know, in, in Arctic Canada, there's another multi-trillion cubic feet resource there. So, um, you know, so ultimately expansion would be the next thing for AK LNG, and, and at that point Okay, you've probably got to put more compression in, maybe reinforce the pipeline, but ultimately, proportionally to the capital, you're not doubling the capital to put— to double the capacity. So one of the advantages of the volumetric tax is that if you double the— or if you increase the capacity of the LNG project, you're also multiplying the AVT. Whereas you wouldn't be multiplying the property tax.

So again, as you think about the future and the potential for expansion, the volumetric tax has perhaps some benefits.

Okay, next up I've got Representative Bynum. Thank you, Co-Chair Foster, through the chair. You know, for me, what I'm seeing here is that we could talk a lot about corporate income tax rates, whether there's S-corp taxes in place. Those things all play a role when there's a profitable project. But the volatility that we have here, the uncertainty that we have here is the property tax component, having this liability against a project when it's not flowing gas.

So hence why we've been talking about the alternative tax structure. But we've also heard a lot about the capital costs of the project potentially being more. Can, can you say whether or not that would be unique to us? Because when I look at this, looking at large mega-type projects, that if we're seeing uncertainty in price, it has to do with a potentiality of unknowns through our permitting process. It could be labor market or commodity pricing.

So two parts of those things. One of those we know, we know what our regulatory framework looks like. Like with permitting. We wouldn't be here talking today if we didn't. But the other component of that has to do with labor market and commodity pricing.

That impacts all the other projects that are out there, does it not? Yes, thank you, Representative Bynum. And certainly as you get the project to FID, once you're through FID and you've started construction, you know, all those risks that you've mentioned start to come to play. And so one of the, one of the major features of risk apportionment will be between the project developers and the EPC contractor, for example. And given some of the cost escalation that we've seen in the LNG sector, especially Australia, those EPC contracts tend to be much more robustly negotiated than in the past.

So typically some degree of risk will be taken on by the construction company doing the work.

But then, you know, commodity risk is obviously something that will continue to affect the project for years to come. And all you can really say about that is that LNG is about the longest, the longest-term sort of fossil fuel hydrocarbon business than you can imagine. The, the returns on LNG are multi-decade. They're not— and, and if you encounter 2 or 3 years of very soft prices, for example, as we've seen recently, um, you have to have the, the balance sheet to sustain that such that when, when prices do recover, you can get your money back. And I think it's something I often say to, um, you know, less developed nations, so to speak, um, you know, who are starting on this LNG journey, that they need to think of, of a generational value, sort of children, grandchildren.

That's That's where these projects are beneficial. And there's an awful lot of risk that has to be taken in the meantime. Thank you. Okay. And Representative Gelman.

Thank you, Co-Chair Foster. Through the Chair, I'm going to back up just a minute here to thinking about how we get to the 70% of the funds that are going to make this project on a green light. And I think about— I assume that there's been some— a lot of discussion around getting to the Energy Dominance Fund, the federal loans that are available. As I understand it, we haven't quite gotten there yet. But if that's incorrect, please correct that.

I'm curious to know if we are on track to get those loans, number one. Number two, what is needed? Is that my— my assumption was that we would need to know what the cost of a project would be in order to get that. But if there's anything else that we need to do also as a, as a legislature to make that happen so that the loan looks very— or so that we— the project looks like something that the federal government would want to invest in? Thank you, Representative Galvin.

That's a great question. Through the chair, I think— well, first of all, I have no inside knowledge about the Energy Dovenance Fund and where the project might be in securing money from that. Obviously, there are a number of supportive messages coming out of federal government, have been for over a year now on the project.

And, you know, arguably the progress that's been made so far in terms of letters of intent and the level of interest being shown particularly by Asian gas consumers, you know, is as a result of positive policy from the federal government.

But I think in terms of the state government and the legislature, the one thing that you could probably do which would help that dialogue go forward is really what we're here discussing today, which is to put in place a more appropriate framework around property tax or whatever replaces it. Because undoubtedly what goes on in the legislature, you know, obviously it has a lot of interest from within the state, but, you know, some of these buyers who are looking at the project are also looking at what the legislature is doing. And to be able to move to a more positive framework, I might say even if it's not the final picture, but to remove the— not exactly a specter, but, you know, to remove the sort of property tax issue after all this time, I think would be seen very positively by certainly buyers, lenders, and no doubt by federal government.

One, just a follow-up if I may. In the beginning of that very long-winded question, I had asked if there would be a need for the price of the project to be in that application for the federal loan. Thank you, Representative. Through the chair, I think it's unlikely that the federal government would commit unequivocally to a project without that kind of level of understanding. Now, whether they need it on day one or whether they need it at some other point remains to be seen, I think.

Thank you. Okay. Please proceed.

Thank you. So Moving on from the last slide, this slide kind of looks back at that 10-year period that I was talking about. And so if you ask your— you know, ask yourself the question, well, how much of the last 10 years would this project have been an economically attractive proposition? What would that look like? So the, the orange line on this graph is the monthly LNG price into Japan, and, um, you can see there that there was a relatively soft pricing environment up until about 2018.

We had the dip which was really created by COVID and the drop in industrial demand globally, and then of course you had the Ukraine crisis where Russian gas imports into Europe were significantly curtailed, and, and it placed a very big burden on, on LNG. On the very right-hand side of this graph is, roughly speaking, what forward prices look like today with the removal of such a lot of capacity in Qatar. Um, obviously it remains to be seen what the forward price actually is, But you can see there that at least for the next 2 to 3 years, there's likely to be a very significantly higher LNG price than before. So, so the, the turquoise square on, on this graph represents really where the project would have been profitable with, with the existing property tax.

And the dotted line— and these are relatively approximate, I think would get your ruler out on the graph— but really what this illustrates is that more of that 10-year period would have been profitable had, had the 6-cent AVT been brought in. So obviously it's of limited use looking backwards, so the next two slides really talk about what things look like moving forwards. And with your permission, Chair, I'll move on.

So for, for LNG supplied into Asia, the, the pricing that typically applies to that would relate to an oil index. Um, the, the LNG contracting world is kind of in flux at the moment. So with the predominance of U.S. Gulf Coast supply, we're seeing Henry Hub and other factors being introduced. But for the purposes of this, I think it's useful to think about oil indexation. So under that arrangement, um, the gas would be priced using a percentage and then using the prevailing Brent price.

On a kind of thermal equivalent, in terms of the amount of energy in a barrel of oil, the sort of technical thermal conversion is about— I think it's just over 15%. But typically with delivery and other sort of inefficiencies, the, um, the, the LNG price you can see on that graph would vary between about $14, $14.50 maybe as a sort of top end, and maybe around $10, $10.50 at the bottom depending on market conditions. So I look back over the last year and, um, obviously not many of these projects are made contracts are made public, but the ones that do, there's 4, 2 in Japan, 1 in India, 1 in Vietnam, and they average out at about 12.4% Brent. That's, that's been the sort of prevailing oil price this last year or so. Um, so what I've shown on this graph is, um, what the gas price would be under different percentages along the left-hand side and under different oil prices along the top.

So the main takeaway from this is that— and, and really the, the two color shades on the chart represent, um, the price without property tax and the 6-cent AVT— sorry, the price with property tax, which is the blue— sorry, the yellow, and the price with the 6-cent tax, which would be the blue.

A lot of numbers on the chart, but what you can conclude from that is that if you took 12.5% as the going rate for LNG, With the 6-cent tax, AVT, Alaska would be profitable somewhere around the sort of $65, $70 a barrel. So really any price greater than $65 or $70 a barrel, Alaska would be in the money. Equally with the property tax, you can see that that shifts slightly to the left— sorry, to the right. And, and you're really in more of a sort of 70-75. So that gives you a sense of, um, the competitiveness of the gas globally and the difference between, um, where things stand today and where they could stand.

And again, this is an illustration really of how it all boils down to pennies and these margins. Representative Stout. Thank you, Co-Chair Foster. Through the chair to Mr. Fulford. So hypothetically, what if we were to do $0.05 on the AVT?

I mean, what type of impact does that have on this competitive matrix? Through the chair. Thank you, Representative Stout.

$0.05 Compared to regular property taxes or just Just compared to the 6 cents, I mean, I don't— looks marginal on my end, but I'm just curious if you have a comment. I think, Representative Stapp, the difference between 5, 6, even 10 cents, it's all in the rounding, really. Thank you. Representative Schraggi. Yeah, thank you, Co-Chair Foster.

Just a quick technical question. I see the asterisk here on the bottom left based on DOR heat map presented to Senate Resources using $1 upstream price and base CapEx. Can you— everywhere I've seen it previously, it's been discussed at $1.50. Can you just tell me why $1 was selected for this? Yes, thank you, Representative Schraggart.

That's an error, actually, because this— I originally did this slide for $1, but given that $1.50 seemed to be coming out as the sort of general understanding. I changed the numbers on the slide, but I obviously forgot to amend that notice. So thank you for that. I need to correct it. And follow-up.

Follow-up. But it does use base CapEx. Is that accurate? Yep. That's affirmative.

So base CapEx and $1.50. Thank you. Representative Galvin.

Well, I guess the One thing I want to note is that you had said this is aligning with some percentage of $65 to $70 per barrel, and if we're at— in that sweet spot or more, Alaska is looking to— this is very much a green light project. Is that correct? Uh, thank you, Representative Galland. And maybe to put that in in more simple terms.

If, if, uh, if an Asian LNG buyer, um, has, has the choice between, you know, buying gas at 12.5% oil versus, um, an arrangement which is more related to Alaska breakeven If they believe— assuming that 12.5% is the going rate, and that varies, then in a $65 to $70 oil environment or higher, they would choose Alaska. And then for the existing property tax, it would have to be a little bit more. Follow-up? Follow-up?

I'm just recollecting that DOR not too long ago gave us long-term projections of the price of oil, and they put that at anywhere between $55 and $60, maybe $65 at best, long-term. So would that— does that extrapolate out for— for this project, or should we be thinking more like that's a world market number so others would have the same? How does— how would I think about that? Thank you, Representative Gallin. I'm not sure where the DOR projection came from, but it sounds consistent with many other forecasts.

Um, and I think maybe, um, another thing to bear in mind is, um, that there are some nuances around how LNG buyers sort of procure their LNG as well, one of which is security of supply. Um, they conceivably, they might look at some different sort of indexation if they feel they, they have too much oil exposure and they want a different type of, of index. So, so I think, um, you know, buying LNG on an oil index is a good starting assumption to look at the economics of the Alaska LNG project. But between, you know, $5 on gas you know, different types of indexation. You know, the diagram here is things helpful directionally to see where things stand, but there's maybe more to it.

Okay, thank you. Okay, please continue.

Thank you. So the, the other way of looking forward in terms of LNG price is how competitive are you versus the US Gulf Coast? As I mentioned in my earlier remarks, in some ways the US Gulf Coast is a little bit like an LNG tap that if there's demand, then you can turn the tap and you can build liquefaction.

For now, that seems to have been working okay for them. The demands on the Lower 48 gas infrastructure, high as they are, don't yet seem to have had much of a price, you know, impact on Henry Hub, which is the U.S. wholesale price.

I think there are a lot of forecasts out there which suggest that that may change, particularly with all the data centers and so forth being built. But for now, I looked up the forward 2030 price for Henry Hub and it comes to $3.55. That's, that's what you can buy gas for today in, in that time frame. The, the way the U.S. Contracts typically work is that they'll add a surcharge, usually 15%, sometimes more. Then there'll be a liquefaction tolling fee which relates to the capital cost of liquefaction.

And then of course you've got the shipping charges which, as I mentioned, are under pressure somewhat. But if you put all those numbers in, you get a roughly a $9.28 break-even for U.S. Gulf Coast gas delivered to Asia. And, you know, if you're an Asian LNG buyer, you're probably looking at that as a kind of a— not exactly a ceiling, but certainly a guide as to where you think LNG value should rest. So if you have another project, whether it's Mozambique or Australia or anywhere else, a buyer will always be looking at that comparison compared to U.S. Gulf Coast, and it'll be just the same with Alaska. So the good news is that if you take the— that U.S. Gulf Coast number and you apply it to the previous chart that I put up, You can see that even under the existing property tax mechanism, that there is a little bit of headroom there.

But again, this assumes base case capital, which I think is probably a very big assumption at this stage.

I think many of the technical assessments would suggest that Henry Hub prices by 2030 will be a lot more than $3.55. And again, that's one of the things that will attract, um, an LNG buyer to Alaska, in the sense that they've got that kind of, um, forward-looking view into multiple TCFs of gas producible at a very low cost. And, and that will be a feature which an LNG buyer will be quite attracted to.

So with that, I'll move on, and I wanted to spend a few minutes on the Phase 1 gas line because obviously from a, from an in-state supply perspective, this is a key consideration and one which has had quite a bit of discussion. So I know certainly in version T in the committee substitute, I'm not sure that spoke to gas line tariffs a lot, but nevertheless I think for the committee it's probably helpful to have that background. And so what I've illustrated on here is the likely gas tariff for a South Central— well, certainly for a South Central utility, I should say. So this would be supplied to NSTAR, for example, under different capital cost assumptions for the pipeline and under different flow rates. I think the, the first thing that you take away from this is that if you take just South Central demand today, which I think is less than 300 million standard cubic feet per day, and you apply it to a 42-inch pipeline, what you can see here is that the economics are quite skewed and that it's a disproportionate level of tariff which would have to be paid.

Once you get it up to about 500 million standard cubic feet per day, which might include, for example, Fairbanks or various power stations, then you're starting to kind of edge down to the, the sort of tariff that's certainly been talked about. Certainly $12 is a number that's been put out there, I think. Um, but there again, obviously it depends on the, the gas price being paid by the midstream. Um, and the other thing I should add is that these tariff numbers don't include any costs for gas processing, um, nor do they include any property tax or AVT. So they don't include either of those features.

But I think for illustrative purposes, it's helpful to kind of understand this exposure to flow rate and the importance of building up in-state demand in, in a scenario where the project is flowing only for in-state customers.

So on the next slide, Representative Galvin.

Thank you. I think it would be responsible of me to dig in a little bit on the 500 MMCFD there where you have you know, some sort of an assumption that we're going to have that much flowing through. I assume— I guess if you could talk to us about how— we know that right now Alaska is using less than half of that, and there will be also some coming from Cook Inlet, I assume, at least initially, maybe later as well. Just some comments, if you could make them, around that flow or expected flow of 500, and what would that do to the price or to the project if that's not at that flow or if it's not being consumed or purchased. Thank you, Representative Galvin.

Through the chair, one of the thinking internationally again, different sort of gasification projects, uh, we're, we're in this kind of chicken and egg situation where if, if the gas is low cost enough, people will use it in, in preference to other things. And so, so creating, creating demand is, is often a case of determining a price for that gas during the buildup phase, which may not reflect the economic value of it. So, um, so in order to get to the 500 million standard cubic feet per day or more, it's— I think this graph sort of shows you that you might have to somehow introduce a subsidy to allow demand to build up You also made the good point that cooking like gas won't disappear overnight either. So there'll inevitably be a ramping up period. But it's very much a case of state policy and how that is addressed.

Follow up? Follow up? I haven't heard discussion around introducing a subsidy, but I haven't been to a lot of these meetings yet, and so I wondered if you could share with us what other nations are doing or have done, or projects within this nation, and if there's been any discussion on this particular project about a subsidy and who pays for that. Thank you, Representative Galvin.

Textbook example might be Egypt. I know it probably doesn't seem very comparable to Alaska. But the, the problem in Egypt was very high demand for LPG with, you know, which, which attracted a very high subsidy compared to the availability of very low-cost gas. So they, they introduced a very ambitious gasification project of I think 7 major cities. And so the subsidy on the gas, effectively on the gas connections, was made up through avoided cost through other government expenditure.

So for Fairbanks, et cetera, you know, you could see some degree of saving from other forms of subsidized energy. But that isn't enough to kind of move the needle completely. Follow-up? I do have a follow-up, but it's regarding— I'm going to go back to another topic, if I may, down to slide 13-ish. Maybe it's around there.

There was a discussion from Representative Stepp, and he asked you specifically around what's the difference between— what if we dropped it to 5 cents? And at that point, you had made a statement that if we— if we changed it between 5 and 10 cents, there is not a big difference there in terms of— that would not red light the project. And I wondered if you wanted to give us a bit more context around that, because to me that feels important between 5 and 10 cents. And these are the decisions that we are talking about, the biggest, I think, decisions that we're trying to make. And so, of course, for me, looking after the state revenue plus lower gases, I'm trying to balance how do we make sure that we're doing our job.

And so if you could talk about that, no difference between $0.05 and $0.10 volume AVT, really red lighting the project. Thank you, Representative Galvin. And through the chair, Maybe just to clarify and add some color to that response. Obviously, every penny that you add, starting with a sort of a zero base, will create cost. And as things develop and the capital cost estimates come in, it will zero in on this sort of— as I was saying, you know, pennies, for MMBTU that'll make the difference.

But I suppose my, my earlier comment was more in the context of an AVT set at 5, 6, 7, 10 cents versus existing property tax. The, the difference between those two scenarios is very material indeed. So, so it, it brings the question away from, you know, a kind of substantial improvement in project economics versus where you're at in terms of this penny, two pennies, whatever it is to get the project economic. Thank you. Okay.

Representative Step, then Justice. Thank you, Chair Foster, through the Chair to Mr. Fulford.

$12 MMBTU supply cap. I have never— I don't think that's in a version of any of our bills. I don't know if that's an other body thing, but I'm— I don't know why we would do that. So last Thursday we discussed basically the competitor, which would be LNG imports, and that's around $17, $18. So I'm curious where the $12 figure comes from and why it's included in the slide deck.

Through the chair. Yes. And thank you, Representative Stark. You're quite right. It came from the other body.

And I sort of included it here as more of an illustrative point. I know it has not been in any of the House recommendations. Thank you. Okay. Thanks.

Representative Josephson.

Thank you, Chair Foster. Mr. Fulford, in one model of bills on the property tax reform for the gas line project, there was a provision that would require, or at least allow, up to $90 million direct impact aid on top of some other tranches, which were $30 or $40 million times X number of years. First of all, that strikes me as a concession that the smaller community impact aid isn't enough, sort of definitionally, or this other proposal on top of it wouldn't have been divined. But is there any other major project where— because you talked about subsidies in a different context, of course— where the, the sovereign has to come in and backfill, um, this gap where community aid is apparently needed. Um, thank you, Representative Josephson, and, um, I'm certainly unaware of any scenarios where central government, whether it be state or provincial, are effectively backfilling compensation.

So the only one which maybe comes close would be maybe the Australian one I had on my example sheet there. But it's an interesting point because, of course, whilst all the property tax mechanisms that have been put before you are very clear about the division of revenues between, you know, the boroughs, municipalities, unorganized, et cetera. For the project itself, they're kind of agnostic to where the money goes. They only really are concerned about how much it is, for the most part. I know Glen Farnham have done a lot of work with stakeholders, with local communities and so forth.

So— but financially speaking, it makes no difference to them where the money goes. You know, I've made the point several times today that the real value in a project like this is not— it's not a few years' time. It's 10, 20, 30, 40 years from now. Again, you look at Brunei, that project is spinning off billions of dollars of cash. It's very— it's been transformative in terms of the nation.

And that's really what you would expect to see here. But this first few years, it's difficult to look after the needs of the communities where clearly there's significant impact versus the kind of long-term gain of the project. And how that's addressed is a key matter of state policy, which I'm not qualified to address. Follow-up? Somewhat unrelated to the— my first question, I watched the hearing presented by Senators Giesel and Wielechowski a few days ago in Senate Finance, and a number stuck with me of $450 million if there were a CIT, corporate income tax, impacting S corps.

I think that was the number. I suspect it was rooted in something I have confidence in, that would impact, of course, Glenfarm itself and Hillcorp. But is that— because we talk about sustainability and unpredictability, is that something that Wall Street would say, geez, you know, this could be with 21 and 11 and a governor, this could be changed in a week? Theoretically. But that— is that a— as Representative Galvin said, is that a red light feature?

Or is that— because it strikes me that that's almost half of the— well, it's about half of the reduction sought in property taxes. So it's an enormous issue, but maybe not one one that would drag potential investment? Thank you, Representative Josephson. I think my comments on that— Gaffney Klein have provided testimony for a number of years on oil and gas taxation. And one of the things we typically point out is that material changes to oil and gas or indeed any other taxation after investments have been made, that tends to send a somewhat negative signal to investors.

And, you know, most countries do it, frankly, within limits, but it's still not popular with the investment community or lenders.

However, you know, setting a tax now which relates to a project that hasn't yet gone to FID, that's a completely different matter. And I think there would be maybe a marginal financial consequence of that for the investors, but ultimately it comes back to what I was saying about fiscal stability. Everyone wants to know where they stand. And they further want to know that it won't change. So my answer is in those two different categories.

Historical changes is one thing, future changes is another.

Okay, thank you. Okay, let's see, Representative Bynum, did you have your— Thank you, co-chair. Yes, I did. I was just hoping— I didn't want to get too much into the weeds here. Obviously, this is price cap versus tariff for this return.

I was hoping you could talk just briefly about the capex budget that's actually listed on these slides. We go from 10 to 12 to 14 to demonstrate how we can get, you know, more throughput, obviously means lower cost and gets us where we want to be. But I was hoping you could talk about the selection of the numbers that we're Yeah, thank you, Representative Bynum. And so these are numbers that I took from various historical publications over the years.

One of the considerations with the pipeline is that if it, if it really is just for in-state demand, it doesn't need any compression. So the flow would just continue all the way from the slope down to Fairbanks, et cetera.

So the capital numbers on here might be a little lower than what you've seen before, but that was the basis of it.

And really, you know, $14 billion seemed to be a kind of a reasonable upper limit to the to the pipeline. Having said that, I think I've heard Glenfarm testify that they do have Class 2 estimates now for the pipeline section of the project. So that would be a good useful data point to put into this. Thank you. Okay.

And next up I've got Representative Galvin, then Hannon.

Thank you, Co-Chair Foster. Through the Chair, we heard from Co-chair Josephson around what sort of revenue measures may or may not be difficult to put into this mix or this recipe, if you will. And I wanted to ask you, because I'm thinking about other countries and other projects wherein they have other revenue measures in place already. Right? I'm assuming that Norway and other countries have broad-based revenue measures such as either sales tax or income tax or things like that.

And I guess it would be maybe helpful for us to appreciate that because if they do have income tax, for example, or sales, likely a project like this would bring in other revenue in addition to, let's say, corporate tax or even changing the S corp. I just wanted to see if you had any comment about that because it must change the impact of either country or state if they have other things in place. Thank you, Representative Galvin. And through the chair, It's, it's worth noting that, um, I think in my experience, you know, every LNG project is unique, you know, every country's taxation mechanism is unique. So really, as you look at the open book economic model and so forth, having all these moving parts incorporated is important.

And as we, you know, today we've looked at comparisons with Texas, Louisiana, Canada, but it is worth just remembering that partly because of some of those factors you've mentioned, direct comparisons with other jurisdictions can be tricky and a little bit misleading. So you kind of have to make sure that you've got the starting point correctly defined before you start looking at different taxes. Maybe I'll follow that up with something a little bit more direct. Do— are there other entities that don't have any broad-based tax measure already in place? In other words, Alaska is pretty unique in the United States to not have those things, and I believe other countries also would be unique if they had none of those other things in place.

We don't. We have property tax and we have pretty high corporate taxes. And so what I'm at— what I'm getting at is that doesn't that put Alaska in a unique— and everyone's unique, but I mean, a little bit unique in terms of when it comes to revenue.

Thank you, Representative Galvin. And I, I think those are valid points, um, and, um, as I say, each project is unique. And, um, the other point I'd make, which perhaps helps— not really a direct answer to the question, but in every LNG project I've worked on has some kind of tax concession that, that considerable work is put into negotiating the right fiscal framework with the host government, and, and often what comes out is quite a complex agreement. If I may, thank you. I'm just going to drill on this just for another minute because I think it's relevant to Alaskans.

We know, for example, if we were to put into play a high earner tax and an S corp, which would also incorporate that, it would be hundreds of millions of dollars, high hundreds of millions of dollars. And we know what we've heard about this project is there may be anywhere between 10,000 and 12,000 employees earning high wages. And so I just want to make mention of this because I think it's important, especially if you include S but also other wage earners, because when we think about how do we replace whatever we're giving up in order to make this work, you know, we need to think about that so that we can keep our public services solid and strong. And I would guess, but I haven't heard from Glenfarm directly, that they wouldn't be surprised that there might be some taxes involved. You know, I haven't heard them say, "Hey, we don't want to pay any taxes." And a lot of employers— employees are already paying taxes back where they are in their home state.

They would not be double taxed if they worked in Alaska, as far as I know. They would only be paying whatever taxes that the higher tax amount is, and then they would be able to deduct it from their home state. So I just want to make sure that we include that because it's important. Information around how are we going to deal with, you know, are there multiple ways, I should say, of dealing with that. And that's not to say let's go and write a tax thing for individuals today, but it is for us to understand how are we going to deal with, if we are going to give up so much in property tax, what will we do for our state services to keep them running.

I think all of this is important, so I appreciate your comments about that.

Next up I have Representative Hannan and then Schrag. Thank you, Co-Chair Foster. Mr. Fulford, you were talking about if future money is hard to predict because if taxes change, etc. And one of the snippets I have heard out there, and I don't know whether you can confirm, and I will ask AGDC directly, but that there is a contract that if the project does not go forward, that AGDC owes some money. So I'm not only— if tax structures change, but if other economics aren't met, if the project does not go forward, is the state, to your knowledge, via AGDC, under an obligation to pay Glenfarm something?

Thank you, Representative Hannan. None of the documentation that I've seen, which I think will be similar to what you've seen, I'm not aware of anything like that. But in a project of this complexity involving a major partnership between AGDC and another entity, I imagine there are a whole series of measures dealing with what may or may not happen in the future.

Through the chair, is it possible that even if we gave all the concessions asked for, I believe Rep. Stapp quoted it, give it to him for free, I think was his saying last week. So charge nothing. That other economics would create a situation, global economics, price of gas, Texas finding a way through the Panama Canal for free by annexing it, I presume, and the, the project doesn't go forward, that we could still be under an obligation to pay Glen Farms for some of the time that they've spent. That's a practicality that could exist in a contract that you and I haven't seen.

Thank you, Representative Hannon. It's probably helpful to think back to 2014. And TransCanada, who were one of the original partners, and I think they were paid a, um, multimillion-dollar fee for, for the time that they'd spent on the project on the basis that they were no longer an equity partner. That's just an example. Thank you.

Okay, next up I've got Representative Shraggi. Yeah, thank you, Co-Chair Foster. Uh, to bring us back to the the slide quickly. I'm looking at the slide and I— basically what it's telling me is that at lower volumes, you're paying a higher price for the gas as a consumer. And at the 300 level, that's the in-state only supply.

It's a very high cost of gas. In fact, I think what we've heard is that for LNG imports, it'd be about $17 for in-state import— for import into the state. And so if you drew a line across this at 17, you'd see that the only point at which delivered gas is below LNG import price is at the $500 level or greater. And, and frankly, even at the $500, you have to be at a dollar in-state supply gas or at $1.50 with a very low and CapEx expenditure on the pipeline. Can you remind me, what is kind of the— is 500 the best case scenario, or are there scenarios in which we're putting more gas through the pipeline than the 500 level?

What are the bands of possibilities here? Can you remind me? I just don't remember. Thank you. Thank you, Representative Schroeder.

And I think at the level of detail that I used to produce these slides, I did some reading around other people's testimony and some of the numbers that are being put out there. But I wouldn't want to comment in too much detail about the potential for high demand. Obviously, any industrial facility or any power generation immediately starts to rank, you know, to add on to that. I mean, just, you know, a power station on its own could be $100 million a day, certainly a larger one. Follow-up.

Follow-up. So to restate, I think what you've kind of just told me is that without some grand new vision for how we might use the gas, just looking at export that kind of upper bound would likely be the 500 level. Is that accurate? I think 500— through the chair, I think the 500 level would be probably a high-end forecast for conceivable in-state demand without any major changes.

One more follow-up to clarify. So 500 would be the upper bound, the upper limit for for just in-state use. Is that accurate? What volumes are we contemplating for export? For export, through the chair, Representative Shrager, it's 3 BCF a day.

Okay. So it's 10 times the amount. Very good. And then last follow-up is more of just a comment, which means that if you get beyond the in-state supply to an export, you're talking much higher volumes and therefore a lower cost of delivered gas to Alaskans. But under the scenarios where we're looking at just in-state, your kind of high end would be $500, maybe average medium or low end would be the $300.

But in pretty much all of these scenarios, it's very hard to have a phase one just in-state supply gas line that delivers cost to Alaskans at a lower price than LNG import. Is that accurate. I think— thank you, Representative Schroeder. I think through the chair that would be accurate. Um, and I think, um, it's useful to consider what this pipeline represents for South Central consumers, and it basically represents an option.

So assuming that the full cost of the pipeline goes— feeds through to consumer prices Effectively, what we have is a scenario where, depending on how long the period is where it's simply in-state demand, that, you know, a higher price will be being paid for the gas, but followed by a substantially lower price than what they're paying today. And in fact, two slides on, I have an illustration of exactly that. Might be worth just Thank you. So if we look at essentially that same graph, um, we're looking at, uh, 3.3 BCF a day instead of 300 to 500. Looking at the same CapEx numbers, not included in those CapEx numbers is an extra $2 billion for compression.

But you see there, and again, so this, this includes no cost for removing CO2, and it includes no property tax or indeed the 6-cent ABT. But what you can see here is that compared to today's prices in the Cook Inlet, the cost to a local utility would be, well, substantially less. It— and from that you would create industrial demand, data centers, and so forth, which ultimately would feed through the demand, which is hard to do at $16, $18, $20 an MMPTU.

Questioner, representative Step. Yeah, thank you. Through the chair to Mr. Fulford, I guess the first thing I kind of want to address is As I was reflecting on kind of Rep. Hannan's comments regarding the payback, and I thought that I had asked AGDC when they were here, and they assured us that all the financial liability is actually on Glenfarn, so we wouldn't have had the TransCanada example, right? So my understanding on the project is, in the event that it, say, for whatever reason doesn't happen, the state does not have to pay the developer in this case anything. But that's, like I said, I'm fairly certain I had that conversation.

And I don't know if anyone else in the committee is any different because when Rep. Pan had made those comments, I was kind of like, oh, I thought they said they didn't. But I'm just unsure. I don't know if you have any comments on that, Mr. Fulford.

Thank you, Representative Stapp. And I would expect that that if there were any kind of material financial liability that would arise from that, that it would have been disclosed to the Legislature. And the fact that it hasn't, and it sounds as though AGDC's testimony backed that up, seems to suggest that there isn't one. Okay. Thanks.

Okay. Okay. Representative Josephson.

On this topic, because so I spent a month, the month of October, I think 2015. Every legislator was there attending, there being the Capitol committee hearings in every room. It was sort of fait accompli that we would spend, I think it was $250 million to buy out TransCanada's Mm-hmm. Interest. I don't know fully what we got for that.

I know that's now a Glenfarm product. Um, and that I, I, I guess what we get is if this plan happens, we get our 25%, I'm told, administrative costs, which constitute $600 million per year. I mean, This is sort of what I'm told. But as to any liability through AGDC, if we— if you know, and we can ask them directly and we will, would they say, oh, you need an NDA to know whether or not there's liability, or is that something to your knowledge they would just disclose? I mean, it strikes me that that's critically important and not something to hide.

Do you know what the terms of the agreement are with Glenfarn in the event of failure? Thank you, Representative Josephson. I have no knowledge at all of that.

So I'm unable to comment, really. Okay. Thank you. Okay. Please continue.

Thank you. So in this last section of the slides, I wanted to maybe go back again to SB 138 and to talk about the differences between what applied then and what applies now.

And, you know, a lot of the dialogue that we've had over the last several weeks has been how to make decisions without some of these major financial attributes that the project— that will determine the future of the project but are not yet in a position to be shared.

So obviously this is a feature that many governments encounter, and I would say it's particularly prevalent where a government has the same constitutional duties that you do, that, that there's a straightforward requirement for you to set taxes in a way which represents a fair cost and revenue to the citizens of Alaska. So where that very firm constitutional commitment exists. You tend to get a much greater degree of focus around, well, what are the costs? What do the economics look like? How much tax are we giving up?

And so, in a commercial world, you know, there are different ways in which you can go about developing that sufficient confidence to go go forward. So under SB 138, it was— it was a much more transparent environment for a number of reasons I'll go on to in a minute. But without that, there are a number of ways you can create some degree of communication without, you know, every number being— being made public.

One way is to create a kind of a multi-agency team of individuals who are tasked just with this kind of disclosure element and don't get involved in any of the other decision-making. Another is to create a kind of a small team with internal or external support. And of course, you know, the overriding feature of that is a confidentiality framework or non-disclosures that will ensure that there's only a certain number of people that are able to look at the data and not disclose it. So that's really the background to it. But, you know, part of this, of course, is what's happening right now.

So the, you know, the question to start with is, well, you know, if some degree of tax is placed on the project, Um, who will pay it? So I think we've established that the LNG market price is what it is, and you can't go to your LNG buyers and say, well, actually we've got this extra tax and we're going to tag it onto the price. So effectively, the, the allocation of that tax falls somewhere between the LNG investors, the midstream, Glenfarm, AGDC, and then of course the upstream gas producers. And one of the features of the dialogue which will be going on right now, I imagine, is this negotiation between the midstream and the upstream in terms of what that appropriate price should be. And so the extent to which you put a tax on the midstream, some of that tax could find its way into the upstream downstream or vice versa.

And one of the reasons I think for the lack of clarity and disclosure around fundamental project economics is simply that it's a feature of the negotiations going on which, you know, for Glenfarm would be unfortunate to be out in the public. So there's some degree of understanding, you know, why Glenfarm are reluctant to share too much of the project information. I think the key, though, is to find a mechanism that's acceptable to the legislature so that some degree of insight can be applied which can allow you to reach a decision.

Josephson.

The—. You talked about SB 138 being a more transparent environment. What I think the Senate Resources Committee found was that it wasn't transparent enough, and so they sought reforms along those lines. Um, do you have any comments about, about that? I mean, there was a feeling that I got that the 2013-14 environment was— the term I use is cheerleading— that we perhaps didn't think this could happen, or we trusted partners like Exxon and ConocoPhillips to have their own self-interest that we would ride along with.

And so this is a wholly different model, of course, but In retrospect, when we look back and have asked questions of our own attorneys about AGDC's transparency, we felt—at least the Senate Resources Committee felt—that those books needed to be opened up a bit more. What is your impression of that vis-à-vis other projects around the world? Thank you, Representative Josephson, through the chair.

You know, I think in some ways these LNG projects are iterative in nature. And, you know, one level of disclosure will enable one aspect of policy to be set. But as you get closer and closer towards FID, Typically, you get into the weeds, and that's where this sort of very extensive exchange of information is more helpful and appropriate. And maybe on SP38, the project never quite got to that point.

But even with this one, I imagine there's going to be several rounds of dialogue and disclosure before the project reaches FID.

I think, if I might, Mr. Chair, the thing that legislature has been wrestling with this calendar year in particular is the amount of— and last— the amount of delegation that was given to AGDC and where does the legislature intervene. And that's something that I think hasn't been resolved. Thank you.

Please continue. Okay. Thank you. So continuing the theme of disclosure and why the situation we have here is different to SB 138, one of the great advantages of the integrated framework under SB 138 is that equity in the project was set subject to the state taking its option.

The gas supply flowed all the way through to the LNG so that the gas suppliers took their own equity portion of the LNG on the other end. So really, you know, 3 key areas of the project were set from the start, the, the equity, the gas supply, and who is going to take the LNG. Now, obviously, with the current arrangement with Glenfarm, those same features don't translate across. So, for example, you know, we've seen this dialogue with the upstream providers in terms of under what terms the gas will be provided.

Glenfarm, I think, have spoken about talking to other equity investors in the project who may take a position in the future. And then, of course, we've got the negotiations with LNG off-takers. So I would say, particularly with respect to the equity in the project and for the gas supply, the same insight into the project that the legislature is seeking to obtain is information which makes those negotiations difficult if too much disclosure happens. Because certainly if you're an equity investor or if you're a gas supplier, these key fundamental aspects of the project are, you know, highly sensitive and ones which you wouldn't want to be out there. And I think that explains a lot of the reluctance.

Representative Stout. Yeah, thank you, uh, Co-Chair Foster, through the Chair to Mr. Fulford. I mean, the way— the way my understanding is pretty simple. I mean, the state has an option to become an equity investor, and if we were to option that option, they would basically be required to give us all the details that we would like, right? But up until then, it's effectively not our project because we're not putting our capital in as an investor.

Through the Chair. Uh, thank you, Representative Staab. That's absolutely right. And, you know, it's one of the reasons why in the past Japanese buyers typically would take a small equity interest in the LNG projects that they support, because it gives them a seat at the table and a full understanding of, you know, the supply issues, the economics, and so forth. And over the years, that that small 2% interest that used to be standard has now become aligned with the LNG take.

So if you're taking 10% of an LNG project's output, typically you take 10% equity, and it's to achieve that kind of alignment. Thanks. Please, can— Representative Galvin.

Thank you. Good morning, uh, Co-chair Foster. I'm curious if you have any thoughts on how, um, this conversation has morphed into a conversation about, um, property tax. We, um, all met with various entities, particularly with Glenfarn, uh, a year ago or so, and at that point in time it was raw Rah! This is on!

And gosh, we were all so excited, and now we're tripped up a little bit, if you will. Some folks have come to the dais and said, well, we've told you this all along. I have heard that from about other— I've heard about a need for property tax abatement because I've learned from, well, partly from your presentation and others, that that is a common ask of a state or a country. But it wasn't the ask from the entities that were initially presenting this, and I wondered if you had any comments about how that changed or why that changed, because now it seems to be this is sort of the bottom line in terms of red light and green light for the project.

Thank you, Representative Galvin. And through the chair, I think I would only refer back to the well-publicized activity that happened, you know, 12, 14 years ago with, you know, for example, that Municipal Advisory Gas Project Review Board. You know, there was a lot of dialogue at that time around a PILT. And I think it has been recognized from that period that property tax was something that had to be dealt with.

Yeah. Thank you. I respect that. I also wanted to share that we have had AGDC in front of us as a committee for me for the last 4 years, and they present where things are. And I just would like to point out that during those times, this wasn't the one topic that, you know, by the way, as you look ahead, this is the one for you to be keeping your eye on and thinking about.

And so I'm— we're definitely here at the table and ready to help find the solution, but I would like to make comment that even though 15 years ago, or what have you, you were in consideration, we weren't here then. And so here we are. Thank you.

Any further questions? Anything further, Mr. Fulford? Thank you, Chair Foster. I think I've covered this slide about the economic modeling. We've spoken about that.

So I think I'm at the end of my slides. Thank you for your attention. Okay, Representative Bynum. Thank you, Co-Chair Foster. I mean, to me, what we have in front of us is to deal with how we, how we treat the property tax here to make a project that we can get investment in.

And there's two components that I hear us debating back and forth. One component is in-state gas and What is that going to cost? And what is our responsibility to try to ensure that that gas is the lowest cost for Alaskans? We know our Constitution is telling us that all natural resources belonging to the state should be for the maximum benefit of its people, and that we should be using— make it available for the maximum use consistent with the public interest. So when we're talking about about trying to bring gas to Alaskans.

I think that's an important conversation to have. The second part of this that we have in front of us is how do we make that more affordable, and that's through export and/or large industrial use. And so we need to make sure that we're getting the maximum benefit of that gas cost-wise without pricing us out of the market. And so there's this— there's this balancing act that we have to have. And I think that any recommendations that we can get to help us achieve the first part so that we can get to the second part is why we are here talking.

And so I think the— what I am hearing is that this property tax issue is the impediment that we have that we must get past and make this an investable project so we can get to that Phase to bring that overall low-cost gas and a maximum benefit to Alaskans. So I look forward to seeing how we're going to solve that. But ultimately, this is a property tax bill that we're talking about. Those property taxes that are being collected are for the boroughs impacted. This isn't about a revenue measure for the state.

This is how do we get gas to Alaskans, and if we're going to export that gas to make it even cheaper, cheaper, how do we maximize that benefit? So I look forward to our work. Thank you. Representative Josephson. Yes, I don't agree that this isn't a revenue measure for the state.

It better be or I'm going to quickly lose interest. On slide 19, talking about impediments, the break-even matrix, who is the arbiter, Mr. Fulford, the referee if the producers don't agree on a gas price? Is it DNR that has some administrative settlement mechanism, or how does that work?

Thank you, Representative Josephson. That's, that's a big question because In the sense that the Phase 1 gas pipeline is an option for low-cost gas for South Central consumers. It's also an option on a multi-billion-dollar gas sales contract for the upstream producers.

And the only way that gas is going to get monetized is through an LNG project.

Obviously, there are one or two other LNG projects under consideration, but none of them have the same volumetric impact that this one does. So, um, so the terms under which that gas gets sold ultimately It's, it's a commercial negotiation between the producers and Glenfarm. Equally, you know, when you look at it, ExxonMobil and ConocoPhillips, they are one of half, half a dozen global leaders in LNG.

A significant portion of their earnings comes from LNG, a lot of which is from the downstream. From LNG marketing and so forth. And, um, so I imagine they're looking at this project not just from the point of view of selling gas at $1.50 or whatever it is, but from what broader opportunity it brings to them through, through the sort of wider LNG context. So, um, so whether I think the, the only option open to the state if an agreement can't be reached is, is some kind of, um, intervention, um, around, you know, taking control or taking interest, which again wouldn't be a very palatable option at all, um, when you think about Alaska's oil and gas future. So, you know, action which sort of undermines the commercial interests of the players would be unwelcome.

Last follow-up. Is that something that would have to be resolved before FID, as you understand it? I think, through the Chair, resolving the terms of the gas supply agreement would have to be resolved before FID. And I would add that it's not just the price. You know, people talk about, well, it's $1, $1.50.

It won't be a flat price. It'll be indexed. It could be a netback to the LNG price, for example. It could be indexed to oil. There's a number of ways you could do it.

And the way in which it's done will have significant tax implications for the state because the more revenue you shift in the upstream, probably the higher the tax revenue. The more revenue gets shipped into the midstream, possibly a little lower.

Okay. Thank you. Representative Hannon. Thank you, Co-chair Foster. Mr. Fulford, I assume that you are familiar with— and I only had a drive-by, they did not meet with me— but the concept of there's markets for our LNG.

It does not have to go through a pipeline. We could ship off the North Slope. Slope and sell in-state in Alaska and meet some of our markets in Asia without having a $50 billion gas line. Um, have you looked at analyzing any of that and whether that makes gas profitable for Alaska's smaller volume because it has less of a huge capital investment of a, of a giga project? Thanks, Representative Hannan.

Through the chair, I think the way I think about it is that any liquefaction on the North Slope involves several dollars worth of capital and cost. So I would guess that LNG shipped off the slope and brought round and up the Cook Inlet for regasification wouldn't be very materially different in cost to buying it from Canada or elsewhere. And certainly it would be very hard to get that gas up to Fairbanks by doing it that way. So I think the gas line project that Glenfarna are developing is probably the only way to substantially reduce energy costs. For Southcentral and Fairbanks.

I think liquefaction and shipping off the slope is going to be a lot more expensive.

But in your statement, to get cheaper energy though, if we get to Phase 2, because otherwise it's not actually cheaper. Is that correct? That's correct, Representative Hannon. Through the chair, if, if the main LNG project doesn't work, then a 42-inch line all the way down from the slope is a very, very expensive way of getting gas to South Central.

Representative Stepp. Yeah, thank you, Chair Foster, the Chair, and Mr. Fulford. I, you know, I think it's certainly a valid concern. Nobody wants to get stuck with a 42-inch piece of infrastructure I have a hard time believing any sane investor is going to drop $15 billion on a $900 million market, right? So I mean, this project probably goes to FID with all of those pieces together or not.

And I don't— and you have 40 years of experience in the industry. I mean, do you know any infrastructure funder or financier that would give— finance a $15 billion pipeline for a $900 million market through the chair? Uh, thank you, Representative Stapp. That's an interesting question because the, the fact is that none, none of those gas buyers have a balance sheet which can support that level of, of purchase. So, you know, Enstar, Chugach, etc., they, they, they cannot support a $15 billion investment.

So the only way you could create certainty around that would be through the regulatory tariff. So in effect, lenders would be looking at the RCA determination around gas price, and they would be looking at that and sustaining it for 10, 15 years as the way to finance the project. So Effectively, every South Central consumer attached to the pipeline would be committing to years of gas supply in order to fund the project.

Thanks. I've got Representative Tomaszewski and Representative Bynum. Thank you, Co-Chair Foster. Through the Chair, thank you, Mr. Fulford, for being here. We do appreciate all your insights on and the information we have been given here.

I am certainly looking forward to working through this information and coming up with, with my colleagues here, a satisfactory way to make this project and this tax structure go through. When we talk about Alaska being partial owner in this infrastructure. Has there been any discussion in the tax-exempt nature of the state? You know, we have buildings around the state we don't pay taxes on. We don't contribute to the boroughs.

We don't contribute to the cities with the nature of the tax exemptions Is that at all— We've got someone on the line, if they could please mute their phone. Somebody on the phone there has got some background noise. Yeah, has there been any discussion about the nature of us owning 25% of the project and whether or not that negates us from a portion of the property taxes. Thank you, Representative Tomaszewski. And through the chair, I'm aware that, you know, that question has been raised and is being considered.

But I think, as far as I'm aware, the analysis around that and the effect it would have on the overall project economics haven't yet been fully closed out. And this may be a question for Department of Revenue.

Okay. Well, thank you. Okay. And I think somebody is probably going to mute the folks online here in the IT window here. Representative Bynum.

Thank you, Co-Chair Foster. Through the Chair, I guess my final question is, is we've heard a lot about this concept concept of the cost for in-state gas versus import. And there's been some reference to the net benefits of in-state gas versus import. I mean, people talk about jobs. There's lots of other benefits.

But has there been any— have you guys looked at all at the— what the threshold for price differential would be for the purposes of having stability, long-term fixed cost and then those other benefits to having in-state gas versus imports and those uncertainties and those things. Is that something that you've actually looked at or could you give an opinion on that? Thank you, Representative Bynum. Mr. Fulford, maybe if I could just take a brief at ease while we try to figure this out here.

House Finance back on record at 4:25. Mr. Fulford. Thank you, Representative Foster. And Thank you, Chair Foster. Through the chair to Representative Bynum, one of the, one of the most important attributes of the Alaska project and its potential to create jobs, revenue, investment is that it's not— so there's no connection with the lower 48 or indeed Canada.

So, so you're looking at this vast gas resource, multiple trillions of cubic feet of gas, which is producible for the, for the most part at a very low cost. So you're immediately then removing, you know, one of the big uncertainties about, for example, investing in an ammonia project in on the Gulf Coast. You're already there, you're at risk of these rising wholesale gas prices that we talked about. But if you're making an investment, you know, in Alaska, whether it be petrochemicals or data centers, et cetera, one of the main advantages is having that view to low-cost gas at a relatively low number for decades to come. And again, it sort of emphasizes the— the immense long-term value of that resource.

Thank you. Do we have any further questions or comments? Okay, seeing none, uh, Mr. Fulford, any closing comments? Uh, thank you, Chair Foster. I, I think I've probably made plenty of comments.

Okay, well, we appreciate your being here. If folks do think of additional questions, I know that Mr. Mr. Fulford will be in Juneau tomorrow. I think you have a 9:00 a.m. meeting with the Senate. And— but if folks are interested in having him back, we could certainly arrange that. So with that, our next meeting is scheduled—.

Co-chair Foster. Yes, is this interrupting more?

I'm sorry. I don't want— I couldn't figure out how to interrupt. I'm so sorry. I just wanted to thank Mr. Fulford for being here today and for taking our questions.

And I know this was a little bit of a long meeting and just really appreciate all of the dialogue today and all the information. So thanks so much. Great. Thank you very much, Representative Moore, for being online. And so with that, our next meeting is scheduled for tomorrow, May 27th, at 1:30 PM.

And at that meeting, we'll have a presentation from the Alaska Gas Line Development Corporation. And so again, again tomorrow at 1:30 PM. If there's nothing else to come before the committee, we'll be adjourned at 4:28 PM. Thank you.