SFIN-260528-0900

Call the Senate Finance Committee to order. It is 3 minutes after 9 AM, May 28th, in the State Capitol Senate Finance Room. Present today are Chairman Steadman, Senator Keogh, Senator Merrick, Senator Kaufman, Senator Cronkite, Senator Olson is watching at home in Gullivan, Alaska. And I'm present, so we have a quorum to conduct business. Today's agenda: SB 2001, gas pipeline, or Valmetrix tax.

We continue our discussion with Nicholas Fulford of Gaffney Klein and follow up on questions from Yesterday's presentation, we are starting with some of the basic megaprojects and this proposed project. We hope to build a foundation so the committee and the public can understand the issues in front of us as we can make the most informed decision as possible.

We'll be hearing from various stakeholders as we go forward. I encourage members to forward areas of interest that they would like to see covered and explained in presentations so we can work with the stakeholders to have the most valuable presentation possible. A reminder, Mr. Fulford from Gaffney Klein, our legislative consultant, will be available for the next couple of days to meet with members and their staff I encourage all members to take advantage of this opportunity to help educate themselves on the decisions we will be making as we work on this gas line legislation. Are there any questions from committee members at this time?

Please come forward, Mr. Fulford. Introduce yourself and continue with your presentation to the Senate Finance Committee.

Well, good morning, Chair Hoffman and committee members. Welcome the opportunity to continue our discussion about this important project. For the record, my name is Nick Fulford. I'm Senior Director of Gas and LNG at Gaffney Klein.

So today's agenda starts with a couple of follow-up points from the meetings that we had yesterday. Then I wanted to move on and talk about the volumetric tax concept in general. Obviously, this is something which has been raised, has been debated quite a lot the last few weeks. So it's helpful to kind of put that into context. And as we discuss that, it's helpful to look at what some of the other states do, particularly in the lower 48 Gulf Coast states like Texas and Louisiana, where obviously there's been a huge amount of LNG development.

The, the other feature of that I wanted to talk about was the concept of either a, a tax abatement or a tax deferment, because from a discounted cash flow point of view, it makes quite a big difference.

The, uh, the next part of the discussion I wanted to talk about was FID considerations, and in particular the Phase 1 gas line and what would go into that.

Uh, the area I wanted to finish off with is the project development value creation, looking at ways in which a developer can profit from a project in general at the early stages. So with that, I'll commence my follow-up.

So one of the interesting things that we began to talk about yesterday was capital cost. Obviously it's been a very significant element of the debate over the last few weeks, both within the Senate and the other committees. And so what I did last night was to dig into some of these projects, especially the ones in Canada, and sort of refresh myself in terms of where these have ended up.

Certainly, as I'm sure the committee members are aware, the feature that really brought LNG capital costs into the public eye and into the front line was the immense expansion of LNG in Australia. Where many of those projects endured a cost overrun of up to double, and quite a few billion dollars of additional CapEx had to be deployed. So for the developers behind those projects, these were very significant events, you know, even with their strong balance sheets. So as we look at Canada, the, uh, one of the projects I highlighted yesterday was the Ksila-Shems project, partly because it's so close to Alaska. It's an interesting project in the sense that, like Alaska, it, it depends on a fairly long pipeline, parts of which are in existence already.

Some linkages needs to be, needs to be done. And the other interesting difference, certainly with that project and some of the other projects, is that they rely on what's called floating LNG technology. So this would be a vessel or a barge built elsewhere, predominantly in Asia, China for example, and then moved into position. So effectively this means that a lot of the engineering work that goes into the liquefaction side of the business can be done remotely and the thing moved in. So as you look at the quoted cost for that XylaShims project at around $1 billion Canadian per MTPA, that brings you to an extraordinarily low number.

And one of the reasons is that it doesn't, I think, include the FLNG module.

Very approximate read across to Alaska LNG. I think if you add in the cost of the floating LNG, you get to about $30 billion for a 20 MTPA project. Wood fiber was a kind of a first of its kind project. There were a lot of features of that project that were innovative and therefore more expensive, so that one comes out as the most expensive. Um, that the estimates for that project are $4.2 billion per MTPA of capacity.

So if we multiply that for AKLNG, it, it comes to around about $84 billion. So, you know, a very large number, much larger than the number that's being talked about in, in the recent testimony. LNG Canada, obviously that's interesting because it's an existing project, and as I say, they're contemplating Phase 2. The— if you run through Phase 1, it comes to about $1.2 billion for— in terms of MTPA. Some of the quotes you see as high as $2.3 billion, but These are not excluding the, the pipeline— not including the pipeline, I should say.

So if you, if you work that forward, that comes to about $47 billion for the AK, um, for the Alaska project. So if you dig a little bit deeper on LNG Canada, the cost overruns for the liquefaction side of the business were material but not unusual. So $14 billion Canadian turned into $18 billion. But where you do see the very substantial cost overrun is with the pipeline. I mentioned yesterday that it's a technically a very challenging route across the Rocky Mountains and that it was being built during COVID And then the third factor, which was the lack of It's not all the First Nations communities along the pipeline had been included in, in the various agreements, so that led to litigation and delays.

So you can see the effect of that was moving that pipeline from $6.6 billion up to $14.5 billion. So I mentioned some of the fiscal concessions that LNG Canada had secured. Secured at yesterday's meeting. And there were in fact one or two follow-ups that were negotiated with the provincial government, but not on a similar scale to the ones that they secured in advance. So I'll pause there for any questions or dialogue, but those were the key follow-ups from yesterday.

Thank you for that, Senator Keele. Thank you, Mr. Chairman. Mr. Fulford, just to make sure I understand, when you say the LNG Canada range does not include existing pipeline. When you draw the rough equivalency to what it would be for an AK LNG project, does that $47 billion include the pipeline, or is that gas treatment and liquefaction for export but not pipe? Thank you for the question, and there are certainly a variety of quotes that you see written for LNG Canada.

One good rule of thumb is if you look at Gulf Coast liquefaction, because of the existing marine facilities, certainly in the projects that have been turned around, the, the general rule of thumb for that is, you know, $800 to $1,200 per ton per annum. So that would be $800 million to $1.2 billion per MTPA. So the, um, that $1.2 billion, uh, for Phase 1 of LNG Canada, that would be very equivalent to a Gulf Coast price. But certainly the, the higher number, the $2.36, is one which has been, I think, assigned to Phase 2. Which is going to FID at the moment.

So if they do achieve Phase 2 FID on a cost of $2.36 billion per MTPA, then that suggests that Alaska potentially has a lot more headroom than previously believed, because if they can invest that and sell LNG profitably into Asia, with a $47 billion equivalent just for the LNG, that suggests that the economics of Alaska might be stronger than previously believed. Senator Kyl. Thank you, Mr. Chair. I appreciate that's an interesting hypothetical.

Do we have a sense of how far out they are from phase 2 final investment decision? Thank you, Senator Kyl, through the Chair.

There's been quite a lot written in, in the media about that, and many of the indications suggest that the, the project could well reach FID this year. This Phase 2, that seems to be the, the target that the developers are having, and I think there's a general belief that that may happen, especially picking up some of the points we're talking about yesterday with Qatar. You know, there is many strategic LNG buyers are reviewing their LNG portfolios right now, and in, in the current climate, it's conceivable, I think, that LNG Canada could secure a small price premium just for security of supply. So I, I think watch this space during this year, I think, will be the, the key. Senator Kiel.

Senator Kiel. Thank you. Thank you, Senator Kiel. Further questions? Please continue.

Thank you, Chair Hoffman. And so the next section of the discussion this morning is about the volumetric tax. And one of the questions that has come up, and certainly relevant to whether a volumetric tax is appropriate, is you know, the extent to which it's used elsewhere. And I would say representing a volumetric tax as a means of collecting government revenue is a somewhat unusual feature in the gas industry. But if you consider the topic perhaps a little bit more generally, you know, there are quite a number of ways in which governments collect revenues on a volumetric basis.

And one of the most common is to do with gas transmission transit. So Ukraine would be a good example, Germany, that would be another mechanism which would be volume-based.

Whether it's volumetric or based on energy is, I think, a question. I mean, normally these things are based on energy, but for the most part Gas is a, is a relatively standard commodity. It's roughly, you know, 1 MMBtu per 1,000 MCF. So when we talk about a, a volumetric tax on gas of so much per MCF, it, it is more or less equal to the same number per MMBtu. But all the same, it is usually energy related, but there are a number of examples.

So taking that sort of generic, you know, volume equals energy, Nigeria has a facility fee model which involves government revenues. And of course, you know, the US FERC-related management of interstate pipelines results in essentially a regulated fee which is considered to be appropriate based on cost. So those are 3 examples. You know, more generally, pipeline transit fees, Georgia would be another example. And then there's a body called the Extractive Industries Transparency Initiative, which is primarily aimed at developing economies.

But they, they provide guidance on how to collect taxes and government revenues through volumetric mechanisms. So, so there are definitely examples out there. It's, it's a relatively well-established concept. My only comment is that it would typically be energy measured by energy rather than volume, but that's, that's just a minor a minor current. Well, with the amount of gas up in the fields, we have a tremendous amount of gas compared to other projects, and it would seem that the industry wouldn't be acceptable to a volumetric tax.

Is that a general statement, or I guess it all depends upon what the rate would be for that volumetric tax? That brings in mind, what are those rates for these projects? Maybe you can get that to the committee for consideration. Yeah, thank you, Chair Hoffman. I'm sure I can get some data where we could measure transit fee by miles of pipeline and work out the capital.

I'll bring that back to the committee tomorrow. Further questions on this slide? Please continue.

Thank you, Chair Hoffman. And over the last few weeks, months really, in looking at different types of tax policy that are applied to LNG.

One of the best sources of insight in some ways would be Texas and Louisiana, partly because the, the number of LNG facilities built or being built is very considerable. The, the one big difference between Texas and Louisiana and Alaska is that what we're looking at here is, is a kind of a generic property tax relief legislation which applies whether it's an LNG plant, you know, ammonia, gas to liquids, hydrogen. So, so the key criteria certainly for Louisiana is job creation. So as long as you can show that the economic investment that you're making, whether it— whatever industry it's in, as long as it's creating jobs and developing the economy, then you, you'll qualify for these kind of property tax concessions. So obviously what we're talking about in Alaska is a single, one single project that has a fundamental effect, and obviously that in itself creates a kind of a different appraisal, so some of these things may not be directly transferable.

But nevertheless, the mechanism in Louisiana through this industrial tax exemption program represents, well, up to an 80% reduction in property tax for 10 years. In reality, with different negotiated arrangements, many of these projects have a full property tax holiday for 10 years, after which the regular tax comes back in and becomes payable. The Obviously another significant difference in this slide is that in Louisiana the property tax rate is 10 mils rather than 20, and there are differences in the way in which the taxable value of the facility is calculated. But you can see there, um, you know, Sabine, which is being expanded, Cameron, Calcasieu, and Plaquemine, they're all existing LNG projects. And you can see there on the chart the value of the property tax concession for those companies is, is quite substantial.

I've added Magnolia LNG because obviously that's another project being developed by Glenfarm. It's, it's at a relatively conceptual stage, but nonetheless it, it does qualify for this property tax exemption. The value you can see there is also proportional to the throughput of the LNG, so just bear in mind that the larger numbers you can see there, for example, Sabine, Cameron, you know, these are multi-million MTPA projects, and which is partly why the numbers are so big.

So that's a good summary for Louisiana. I can move on to Texas if there are any questions. A couple of questions. Are these— any of these projects constructed?

So the— all the ones in white are constructed. Black means is the last one, but that's that's operational now. And both Calcasieu Pass and Plaquemines is being expanded. Sabine's already been expanded.

So, so yes, these, these are operational except for Magnolia LNG, which is, as I say, under development. And the other question is, of these property tax incentives are any of them recouped after 10 years or are they not? Senator Hoffman, Chair Hoffman, they're not. So the mechanism in Louisiana is a— well, it's a forgiveness, if you like, of property tax for a period of 10 years, after which the normal rates apply, but there's no there's no recouping of unpaid property tax.

Senator Kaufman, thank you. I know that some, some of the coastal Gulf Coast facilities were repurposed. They were LNG imports. And I don't know, does that complicate the numbers a little, that there was some existing infrastructure for import and then repurposed through a retrofit project? Uh, thank you, Senator Kaufman, through the chair.

That's, that's absolutely right. It's obviously, it's a kind of a hallmark of some of these Texas LNG facilities. Of the ones on there, Sabine Pass was repurposed. The others are, are brand new, so to speak, including all the marine facilities. And So it's an excellent question.

I'm not quite sure what the implications would have been for property tax. But from the numbers on that chart, you know, you can see Sabine is the one that was repurposed and it has one of the biggest property tax reductions. So probably it doesn't make a lot of difference. Senator Kaufman? Thank you, Senator Kaufman.

Senator Steadman? Thank you, Mr. Chairman. Yeah, I think Sublime Pass never even became an import facility. They never finished it. They got it almost done and then they had to, for a layman's term, turn the valves around and turn it into an export facility instead of an import facility.

It was designed to be an import facility. So the market changed during that construction of that project. Louisiana, so they basically go from 10 mils down to 2 mils for 10 years roughly, and then there's some fluctuations around there? Is that kind of their basic structure? Yeah, thank you, Senator Steadman, through the chair.

That's a good summary. What I would say is that that remaining 2 mils, from what I understand, And I don't have detailed numbers on this, but from what I understand, through various other tax exemptions and local arrangements, I think most of the rest of that 2 mils disappears as well. So I think you could almost regard Louisiana as being a full property tax holiday for 10 years, even though notionally 20% is still payable. And the 10-year kickoff is when gas first flows. I believe that's correct, Chair Hoffman.

But it was one of the things I was planning to drill into a little bit more. Okay. Further questions? Senator Keele. Thank you, Mr. Chairman.

Mr. Fulford, do any of these incentives touch Louisiana's personal income sales or corporate income taxes. Thank you, Senator Kiel. And through the chair, the, the more you, uh, delve into these Gulf Coast LNG projects, the, the more you, um, find in terms of different concessions, grants, job creation programs. So I think the answer to the question is probably that there are a suite of other features which provide incentives for these projects, but probably none of them are of a similar order of magnitude to the property tax holiday. Thank you, Senator Kiel.

Thank you, Mr. Chairman. Thank you, Senator Kiel. Further questions? Seeing none, please proceed.

Thank you, Chair Hoffman. So moving on to Texas. So the mill rate in Texas is higher, or notionally higher. It's comparable to that that applies here in Alaska.

But around half of it relates to school district property tax. And I think partly as a— and obviously, property tax holidays, call it what you will, or excuse, is a matter of policy that many people have a view on. And I think even in Louisiana, I think on the previous slide, you know, the state auditor put a number on the sort of property tax reductions that have been offered to these LNG plants, and there's a body of opinion which is that It's a very high number. So that same debate took place in Texas. And so in 2023, the, the decision was taken to keep the school district property tax outside the LNG tax exclusion for, for the remainder.

So up until 2023, there was a, a full tax, property tax holiday. And then after 2023, it was limited to the county, city, and Port Authority mill rates, uh, which, which formed the, the tax holiday. So really, the, the property tax concessions, you could say, were, were roughly halved in, in 2023 as a result of this treatment for school districts. But nevertheless, you can see on the— you know, a number of Texas-based projects which have received significant property tax concessions. Not as much as in Louisiana.

So Corpus Christi, that would be another of the reversed LNG facilities.

Next decade— well, next decade and Texas LNG came in after the change in property tax. So you can see that between the lower volumes for Texas LNG and the smaller property tax concession, you can see that the value assigned to land funds property tax concession for Texas LNG is somewhat lower.

Questions on this slide? Senator Kaufman? As we're thinking of our property tax rates or other tax rates on the infrastructure of the pipeline, while we're trying to compare here, The one of the huge differences is the source of the gas. And so, I mean, there's things that make it such an apples and oranges comparison where I'm sure most of the gas that's being transported in these lines is not coming from state ownership with any kind of royalty or maybe very little. Do we just need to make that distinction as we're looking at the different tax regimes of of the economic impact, the total return of gas transport if it's coming to the entity, be it, you know, the state or U.S., of who owns the gas in these cases.

Is it individual or state-owned? And where— if you're producing the gas and you're moving it, what the total return from that is relative to the property tax. Seems like there's things we need to sort out there. Uh, thank you, Senator Kaufman, and through the chair, it is perhaps a good juncture, you know, using that question to kind of reflect more generally on the Alaska LNG project. Um, in, in the senses we've, we've talked about a few times, it's, it's kind of unique.

Um, and, you know, if you look at all those, uh, LNG projects in Texas or Louisiana None of them really move the needle in terms of the state economy on their own. Obviously, the LNG industry in aggregate has kind of created a lot of economic growth, but individually these projects don't make a lot of difference.

And as you say, the gas being used for the projects— Texas, Louisiana, they have a severance tax. At the wellhead, but it's, it's just a few percent. It's not very high. So most of this gas would be in private ownership, would be developed, you know, in, in under very commercial terms. So, um, so I, I would agree generally with the, the idea that some learning is useful from these other examples.

I would say the most significant learning, which we'll perhaps come on to, is that in offering these tax concessions for 10 years, it's kind of recognizing that with these very high capital projects, it is in that first 10 years that the economic boost given to the project by tax forgiveness is the greatest. So that's probably the main takeaway, I think, from this, that it's that 10 years. And I could give you dozens of examples of other 10-year tax holidays, whether it be, you know, Trinidad or Senegal or wherever it happens to be. So it's kind of a long answer to the question, but it's a valid point. Senator Kaufman.

Thank you, and I absolutely agree about the positive effect on a project of a certain term of tax relief. If it's not productive, you're taxing it for merely existing, and that's not a beneficial incentive. So it— but I guess the total point that I was making is that in, for instance, in Phase 1 of this where we're going to be the in-state users of it, we're to some degree taxing ourselves. For gas that's being used in-state. And meanwhile, we're also making money on the gas that's being produced.

And so that's why I'm referring to the total return of the project. It can't be looked at the same as where all you're getting is a severance tax, because we're in a unique position as owners. And so the total value of the project is going to be the sum of all of that revenue, however we structure that, you know, with the gas policy as well as the gas transportation policy that we need to do. So, yeah, these tax holidays are absolutely an enterprise corridor concept with a certain tax abatement as a well-recognized way of getting a project bootstrapped and getting it going and enduring that high-cost early period zero or low productivity. Thank you.

Thank you. Do you have comments on— Senator Kaufman's statement.

I would, through the Chair, I would just acknowledge that, you know, the— maybe another general point, thinking about the hearings and testimony that we've all witnessed over the last few weeks, and it comes back again to what we were discussing yesterday about the differences between the original integrated project involving the upstream providers and the Glenfarm-led project here, in that all this dialogue that we're having is all aimed at the midstream. It's the treatment plant, the pipeline, and the LNG. And I think as Senator Kaufman has pointed out, there's a whole other tax-generating activity going on here, which is the upstream, which hasn't perhaps had, you know, a great deal of attention over the last few weeks. Can we also— can we get, if possible, the length of these projects, the size of the pipe?

So we get some reference to the project in Alaska. Yes, thank you, Chair Hoffman. I can do that. There's so many of these projects now. I used to be able to remember each of them and their capacity, but there's so many.

I'll revert with a proper research list. Thank you. Further questions?

Thank you, Mr. You know, every— I'm looking at this and I'm just relating this. Okay, so you're asking for relief, or if they get relief in Texas and Louisiana for this, and yet we want to build an 800-mile pipeline through the harshest conditions in North America. And we have to be able to expect that we need some of those in order to build this line. I mean, these guys, their shipping costs are way way cheaper, everything to get there is cheaper, and we're gonna try to build this. So I mean, I'm like, these people are out, you know, are getting some breaks, yet we're sitting here arguing, should we give breaks to building our pipeline in the harshest conditions and, you know, maybe very limited building seasons of time when they have to put that pipeline in the ground.

So it's just, when you relate this to us, like, if these people need some sort of tax break, you know, to get this, I think it must be imperative that Alaska has that in order to succeed in building this gas line.

Thank you, Senator Cronkite. Through the chair, again, picking up some of the themes that we've been talking about over the last couple of days, the Effectively, you have the sort of developer economics and the risks and the potential cost overruns and so forth, which we talked about, and then you have the kind of steady-state delivery of value from the project. And one of the things I pointed out in the report that we did back in December is that Given the host nation kind of focus on long-term strategic planning of the economy and revenues and so forth, and the developers' focus on making sure they get their money back in the first few years, often there's a kind of trade-off between those two. So, for example, you know, a tax concession offered for the first 10 years might be countered with some other benefit which, you know, that is perhaps more important for the state in further years. And one of the advantages with these LNG projects is that they go on for so long that that kind of trade-off is possible.

But equally, the tax— the state has needs, the communities involved have needs in terms of infrastructure, community support and so forth. And that somehow has to be paid for as well. So that's the tricky bit. It's how you present an economic package that will enable the project to just make its FID, but you're still providing funding for that kind of essential support that's needed. Senator Cronk?

Thank you, Senator Cronk. Please proceed.

Thank you, Chair Hoffman. So the Maryland example is interesting because it has parallels to the, as I say, the unique nature of the project here in Alaska. So the COVID Point terminal was another of the LNG terminals that was built as an import facility and then mothballed for the best part of 20 years because of the change in market and so forth. But of course, with the advent of shale gas and so forth, as Senator Steadman remarked earlier, there was this tremendous reversal in terms of US becoming an exporter rather than an importer. So the existence of that facility became much more key.

And a little bit like Alaska, one of the challenges that the local communities encountered is that most of their funding came from the property tax revenues from the COVID Point Terminal. And over the years, there were various disputes around taxable value, you know, what should be paid and as a result, a lot of the local communities had a very volatile and very difficult job in terms of planning revenues, expenditure for schools, so forth. So one of their reasons for moving to a PILT, payment in lieu of tax, was simply to overcome that kind of volatility in local funding. Which they'd experienced because of the property tax. And it's something that we talked about briefly yesterday, but, you know, one of the challenges around property tax is that it does not sit happily with this idea of fiscal stability, that, you know, it can be reevaluated, it can be changed, and, you know, it's difficult to plan for.

So, so it's an interesting one. The, the PILT was fixed, and it depends, depends on whose evaluation you take, but the payment in lieu of tax was, was now, now fixed for 15 years. It runs to 2038, and depending on whose opinion you take, it's, it's either more or less than the property tax that would have resulted. But as I say, the lesson from it is that a fixed revenue such as a volumetric tax or a PILT can work better for local communities because of the planning ability.

Questions? Seeing none, please proceed.

Thank you, Chair Hoffman. So I know you'll be hearing a lot more about, about this from DOR and others, but just to set the scene and put a few ideas out there about the volumetric tax, the— these numbers from the DOR model, which I'm sure you'll hear much more about, the, the current property tax projection up until 2062 would amount to just over $23 billion of revenue, of which about a third would go to the state and about two-thirds goes to local communities along the line and affected host communities. The volumetric tax in— certainly in the original bill set at 6 cents comes to about $2.6 billion. Of which about 1/8 goes to the state and about 7/8 goes to local communities. So if you, if you do the maths on that, it's equivalent to about $2.25 mils compared to the $20.

And you can see there, um, the bar chart on, on the left is what's projected from property tax, and the one on the right is, is from the volumetric tax.

So in very brief terms, that's roughly what was put on the table a couple of months ago now. And— but what I wanted to do was sort of develop that a little further and look at a number of illustrative scenarios.

And as I say, I think you'll be hearing more about this from DOR and others. Is there any way to get a copy comparison of the mills in 138 as compared to these numbers here? That's an interesting question, Chair Hoffman.

Somewhere on my laptop I have the built proposals which were put in front of the Municipal Advisory Gas Project Review Board back in 2014-15. I think there's others in the building who were there at the time, but it was never— it was never closed out. But what I can tell you is that at the time, a PILT which started low and increased over time was, I think, the broad concept that was, I think, accepted by many of those stakeholders 10 years ago. Further questions? Senator Steadman.

Thank you, Mr. Chairman. I think, you know, one of the things that I think we should look at when we look at this property tax, if it's the full 20 mils or 10 mils, or if you do a 10-year abatement or whatever we're going to do, I'm not too interested in looking out to 2062. You know, maybe looking out a decade or decade and a half because we're a little bit well past first gas then. But in particular, breaking down the beginning years of when the tax would come in place, because you're not implementing a property tax on something that isn't constructed. It has to be physically in your borough.

And then you've got to go through the calendar process of having the assessment done.

Triggering the bill. And if you have a gas line that goes from the North Slope to the west side of Cook Inlet, that doesn't affect the Kenai Peninsula. You know, the liquefaction plant does, and when they connect it. So I think we need a breakdown of the construction schedule and time. And I don't care if it's 6 months or a year schedule or whatever they're going to however we're going to put it together, and then get an idea how much tax would be implemented in each given year through the construction and after first gas.

Because it's— you don't pay 20 mills on the entire line when nothing's built.

So I think we need to look at it in more detail.

And over the next few days, Mr. Chairman, to get an idea And it comes down to the question we're going to have coming forward with Glenfarm is the cash flow analysis that we're going to want to look at. And their debt levels and all the whole ball of wax to get an idea of what we're dealing with because the presentations that have been given so far I don't think go into those details.

Or their numbers are just pie in the sky. There's no validity to them, or most of them. Mr. Fulford, do you have comments on Senator Steadman's statement? Thank you, Chair Hoffman. And I think, you know, one of the key points is absolutely cash flow and timing because Certainly for the project, as I've mentioned many times, the higher the cost burden and the earlier that it applies, then the effect on the internal rate of return is kind of magnified.

So I think it sounds like a good place to start in terms of looking at the actual cash flows and how taxes could be applied to accommodate that. Before we go forward, I'd like to acknowledge the presence of Senate President Jerry Stevens, Senator Jesse Bjorgman, and Senator Rob Meyer. They've been here since the beginning of the presentation. Please continue, Senator Keele. Sure.

Thanks, Mr. Chairman. Mr. Fulford, just looking at the slide, certainly this This tax structure does a lot for the stability issue you mentioned. And it addresses that carrying cost of tax liabilities before there's cash flow, right? Looks like just squinting at the slide, it looks like a couple hundred million before the line only. And then, you know, probably a billion and some before LNG.

Sales at volume. So I get not having to put those on the books and borrow them, pay interest on them before you got cash flow.

The flip side is what you described in answer to a previous question by another member, the need for the state and some municipalities to provide some services. Good problem to have with an economic growth project, right? Fix the roads, educate the kids, occasionally somebody gets in There's trouble somewhere, there's a public safety cost. Is there a structure of this volumetric tax that could help address those upfront public sector costs, or would there need to be another element? What would be— I guess, how would we be wise to think about that?

Thank you, Senator Keel. Through the Chair. Certainly I've been following the debate in different committees over the last few months, and I think exactly that point has come up, and I think there are some suggested solutions to that which involve various impact fee payments to address the very tangible impact of a very large construction undertaking happening in a relatively small community. So perhaps I would leave it at that and just say that the point I think has been well acknowledged by Glenfunnan AGDC and a number of suggestions have been made. Thank you, Senator Keogh.

Further questions? Please continue.

Thank you, Chair Hoffman. Just first, before we get into this slide, just to make it clear that this is simply an illustrative exercise to demonstrate how the timing of these taxation cash flows can matter quite a bit. So on the left-hand slide, the blue bars represent exactly what you saw on the last slide, which is the standard property tax application over time. So just from a— for a theoretical exercise, what I said was, well, if FID is in 2026 and construction starts and so forth, if we were to delay any property tax collection until 2036, but but also ensure that that missing tax, for want of a better term, is collected over time, you know, what would that look like? So obviously you've got on the orange line, or orange bars, you've got a lack of tax in the first 10 years, and then you've got an increased tax in the remaining years up to 2062, or whatever year you want to choose.

So for the state, you still end up with the $23.1 billion. Okay, you have to wait till 2036, 2062 to collect it. But for the project, they have 10 years following FID to address technical risk, cash flow, etc. So you might say, well, what difference does that make? Because you know, the project still has to pay the tax, so, you know, what's the— what's the benefit?

But then if you— if you look at it through the magnifying glass of discounted cash flow, which typically would be how a big mega project like this would— would examine it, then the picture starts to look very different. And I do apologize, the blue and the orange have switched for the right-hand line. So on the right hand graph, the, the orange line is the discounted value of the standard property tax, and the blue line is the discounted value of the delayed property tax. So, um, so what you see there is that if you, if you look at it through a DCF lens, the project is actually making a 30% saving. So instead of a discounted cash flow amounting to $4 billion, it's one that amounts to $2.8 billion.

So as I say, just up here for illustrative purposes, but if, if you were to delay the collection of property tax and then collect it in future years, even that represents quite a significant benefit to the project. So I think as we think about a framework which might work for the state and the project, this might be something to consider. Questions? Senator Steadman? Yeah.

So the— it doesn't seem like we get any credit for the billion dollars we already have sunk in the project. Ballpark number, what we've got invested in the gas line.

Recently there's been some forgiveness given on gravel extraction, and that's several million— several tens of millions of dollars in concessions. So I just thought I'd put that on the table, that there is concessions and expenditures that we've already facing that we're not recognizing, and this is just another step. And as you mentioned earlier, Mr. Fulford, I think we should expect if we get to further down this project and get to major gas off takes on the North Slope, we'll probably be asked for concessions on the upstream.

Is that accurate from what you've told us? Mentioned. Uh, thank you, Senator Steadman. I think that's, um, that's a good appraisal. Um, and as, as you say, over the years, um, I, I've seen the same estimates that you have, I think, of billion dollars of state funds, um, being deployed to get the project moving.

Um, I think perhaps for people at home as well, it's worth remembering some of the maths that we did yesterday So it's a billion dollars of state funding, but every year this project will be selling a billion MMBTUs of gas. So, you know, if you were to add a dollar for the first year or for any year, you would get that billion dollars back. But— so in the general scheme of things, of a project of this importance and magnitude, it's not unusual for funding of that level to have to be deployed as part of the project development. It has to be said that the Alaska LNG project has probably been, you know, one of the longest-running gas development stories that we've ever seen, and because of that, the funding is significant. But as I say, the value of that billion dollars would come back relatively quickly if the project were to go ahead.

That's useful to bear in mind. Further questions on this slide? With that, we'll take a 5-minute break for the next 7 minutes.

Ready's.

Call Senate Finance Committee back to order. Or FID considerations. Mr. Fulford, please continue with your presentation. Thank you, Chair Hoffman. So I know the broader kind of mega project risks and process of FID, I know it's something that you'll be delving into in the next few days and in the next few weeks.

But I wanted to set out some ground rules and perhaps talk more generally as to how FID typically takes place.

So on this slide we have in front of us now, the— and I think many of— certainly many of the committee have been on courses and discussions around megaprojects and how they work. But certainly for the folks at home, it's probably useful to kind of recap a little bit. So the key thing to bear in mind is the kind of pre-feasibility process where, you know, you'd look at the rough costs of the capital, you'd look at the economics of the gas, you'd look at the market, and you'd establish whether there was a sufficiently robust project to to spend money on. So that, that really would be the decision gate one. It's like, yep, we've got a project here that works.

And the, the next phase would be a kind of a concept selection. For example, are you going to do floating LNG? Is it going to be fixed? Um, you know, what, what type of liquefaction might you use? And that's when, you know, typically you'd start spending in the millions of dollars in terms of engineering and costing.

But the real decision to deploy significant capital happens at decision gate 3, which is where you'd move into FEED, front-end engineering design, which for a major LNG project would be tens of millions of dollars. So this would be a this would be at the point where you have a project that you feel is, um, is promising enough to deploy quite significant funds to, to develop. So, um, so this is— I, my understanding is that this is kind of the, the phase that we're in at the moment with Glenfarn. One of the, one of the benefits of that billion dollars that we were talking about earlier that the state has spent is that certain aspects of this project are very, very well advanced indeed, and in fact a lot of that work that was done under SB138 is being reused now, you know, obviously updated and amended. But when you think about that money that was deployed, you do have as a result this relatively detailed concept of what the project would look like.

However, you know, there continue to be key aspects of that which still need to be defined, and probably the biggest one, which we've been talking about a lot over the last couple of days and the last few weeks, is these, uh, capital cost estimates and how they're coming in. So typically, as you see on this diagram, the point at which you would reach the final investment decision would be after you've carried out this front-end engineering design. You have more accurate data on costs and and who is going to build it. And at that point, it's in, in, in general terms, I suppose you could call it the point of no return. So once you get to FID, then, you know, you're signing binding supply contracts, you're signing EPC agreements, you need to have much of the regulatory process in place.

And so, for example, all the work that we've seen reported in the press in terms of letters of agreement and letters of intent in terms of LNG, you know, all those things would need to turn into typically, you know, a sale and purchase agreement to enable things to move forward. So the key points I've mentioned, they're kind of listed on this slide, project technical scope, so you need to know exactly what is being implemented, the key design parameters. One of the other features which is common in a project of this size is to do a kind of risk analysis, and that's something that we do quite frequently for— as a sort of a pre-FID checklist. Because ultimately, as we've discussed, you know, LNG Canada, a good example, on the pipeline even when you get to FID, you haven't removed all the risk in terms of cost. So that kind of risk assessment and looking at where your vulnerabilities are would be key.

The other feature, given the scale of the project, is debt funding. As we've discussed, in a project of this sort, probably be 60, 70% maybe even more, financed on what they call a non-recourse basis. So this would be off balance sheet, so companies would contract with a consortium of banks that would lend the money and would take some degree of risk themselves. But in moving to FID, you know, everyone is doing due diligence but the banks probably do more than anybody. And certainly I've seen LNG projects that have had to have been quite significantly reworked at a relatively late stage simply because the lending community are not comfortable with, with the degree of risk and risk medications that's happened.

So one of the key challenges for this project when you're probably looking at $30 billion or so of debt, is between now and FID, the people providing that $30 billion have to go through this project with a fine-tooth comb and consider every kind of scenario to make sure their money is safe. So in some ways, if the project can secure $30 billion of debt, then right there, there's a relatively high degree of confidence in the project's ability to go forward. So, as I say, you know, the due diligence carried out by the lending community on a project of this scale would be immense and very, very thorough. So with that, I'll move on. If there's questions—.

Mr. Chairman, thank you.

So we've talked about that 40, mid-40 range cost factor, and some of us believe it's complete nonsense, right? It's an old number that's not relevant, and we'll get into that when we get into our modeling in a couple of days. But if they do the, you know, 70% debt level, there is the government loan guarantees and backing that we need to to get an understanding for over the next several days what that entails. But my understanding from the federal folks that I've talked to, it's if you do 20 years, it's 20 years plus 3/8 on the government bond. If you do 30-year financing, it's 30-year government bonds plus 3/8.

Pretty straightforward. But what's not straightforward is 70% of 45, which is about $30 billion in debt, And a more realistic number, just dealing with some of the cost escalations, uh, is in the neighborhood of $60 billion, maybe over, because from what we understand, that, uh, construction and pipeline construction costs have escalated a little faster than inflation. So it's probably somewhere north of $60, but just using $60, that's a debt increase of $12 billion. $12 Billion is a big cash flow payment to meet in and of itself. So when we start looking at the cash flow modeling, that's a significant issue.

The price of this project and that, that 70% debt level, and I think the common terms or ranges from 60% debt to 80% debt. So just using the middle number at 60, and we can run the different scenarios, But somebody has to meet those semiannual bond payments. And $12 billion is a lot of money. And it shouldn't be, you know, just disregarded. So we'll work on that with the model that we have in place that I think we'll find— members will find it's a sound model.

It's the inputs that we're going to be having significant concern about. And that model has been worked on and assembled over the last several years. It's not something that was just put together. I just thought I'd make that point, Mr. Chairman. Thank you, Senator Steadman.

Further comments? Senator Keele. Thank you, Mr. Chairman. So, Mr. Fulford, you've got a slide here about the things that go into DecisionGate 4, as I understand it. Is there a sequencing to these, or are these all running in parallel when you're at that point in the game?

Certainly, Senator Kyl, through the chair, yeah, the sequencing is essential. So it's a flow through which the project becomes better and better defined. The engineering features of it get right down to significant degree of detail. To the point where you can discuss with EPC companies a budget and a timeframe and a whole range of detail. Senator Kyl.

So for folks in our position trying to assess where things stand and how things are, some of these obviously have great visibility, right? Permits and regulatory stuff, there's public notices, we see that. Things like financing, the bankers doing the diligence they need to, are there ways that we can see into or get at least a distant view of where some of these other items are in the process? Thank you, Senator Kiel.

That's something that I'm sure Glen Farnon, AGDC, could help you with. Thank you. Senator Keele. Thank you, Mr. Chairman. I think it will be important to get an understanding of how close we are and where we are in the process in talking with them so that we understand the level of urgency, the level of preparation.

Thank you, Senator Keele. Further questions? Senator Kaufman. Thank you. A lot of great questions, a lot of great points, cost of capital and, you know, community impact, all of these things.

I'm just wondering if we could consider getting some sort of matrix of all of these concerns. There's a great deal of public interest in this process. I get emails pro and con. Some people, you know, are characterizing this thing is a big trap. Other people are characterizing it as an opportunity that if we don't get it right and don't get it done here, that we're going to really impact the future of the state.

I think potentially both are right. If we do it wrong, it won't be good. But if we do the right thing and we can figure it out and make it happen, it's a great thing. But I think it would be good— we have really limited time left. We have, you know, I see about 20 days of official effective time left in the special session.

And we've got to methodically work through these things. I think we should be approaching it a bit more that way. And I know we've all done this, so we've got an idea in our head where we're going. But I mean, as a team, and also for the folks at home, we should, I feel, start each one of these committee hearings with kind of a dashboard of, hey, here's where we're at. Here's the critical things that we need to get sorted out, this is what we need to work on, this is the information we need, and then it's kind of a go or no-go on each one of these things.

If we— if there's critical information we don't have and we can't make a decision, I think we need to make it apparent for the table, for the folks that are going to interface with us as subject matter experts coming in, of the pieces that we have, what we don't have, and just tabulate it, and as we start the day, hey, this is what we're working on to get this critical information, and if we can get there, if we can be informed to make a good decision, then we'll be able to do that before the session's out. So I think the magnitude of this and the timeline that we're on, I think maybe it requires a structured and publicly clear process of what we're what we're doing and where we're going with it. It's just a— I'm just trying to give a helpful suggestion on how to chew on this volume of data and the many questions that we have. Thank you, Senator Kaufman. Further comments from Senate Finance members?

Maybe we could talk a little later, Senator Kaufman. Please proceed. Thank you, Chair Holcomb.

So one of the features which has been debated quite a bit over the last, well, several years really, is the time needed to move from, well, through the chart that I had on the previous slide.

And it would be true to say that where the economic case for a project is so compelling, it is possible to sort of circumvent or sidestep some of the features which we talked about in the last project, so in the last slide. So, you know, for example, if you don't have a, you know, a signed sale and purchase agreement or if you, you know, aren't quite ready with your EPC estimates, if you have sufficient confidence that the project is going to be very accretive, then sometimes companies will take the plunge and move forward earlier. I've never seen this happen with an LNG project because typically, you know, as I've said a couple of times, the hardest thing with these projects is to get to FID with everything lined up. So LNG projects, unfortunately, typically have to follow this very granular step-by-step process. But there's things that you can do to ensure that that journey is a smooth one.

Obviously, as I say, for Alaska, a lot of the regulatory work, the the FERC approvals, the export approvals, things like that which can take quite a long time, they've already been done. And so in that sense, you know, the project is, you know, as far ahead as it can be, really, given where we are. But as we've just been discussing, one of the— well, among the critical factors would be the capital cost and the EPC arrangements. And of course, another one would be what we're talking about today, which is the property tax, which, you know, lenders, equity holders would be looking at in terms of what type of cost burden they might expect.

Questions? Seeing none, please proceed. Thank you, Chief.

So perhaps picking up some of Senator Kaufman's comments, you know, this idea of a decision support package, that is typically a very detailed, robust document which would be typically prepared by the project developer. And then shared with equity holders, and that would in turn typically go up to the board of directors of non-operating companies. They would review that. They would look at the risk assessment around it, and they would use that as a kind of reference in terms of, you know, where things are. So this term decision support package is one that you'll see crop up quite a lot when projects come to FID.

And I think in this context, it would be typical for the host government to certainly have some visibility into that decision support package, you know, in the same way that equity partners would do. So, you know, I'm sure this is something that Glenn Farmer, IGDC, can take you through in terms of where it's at. But it's a valuable document in terms of decision-making. The other factor, coming back to the question of cost estimates, is kind of risk and how it's apportioned. And I think we talked about this a little bit yesterday.

It's quite common, especially after the Australian experiences, it's quite common for LNG developers to push back on the EPC contractors in terms of cost caps and other cost mitigation exercises. With a project of this scale, you know, we're talking billions of dollars, so the extent to which cost risk can be pushed onto an EPC contractor, I think, limited simply because many of these companies, large as they are, their balance sheets simply cannot support, you know, a huge risk of that support.

And then, of course, you know, again, another feature that we've talked about is this question of transparency and engagement and involvement of all the key stakeholders. So these are the things that can assist with the FID and make sure that it's a smooth process. Thank you, Chris.

I did want to pause before we move on to the next section to consider the Phase 1 and Phase 2 nature of the project that we have in front of us. So Phase 1 of the project, as we know, is the building of the gas line. And as we approach FID for that, potentially independent of the rest of the project, it's worth reflecting on what FID would mean to the various stakeholders in the project.

Perhaps the biggest group of stakeholders who, through RCA tariffs and so forth, might be Ultimately, the key to financing the pipeline is the energy ratepayers, both gas and electricity, in Southcentral and potentially Fairbanks and other parts of the interior. So effectively what Phase 1 represents is a potential for very, very significant reductions in energy costs going forward. So whereas the Phase 1 gas line, if it's apportioned across typical rate-paying customers, would represent a significant increase in energy costs, the Phase 2 would represent a significant decrease, possibly less than half what they're paying today. So For South Central and interior ratepayers, the pipeline represents an option. It's by committing to a Phase 1 supply, you're also being given an option on these— on potentially years of lower-cost gas, but it's not definite.

The same concept of an option value applies to Glenfarm and AGDC. I think based on, you know, things which have been shared in public, that there's a perception that once the gas pipeline goes to FID, the risks around the entire project decrease because one significant element of it is dealt with and has become certain. So there's a very significant de-risking of the project. So one way of looking at that is that the opportunity to deploy a further $40 billion or more capital in terms of liquefaction, the gas treatment, becomes a more certain outcome. So in terms of option value, FID on the pipeline has a kind of a financial or commercial value to AGDC and Glenfarm because it de-risks the rest of the project.

So the other main stakeholder involved in that Phase 1 gas line, of course, is the upstream producers. Now they may only be providing, you know, a few hundred million standard cubic feet per day of gas to Southcentral and Fairbanks, and in financial terms it's probably the— broadly the equivalent of of another fuel demand up on the slope. It's of similar order of magnitude. But of course, the big prize for them is the 3 BCF a day that they'd be selling to the LNG project. So, you know, 3 BCF a day at $1.50 in MMBtu, that's about $1.5 billion a year in revenue.

So for them, even though they're not necessarily present in the discussion around the Phase 1 gas line. For them, FID on that gas pipeline brings that $1.5 billion per annum that little bit closer. So as you, as you think more sort of holistically then about the Phase 1 pipeline, you've got these 3 separate stakeholders. You've got customers, you've got Glenfarm and AGDC, and you've got the upstream producers, each of which gains quite significantly from the option represented by that pipeline. So the final thing to add is that, you know, we were talking about the banks and the lenders and so forth, and, you know, that pipeline would represent probably less than $10 billion, but nevertheless several billion dollars of lending.

And the, the thing that those lenders would probably look at in, in and, and give most scrutiny to as they think about lending that money is the nature of that tariff. You know, what does that tariff look like between the upstream producers and, you know, utilities like Enstar or Chugach? And is that tariff robust enough to support debt service on that loan for 10, 20 years to come. So in that sense, the determination that the RCA make and how that tariff is, is comprised and how long it lasts, that will be the foundation for any lending that happens on that pipeline if it's done separately from the LNG So that tariff and the degree to which these other option features are looked at and whether or not they translate into financial support, that will all be looked at.

Question is by Senator Steadman. Thank you, Mr. Chairman. I think the Finance Committee wants to look at that.

We know the rough volume in the rail belt that they consume, about 250. Maybe they go to 500. There's some estimates that they can get to 500. What does the— you know, what is the debt service cost semi-annually or annually if you want to work annual numbers? Annually.

And where does that leave the project? Also with some numeric for operations. You got to pay the people that run the system. And what is the debt service coverage ratio? We should have that number on the table.

And I think some of the other committees have used a number of about $12 billion for the in-state gas line, not $10 billion. So that's, you know, a significant increase right there. And then 20-year government bonds plus 3/8 is roughly 5.5 for your interest rate. We should be able to get a ballpark number of the, of coverage, how much room that is. Do we need the Donnellan mine up and going to make that debt service payment, which is a presentation we had here several weeks ago?

And what other expansions need to be take place in the rail belt to get from 250 to 500 on the consumption?

So can we, Mr. Chairman, have somebody cook those up? If it's our consultant or if it's Department of Revenue, somebody should be putting those numbers in front of us. We could have that debate after this meeting. I mean, discussion. Further questions?

Senator Keehl. Well, thank you, Mr. Chairman. On exactly that topic, there's an ultimate cap on on what that tariff can be and it's imported LNG. Because the RCA is only ever gonna approve what's reasonable and necessary. And if, you know, the cost overrun example on slide 4 today were to hit an in-state 42-inch pipe with only in-state consumers, I worry that we have a half-built project and no chance of an approved tariff that could pay for the cost overruns.

And then I think I have a guess as to where the money comes from. That's going to be a problem. So it's a— with the smaller volumes, I think, comes a much, much smaller pool of those who can take that risk. And I'm very concerned about the earnings reserve on the permanent fund at that point. Am I missing a big risk taker?

Is there insurance you can buy for that? Thank you, Senator Kyl, and through the, through the chair. Well, perhaps the first part of your question around the cap being the cost of imported LNG.

Thinking back to one of the slides we looked at yesterday, looking at what that tariff would need to be for these smaller volumes of gas, right there you've got a number which is higher than the cost of imported LNG. So, so one of the questions, and, and I'm sure something that'll be deliberated over by the ICA, is how that price ceiling— call it what you will, using your terms— how that can be accommodated with a pipeline whose cost is that, that bit higher. And so as we look at this slide we have in front of us, um, you think, well, where, where might an additional financial contribution come from to either address risk or to bring the gas tariff to consumers down to a level that's comparable to imported LNG. Um, that— there's a range of ways you could do that, but it would involve financial contributions from other than South Central customers and, and customers in Fairbanks. So I think one of the things that's worth looking at is how the RCA tariff-setting mechanism is configured today, and whether there are other features which might need to be introduced to take in some of these broader, more strategic questions around tariff setting which are unique to this Phase 1 project, but typically probably not part of the usual RCA mandate.

Senator Kyl.

I take it there's not insurance you can buy for that.

Thank you, Senator Kiel. Further questions of the committee on this slide? Seeing none, please proceed.

Thank you, Chair Hoffman.

So one of the questions that has come up as well is, you know, in terms of the sort of project development activities which are going on currently, even led by Glenfarm, How does this work into a kind of viable business model? And, you know, at what stage in the project does value accrue? How does this work? Now, obviously I have no insight at all into the commercial arrangements that Glenfarm are operating under, so my comments in the next few slides, they're more generic in terms of how a project developer would would function. But nevertheless, it might provide some insights in terms of, you know, where value could accrue.

So it's worth— it's worth taking a step back and thinking, well, what is it that a project developer is doing? And the sort of headline term to describe all these factors would be de-risking. So the, the whole objective is to use a number of levers to turn a project into something, from something that's just an idea on a piece of paper, although obviously the starting point with AKLNG was much more than that, and, and turning into something where perhaps other entities would see value to the point where they're willing to invest. So a number of ways in which that is done we've talked about in the previous slides. So the completion of the front-end engineering design, it reduces cost uncertainty and it enables the project to present itself as an economically attractive investment.

As opposed to an idea. So at that point, you've created something that other people will pay to be part of, and that process of equity participation, you know, can happen from the very earliest days right through to a project that's operating where an interest is being sold down. Um, so other elements of de-risking, which again we've seen a lot of evidence of in the press, is creating an anchor demand through LNG customers interested. That number of, um, certainly world-class companies that have shown an interest in, in Alaska LNG and have indicated their interest through a letter of intent or sometimes something a little bit more significant.

The other element, of course, is the gas supply, which certainly has been discussed. And then a key point, which we talked about quite a lot today, is arranging debt. So setting out a robust banking consortium who are willing to step up and provide capital. So all these things take the project to a point where there's enough confidence and belief in it that it becomes an attractive investment for other people.

So moving on to perhaps a more granular level, typical in any kind of project development of this sort is the ability to capitalize development fees. So in terms of anyone additional coming into the project, those capitalized fees would represent an asset that they're buying, and that, you know, as, as additional equity is sold, that the value of that capitalized cost would be recognized in the value of the shares. And would be recouped by, by the developer. So the more equity that's sold, the more revenue that comes back, and obviously the more de-risked the project is right up to the point where it's operating, that the higher the value of that equity. But, but even today, given the development activities and the de-risking that's happened over the last year, already tangible value would be attached to that shareholding.

And certainly from what's been said publicly, I think Glenfarm are actively talking to various strategic partners who may then subsequently take equity in the project. The, you know, I think just summarizing the last few slides, obviously at each point you're at with that development cycle, the lower the risk and the higher the value. So for example, once you're approaching FID, then, you know, the potential value to a counterparty will reach a significant level. And for LNG projects, often you will see, you know, changes or exchanges in equity leading right up to, to FID. So LNG Canada, for example, uh, KOGAS, a Korean gas corporation, they sold down part of their equity.

And Petronas from Malaysia, who had been developing a competing project some years earlier, they, they in turn took additional equity. So right at the last point up to FID, there was that kind of rearrangement of equity and reflecting the value in the project. So the, the other, the other area of value for a project developer or operator can be some of these adjacent features. For example, management fees around the EPC, operational and maintenance fees for becoming an operator. LNG marketing fees would be another area where there could be revenue.

Chartering vessels, and of course gas, gas production and gas aggregation. So these are the sort of areas where a developer or an operator can enhance the fundamental value of the project by providing these other services. So as I say, this is kind of illustrative. It's, you know, how a typical LNG or gas project would work. Obviously Glen Farn, I'm sure, could set this out in more detail.

Mr. Fulford, can you expand on your second bullet point on shared by AGDC?

So obviously, certainly my understanding of what's been said publicly and from the presentations that AGDC have made, whilst Glen Farn are carrying out the— and funding the, the development costs for the project through their interest in 8Star. I believe AGDC have a right to kind of share in that value generation that's created by Glenfarm's activities as, as the project is de-risked and the value of the equity increases. Uh, so in terms of the project structure, which has been described by AGDC of the, the 8-star holding company with the sub-projects, arguably that value uplift that's mentioned in bullet 2 there is something that would accrue value at the 8-star holding company level as opposed to the sub-project level. So, um, so, so that I think is something that would reflect on, on AGDC as, as the value of the project increases. Further questions?

Senator Steadman. I think we need more elaboration on that. You want to try that again so people at home can understand what you're talking about? Because some of us are concerned 8 Star Gold is nothing but a shell company and there'll be no revenue of any significance ending up there.

Thank you, Senator, and I'll try and be a little clearer in my response through the chair.

The, the project is made up of these three very substantial modules: the treatment plant, pipeline, and the liquefaction.

At the point that FID is reached on those 3 modules, billions of dollars of capital will be deployed in each of those 3 sub-companies. So at that point, um, I think 8Star is exactly that. It's a holding company, um, and the, the degree of dividend that goes from those project companies back up into 8Star, I think, could be relatively low order of magnitude, because ultimately it'll be the investors in those sub-projects that will want their revenue corresponding. However, um, as, as the project gains momentum and, um, the rights to invest in those sub-projects emerge. And again, I think AGDC would be a better place to answer this than me, but I believe the sort of fundamental uplift in equity in the broader LNG project would be reflected in that holding company.

So in terms of orders of magnitude, that at this point, this early point in the project, where, you know, it's unlikely, I think, that a counterparty would pay a significant premium to acquire those shares. But I think whatever premium they do pay may reside in that top-level 8-star company. But as I say, I think the thing to bear in mind is that the underlying value of the project will reside in those 3 subprojects. Subcompanies, and the value that we're talking about residing in the holding company through selling down shares could be relatively low order of magnitude. Andrew Steadman.

Yeah, I mean, so just assume it's $60 billion, and at 70/30, that's $18 billion in equity. Somebody's got to put down $18 billion in cash. I would expect the guy that comes to the table with $18 billion, the guy with the gold makes the golden rules, is going to want a significant majority of the equity position or he won't put his $18 billion on the table, he'll go somewhere else. Therein lies a dilution problem or a challenge. So I think at some point we need to have that discussion with AGDC.

And Glenfarm, the whole dilution mechanism. Because I don't— it would— I'd be shocked if somebody puts down $18 billion and doesn't demand a significant equity position, if not virtually all of it. Because without the $18 billion, nothing gets built. And Glenfarm doesn't have it anywhere close.

Thank you, Senator Steadman. I think through the chair, These are questions which I think are best addressed to Glenfarm, but if you, if you look at other LNG projects of a similar nature, then yes, those counterparties who come in with equity and cash would typically take a very large chunk of it. Typically they would be LNG buyers, for example, and it wouldn't be unusual, you know, obviously there are a number of world-class LNG buyers who've shown an interest, but, you know, let's pick one just as an example. It could be JERA, you know, the biggest LNG buyer in Japan. They have a track record of investing in the projects from, from which they procure gas.

So if If they were to take, for example, 2 million tonnes, then it would be natural to see them take a 10% interest in the project equity and contribute a corresponding amount of capital, and same with the others. So in effect, that 75% that is with Glenfarm today could become a much smaller number.

Like, significantly smaller, not relatively smaller, virtually evaporate, and they would still have huge cash flow coming in for their amount that they have invested in this project from what it— how it appears. It would take very small percentage of equity to have significant cash flow coming And the issue I think that we'll be faced with at some point is a discussion on the state's position being diluted. And the only way you can keep it from being diluted is pony up your portion of the cash, generally speaking.

Thank you, Senator. I think the only comment I would make on that is that, you know, given what we talked about the last couple of days in terms of property tax and so forth, the likeliest avenue to significant state revenues from this project are going to be through equity participation at an appropriate level.

And that will require a whole different debate around diligence and so forth. But the equity participation is probably where the value of this project is going to be for the state, if it so chooses to invest. Senator Steadman. No, I think that's a coming discussion on if we invest in this project or do we take our money and invest in an existing pipeline. That's already been de-risked.

I mean, we're not an investment company, we're a state. So anyway, that'll be future discussions later on.

But it is our gas. Yes.

Do we have— do you have any additional presentation on this slide? I just— I think that is the last slide. Thank you. Take a brief release.

Further questions of our presenter? This—. If not, this does conclude this morning's meeting.

We have our next meeting is two Tomorrow morning, May 29th at 9:00 AM, we will have a presentation from the Department of Revenue to present the tax structure in Alaska. Any closing comments, Mr. Fulford? No, thank you again. Appreciate the opportunity to discuss this important project and hopefully assist the committee in their decision-making. With that, we are adjourned.