Senate Resources, 5/7/26, 9am

I call Senate Resources Committee meeting to order. Today is Thursday, May 7th, 2026, and the time is 9:00 a.m. Please turn off your cell phones. Committee members present today: Senator Kawasaki, Senator Dunbar, Senator Myers, Vice Chair Senator Wielekowski, and I'm Senator Giesel. We have a quorum to conduct business.

Thank you to Heather and Chloe who are helping us out with records today. And we are hearing again, uh, Senate Bill 280, Supporting a Gas Line for Alaskans Act. Today we have one item on our agenda, and that is hearing from our consultant Nick Fulford. He is the senior director Gas, LNG, and Energy Transition, Gaffney Klein. And no, no one else is online right now from the Tax Division.

Welcome, Senator Rauscher and Senator Clayman. So welcome, Mr. Fulford. Thanks for joining us today. And you have prepared some slides related to some questions that we've had. So welcome.

I'll let you go through your presentation. Thank you, Chair Giesel. For the record, this is Nick Fulford from Gaffney Klein, and just checking that you can hear me fine. Yes, very well, thank you. Excellent.

Well, good morning, committee. Really, 3 topics to cover today, and if we go to slide 3, that sets out today's agenda. So really, the purpose of today's materials is to address and expand on some of the core questions that have come up over the last many hearings. And perhaps provide some context and some additional guidance that the committee can use in furthering the bill. So really, these divide into three.

The first relates to a constant theme which has been raised in some fashion or another really for several months now, which is the requirement really for the legislature to have some appropriate degree of insight and transparency into the project to enable an objective discussion around fiscal terms.

The second relates to the gas supply arrangements. The way I would characterize this— this part of the discussion is that we've had a lot of discussion about the capital cost of the plant and understanding what that might be. One of the other features, of course, which has a fundamental effect on the economic rent within the midstream is how the arrangements with the upstream function. The other thing which makes this a highly relevant discussion is that, of course, the tax rates applying to the midstream through corporate income tax and potentially the volumetric tax compared to the— currently the gross tax upstream for the gas These are very different tax frameworks and as you move economic rent from the midstream to the upstream, there are significant tax consequences for the state. The third item I wanted to cover relates to some of the questions which have come up about, well, you know, how do other projects sell their gas?

What price could we expect? What might be the terms? So I've prepared a couple of slides on really how LNG is traded, the pricing arrangements, and try to put this into context of Alaska, the volumetric tax, and, and some of the competing supply sources. Uh, so with that, I'll move directly to slide 4 and, uh, we'll address the question of disclosure. So, um, before getting into how disclosure might happen, uh, it's worth looking at this project and considering the differences between this project and the former one for which, uh, SB 138 provided the guiding principles.

The—. One of the huge benefits of the SB138 project, if I can call it that, is that it was a completely internally managed project. That is to say, the, the 3 main corporate sponsors were producing the gas, they were equity investors in the midstream, and they were effectively going to buy the LNG at the, at the marine terminal. And, and add it to their existing portfolios.

Exactly what the state would have done in terms of LNG marketing is— never was decided, but that's, that's not, I think, a major factor. The difference we have today is that there are 3 key interfaces currently unresolved for which this type of commercial data, capital costs and so forth is highly sensitive and highly relevant to the negotiations. One of them we'll talk about a little bit more in a moment, which is the interaction between the midstream project sponsors and the upstream gas providers. So in that negotiation, the degree of economic rent that the midstream can support is highly highly critical information, and things like the capital cost of the project will be very, very helpful to a counterparty in terms of how that negotiation was conducted.

The second one, of course, is in terms of the LNG sales. I would say here, as we'll hear later on in the presentation, LNG market prices are give or take reasonably set. There are always competing supply sources of LNG and therefore it's difficult to depart too much. You know, within reason you can negotiate a higher or lower price, but broadly speaking, you know, you kind of know what the range is. But even with that, understanding the project economics can sway a negotiation.

And then of course the third element relates to equity investment. At the moment Glenfarm are the primary equity investor. I think we've heard in testimony this week, last week, that they are looking for equity investors elsewhere, other people to join the project and, and be part of it. And that's another area of course where Understanding the economic rent, knowing what an investment in AKLNG might look like is key. So bottom line, unlike SB138 where everything was kind of self-contained and therefore there was a relatively open and transparent dialogue on capital, and I think certainly yourself, Chair Giesel, and Senator Wodakowski, you'll remember that dialogue.

About 10, 12 years ago. So unlike that project, with this one, as I say, there are 3 key negotiations going on right now where things like the capital cost and other details are highly sensitive to the negotiation. So that said, clearly again, everything you read about best practice and —fiscal management—suggests that particularly in such a resource-based economy like Alaska's, and then you layer on the constitutional obligation that your committee has, clearly there's a requirement in terms of good practice to know and understand the broad economic framework around the project that you're seeking to set taxes on. So, I think with the sort of preamble, with the differences in the project, but with this ongoing requirement that the legislature has to understand and tax appropriately, you are left with the problem of, well, how do you conduct that exchange of information in a way which keeps it suitably ring-fenced and keeps it out of the public domain, but nevertheless gives the legislature and this committee enough understanding to make a sensible determination on costs— on taxes, I should say. So as you look at how that's done, often, you know, I've talked about some of the other mechanisms around the world, some of the other projects where this —this determination of economics is a very lively and very sort of actively discussed feature.

It's done in a number of ways. Sometimes the best conduit for doing that is through a national oil company or national gas company. Obviously here in Alaska you have AGDC who play a role, but, you know, the role that's defined for them isn't quite the same. As some of those other national gas company examples. There are also lessons from mergers and acquisitions in large transactions where, for whatever reason, some degree of understanding is required short of full disclosure.

So, some interesting examples: International Monetary Fund, they have a a formal framework. It's called the Fiscal Analysis of Resource Industries. It's been used in LNG, was used for Senegal, I think it was used for Mozambique to enable an understanding of depreciation features.

But obviously it's, you know, the sort of experience and knowledge here is already kind of a thing. Well, well advanced from that.

The usual, if I can call it a usual solution, is to try and establish a core team of individuals, sometimes quite small, made up of subject matter experts from a number of agencies. In Alaska, for example, it could be DOR, DNR, Department of Law perhaps, Often there's some kind of external facilitation that happens, but ultimately the key challenge, and I think one that the committee is probably worth spending some time on, is to establish, well, what would that team look like such that trusted advice and an appropriate level of— inspection and audit can take place and be passed back to the legislature in a way that the legislature feels it's being properly instructed. So other than pointing out some of the ways in which this is done, the word clean team you'll hear sometimes referred to as this group that broker the information.

But I think, you know, in the context of Alaska Department of Law, looking at your own sort of constitutional requirements and how you might work those into a more ring-fenced transfer of data, that might be well worth doing. But I'll pause there for any questions. Any questions? Senator Myers. Yeah, thank you, Madam Chair.

Mr. Fulford, that clean team that you mentioned, You said that you've been having some conversations with Mr. Stickel and maybe a couple others over at Department of Revenue, and they've got a team over there that's been examining it and then filtering some of that information to us to the extent that you can kind of— I don't know if depersonalize is quite the right word, but generalize it. Is that at or close to how you envision, how you have seen these clean teams work in other jurisdictions?

Thank you, Senator Myers, through the Chair. I think, given— first of all, given the advanced level of model that exists and that's well understood by Mr. Stickell and his team, that would seem an excellent starting point. Just a word about the modeling too.

Very, very important that you sort of think about modeling in two buckets. You know, one is the maths, the maths of the model, and that's the area where I've been, you know, discussing back and forth with, with DOR to make sure that the model itself is appropriate for the LNG project. The other feature, of course, is the assumptions, and that's the area where different assumptions can be used to generate different results. So auditing those assumptions, making sure that they're appropriate is probably certainly as important if not more than the math. So I just wanted to make that point.

But yes, I think that the model hosted by DOR with appropriate inputs and appropriately presented to the legislature I think could be an excellent starting point.

Senator Kawasaki. So thank you, Mr. Fulford, for being online. And as a contractor for the committee and for the legislature, I guess the next question is, if it's a good starting point, what's next? You know, we kind of assume that you've got some greater experience than, um, Mr. Stickel, who's our chief economist, knows a lot of stuff. But you're the guy who we sort of depend on for expertise when it comes to LNG.

And so our— I guess, are the key assumptions, do they seem within the ballpark? Are they off? What sort of advice have you given the department so that they can sort of scrub their numbers? And then does the math calculate out based on those assumptions?

Thank you, Senator Kawasaki. Through the Chair, first of all, it's kind of early days in a way. I would say that the detailed dialogue with DOR really started maybe a week, 10 days ago, mainly to iron out where we were with corporate income tax and so forth. There are a couple of assumptions used to generate, for example, the breakeven matrix that you have seen, somewhat different depreciation methodology, so that might be a sensitivity to look at.

The cost of debt, I think, you know, if there is indeed federal support for loan guarantees, I think the cost of debt being used is probably fairly accurate. If that doesn't happen, maybe a higher cost of debt should be used.

So there are features like that. Those are just two examples where, you know, delving into those assumptions and perhaps looking at sensitivities would be appropriate.

Follow-up, Senator Kowalski. Thank you. I'll just say that You mentioned that we are just in the early days of this.

I mean, we just saw the press conference yesterday. We are in day 108, 109 of a 120-day session. So we as resources are sort of— I mean, I will speak for myself, a little stressed that I don't have this information yet, but I am supposed to make these multibillion-dollar decisions with a 30-year horizon, time horizon, within the next week because we have to pass this on to the next committee or referral. And are there things that you can do to speed up the information gathering or information analysis? Because these are things that I feel like we need before we can move on a bill of this magnitude.

Thank you, Senator Kawasaki. Through the Chair, obviously, you know, we're here to help the committee as we're able to.

I would say, you know, some of these modeling and assumption features are, you know, they can be quite challenging to make sure they got right. But I would refer back to my previous dialogue. I think that, you know, one of the core assumptions— well, there are two core assumptions with that model which enable you to establish whether the project can support an ABT at all or indeed what level it would be. One is the capital cost of the project. The other is the price of the gas.

So, so within those constraints, we can look at sensitivities and other features like depreciation and cost of debt. But ultimately, you know, one could produce an estimate of the economic rent in the midstream and you could use a low capital cost, a high capital cost, which is effectively what that DOR heat map does. Um, but until some of these other features are resolved, it's hard to provide guidance, I think.

Senator Wilkowski. Thank you. It's such an odd and uncomfortable position that I feel we're in, where it feels like the governor is almost doing the bidding of Glenfarm. And AGDC is right there along with them. And it— I understand this is a negotiation process and we have a constitutional obligation to get the maximum value for the resource.

And it feels like we're trying to do that on our side and yet the governor is berating us and his revenue department is completely hollowed out and is having a challenge getting us the information. But, you know, governor threatening us.

It's just such an odd situation that I find that I think I feel like we're in. His own department is providing different numbers than he's saying publicly. He's saying gas is $4.50 and his own department is saying no, it's actually Phase 1, $22.96, probably best case scenario. And I guess the challenge that I have is what additional information do you believe the legislature needs to follow our constitutional obligation?

Thank you, Senator Wielechowski, through the chair. Obviously there's a lot in that question.

One of the other features that I was planning to get onto on the next slide is the question of the upstream price because, you know, arguably that's another feature which is quite relevant to the committee's deliberations but is not yet fixed. I think— I suppose that there's a number of dynamics going on here, but dynamic one is that for the last 10, 12 years, it's been widely understood that the current property tax framework is inappropriate and ill-fitting with an LNG project of this scale. So putting in place something which is a more manageable and appropriate way to tax the project, you know, clearly that's something which could be considered.

The other factor is the rate at which a tax is set. Under the current committee substitute, you know, I would say that's a relatively high tax and one which may not be supportable by the project. I think the numbers suggest that.

But, you know, the problem for the committee is exactly what that tax should be to create that appropriate balance of private investor and government take. At the end of the day, the legislature can change tax rates. And again, if you look at the LNG Canada experience, they, they, they put a special LNG project tax on the project. They put a carbon tax on the project. And in the end, they repealed both of those.

They replaced the carbon tax with something different. And then they introduced a natural gas credit.

So in that example, they weren't able to set exactly the right tax on effectively day one or even day 101. There was an incremental iteration of legislation which finally got to a formula that enabled that project to go ahead in combination with the federal government. And in a way, we're at that same— you know, we're on that same journey here, that pinning the tax down at this stage is a challenge, but setting a better tax framework for the project is something that could be done potentially. Follow-up. Yeah.

Do you think—. We've heard from the Department of Revenue that the internal rate of return for the producers, Slope Wide, including Point Thompson, for, for their gases is 83%. Do you think it's unfair for us to say as a state, we'll, we'll chip in, we'll reduce property taxes a certain level, we'll have some skin in the game, but the producers, there should be a way to figure out to So maybe that 83% drops down to, I don't know, 50 or 60%. It's still a great rate of return. But to make the project work, everyone sacrifices a little bit.

Do you think that's an unreasonable approach?

Thank you, Senator Wielekowski. And that's more or less the topic for the next slide. I don't know if it's appropriate to move to that at this point, or I can just address the question. Let me pause for a moment. Are there more questions on this slide?

Senator Myers does have another question on this slide. Mr. Fulford. Thank you, Madam Chair. So, Mr. Fulford, timing has come up quite a bit in the conversation here.

And, you know, of course we've got our kind of artificial deadline of the end of session coming up here in a couple weeks.

But, uh, you know, we've also talked about how market conditions have been rapidly changing, particularly since the Iran War got started and, and the like. Is it relatively common among large-scale projects like this to need to get something done relatively rapidly because of market conditions, because you're worried if you come back the following year that you're going to lose either lose momentum or somebody else is going to come in and undercut you.

Is that a common problem?

Thank you, Senator Myers. Through the chair, it's an extremely common problem, and in LNG projects, there almost has to be a kind of momentum and a constant pressure. To meet the next deadline because they are so big and so complex that if you don't have that drive and push towards making progress, reaching the next hurdle, it's, it's very, very easy for projects to just lose momentum. And, and you've seen that happen before in Alaska. So, so there's constant tension about timing and needing to get stuff done is ever-present.

It's a feature. And, you know, Glenfarm, arguably they're doing a great job in terms of providing that momentum and pushing the project forward. But ultimately there are other constraints, some political, some commercial, some physical, which create these delays. And permitting, obviously, is another one. Okay, thank you.

Senator Kawasaki, on this slide. Thank you. Uh, yeah, you mentioned, um, FID and pre-FID, and one of the big deadlines that we had talked about a year ago to this date almost was that they would have FID on the pipeline portion of the project by December 2025. And then they were— and session began in January We had the governor spoke to it too in his press conference, or in his State of the State address, and Glen Farn was there, president, saying that it's gonna be pushed off a little bit to March. And then now we're in May, and isn't, I mean, I'm, you know, just if I'm really skeptical about a pipeline actually happening, Wouldn't I point to that as something a skeptic would point to, I guess?

'Cause again, it was a promise that we would have that. And I guess I would be very comfortable if I heard that we've got an FID on the pipeline and then we made these pronouncements on the tax subsidies. So I'm a little bit less so today just because again, we've already slipped deadlines for the last half a year.

Uh, yes, thank you, Senator Kawasaki, through the chair.

Again, it's, it's worth mentioning that, um, this project that we're talking about today, it's probably the biggest, most complex gas infrastructure project in the entire world, and As I mentioned, I think it's important that there's a momentum and a sort of progression of the project that is visible to see. But understandably, major decision points like FID on the pipeline, they take a lot of work to bring together.

It, it's not surprising in many ways that even in spite of the momentum and the work and the effort that everyone's doing, that, that potentially we're not quite there yet. Um, I, you know, again, just to emphasize what a, what a big and complex project this is, an LNG project just on its own would be a challenge. If when you factor in the gas shortages in the state You know, that's yet another feature which adds complication and also makes it that bit more important that some kind of gas supply arrangement is put in place.

So in short, I don't think anyone would be very surprised that there's some slippage in FID. I think the key thing is to examine the kind of momentum in the project and check that that's continuing to receive appropriate attention.

All right. I see no further questions on this slide, so I think we are ready to move to slide 5 and Senator Wielekowski's question.

I'll pass. Pardon? Okay. Pause for one moment, Mr. Fulford. I'll pass.

Senator Wielekowski. Okay. All right. Go ahead on to slide 5, please.

Okay. Thank you, Chair Giesel. And I think this slide sort of speaks to Senator Wielechowski's question because, you know, what you're left with is a decision around, well, you know, who pays the tax on the project because, as I mentioned before and we'll talk about a little bit, it's not as if you can charge more for the LNG. So if the project— let's say that the project is exactly economically viable without a tax, then if you impose a tax on the project, the question is, well, you know, where does that funding come from? And in this example, you know, because we have this interface between the upstream and the midstream, The answer is it can come from two places.

It could come from the LNG investors, in which case the rate of return in the project would drop, and then you have the questions about whether it's investable or not. But ultimately, it can come from the upstream gas producers as well. And as you think about the volumetric tax, okay, the tax is related to the pipeline, the processing plant, the liquefaction. But equally, if you look at the upstream, really the only reason that that gas would be flowing is because it's being sold to the LNG project. There's no— realistically, there are very few other alternatives for monetizing that gas.

So in a way, you can view that those upstream contracts as being just as firmly linked with the LNG project as, you know, the pipeline tariffs, the liquefaction, and so forth. So in asking yourself, well, where will the funding for that AVT come from? It could come from the midstream, it could come from the upstream. Not that I'm advocating that, but in terms of where the economic rent is, if there's more economic rent in the upstream than there is in the midstream, then that might be the place to look for additional revenue.

So, so, you know, with that, it's useful to come back to this other question that the cash, the way the cash flows is, is represented by those arrows. So first of all, you know, the, the LNG is sold and the cash is collected. It then flows— depending on the project structure, it then flows through the midstream to collect appropriate returns, and then from there it goes up to the gas producers. So at the moment, I would imagine the gas producers are looking at the project and determining how much economic rent is required. They're all well, certainly two of them are very, very experienced LNG players.

They have vast knowledge of the market and how the economics would work. So at the moment they'll be assessing, you know, how much economic rent there is in the whole system from the LNG revenues right back to the wellhead. So I made the point at the start, we talked a lot about the capital cost of the project, but we haven't really talked a lot about where that gas cost will be fixed and how much economic rent is in the midstream versus the upstream.

So that's a kind of a start to, I think, the answer to Senator Wielechowski.

I see no questions on this. Oh, Senator Clayman has a question. Thank you. It's probably partly this slide and the prior slide. It's just a matter of economic dynamics.

Because the price of gas and oil has been up as a product of the, the war in the Middle East. Does that higher price make this a project more appealing to investors or less appealing because of the higher price? And part of my query is that the higher price may mean marginal fields that are smaller and have less risks involved may become more appealing. But I'm curious your perspective on what the higher price does to investors' interest in this project.

Yeah. Thank you, Senator Clemon. Through the chair, LNG is, is such a long-term business that these are 20, 30, 40-year projects and fluctuations in price such as the one we're seeing now. It creates a flurry of activity. There are governments in Asia in particular who are rewriting their entire LNG procurement strategies because, because of what's happened.

And, and obviously there is this medium-term price impact which, which we're not sure what will happen. But I think, you know, for more marginal LNG projects right now, the economics of those marginal projects might look very good. But I think, you know, lenders, investors, they all know that give it a year or two, those economics will fall away again.

I think, you know, your question is not specifically directed at this, but while we're talking about the midstream and upstream, the other factor which I've shown on previous slides is how that contract is structured. At the moment we're just talking numbers, you know, $1, $1.50, $2. But inevitably that price will have probably quite complex indexation linked to it.

It could be entirely linked to the LNG price. It could be partially linked to it, or it could have some kind of inflationary factor to it. But that's another nuance in detail which is fundamental to the fiscal picture but hasn't really been talked about yet.

Follow-up? And then related, it continually strikes me that the analysis you're attempting to do for us is hamstrung and almost impossible without meaningful data. You know, without actually knowing the price of the project, without— and nobody will tell us the price of the project. And questions that you've raised today about what's the price of the resource at the top, you know, what price is it selling for before it starts its way down the chain. Let's turn this slightly, and we're no longer the state of Alaska, but we're a major lending institution.

Would the major lending institution, without nondisclosure agreements and without a full exploration of the— all the details that we don't get to see as members of the legislature, would that major lending institution have anything to do with this project without full access to the stuff that we don't get to see? Or would that lending institution say, we're not going to lend until you actually disclose the information that you're specifically not going to give to the legislature?

Thank you, Senator Clayman. Through the chair, the, the way these LNG projects come together is, is iterative, as I've mentioned. And I have no idea where Glenfarm are with their discussions with lenders, but obviously that'll be a key part of what they're doing at the moment. And typically the first thing you do is to get maybe one or two globally, you know, globally known lead banks to start to show an interest in the project.

And for them to assess whether they should put the effort and the resources into doing that evaluation, some degree of understanding of project economics would be required. As you move towards FID, the degree of due diligence that would be carried out by those lead banks and in fact by the other lending institutions would be orders of magnitude more than what you would consider even appropriate for government. So they would go over every feature of that project with a fine-tooth comb, including the gas contracts, the gas resource. The engineering contracts, really everything to do with the project would be looked at in immense detail.

Thank you. Senator Wilkowski. Yeah, thank you, Mr. Fulford. We haven't had a whole lot of discussion on the upstream side, but that is certainly where a large portion of our value from this project exists. How confident are you that we've protected ourselves on the upstream side?

In other words, there's some concern that you could value gas at a small amount on the North Slope, maybe 25 cents, and then pick it up at the end of the pipeline after paying the tariff and maybe sort of pay a lower production tax, lower royalty. And I don't know if you've looked into this or not, maybe it's DOR is the one, but how confident are you that we've protected ourselves on the upstream side? What, again, and I'll just tell you what my hope is, is that if gas sells for $1.50 on the North Slope, we get $1.50 in royalties and worth, and a dollar at, you know, 12.5% royalty and a 13% gross tax. Are we doing that or is there a way that you can envision us you know, via netbacks or tailgates or something that maybe we wouldn't capture the value that we're expecting?

Thank you, Senator Wielechowski. Through the Chair, I think there's two elements to that question. First is the question of audit and fair market value. The Australian government, for example, felt that they were at risk because of the ways in which prices were being set in different parts of the value chain. So they undertook to evaluate exactly, you know, within reasonable bounds, what an arm's length unrelated sales contract might look like at the different stages in the value chain.

And they took action where they felt that prices were being inappropriately set and therefore taxes were being avoided. So exactly which agency would do that and what would be the sort of legal basis for challenging some of those contracts, I don't know. It's certainly quite common because the revenues involved are so vast. Typically it's worth a small team of people to look at it very carefully.

So then the second part of that question comes back to what I was saying a moment ago about indexation and how that price is set.

On the one extreme, you could set a tariff for the treatment pipeline liquefaction which produced a regular 10, 11% return, whatever it is, and you would take that away from the LNG sales price and the upstream producers would get the remainder. So that's That's what would be termed typically a tolling arrangement or something similar to it and is very common in the LNG industry. I don't believe that's what's envisioned here, but, you know, another way would be to say, well, if the LNG sales price is $20, then the upstream producers get $5. It's a straightforward percentage netback. I mean, it's just an example.

That's not a an actual number. So, um, so your question about how royalties and things are set and, and the, the impact on, you know, um, the, the sort of government take, a, a lot has to do with the way that indexation is set and therefore how much of the upside. For example, at the moment, you know, with prices being so high you know, where does that value feed back to? Does it feed back to the midstream or the upstream? And that aspect of the project hasn't really been discussed yet.

I'm sure it's being discussed internally. Follow-up, Senator Wilkowski. Can you— and maybe you don't necessarily have to do it on the spot right here, but can you— we need you to help us protect our state's interest in that regard. And I don't know if it's maybe you in conjunction with Department of Revenue working on protecting the state's interest, protecting the value chain, ensuring that we're getting the maximum value for the resource. I don't want to get in a situation where we do something quick and hurried and all of a sudden we realize, oh, we made a mistake and actually, yeah, they can value the gas at a nickel or 25 cents and then buy it back at you know, pay the tariff and buy it back at the low end, and then all of a sudden we've foregone hundreds of millions of dollars in revenue per year.

That's a big concern that many of us have. So this is where we need your help. This is where we need DOR to help.

Thank you, Wilkowski. Sen. Wilkowski, through the chair, the— probably the best example of of this kind of oversight diligence is what the Australian Tax Office do. Some of that I think has been subject to reports and papers, and that would definitely be an excellent starting point because their concerns are exactly the same as the ones you have just articulated.

Mr. Fulford, the modeling that we are looking at is the sale price of the gas is $1.50, but we also have seen published by Department of Revenue prevailing value on the North Slope for infield use, or use for— yeah, infield, is $3. That's kind of a gap there in the price.

Thank you, Senator Giesel. I would say there are a number of reasons— there could be a number of reasons for that. Ultimately, you know, the cost or the price of gas is the number of therms or BTUs delivered in relation to the operating costs and the capital cost required. So if, if that in-field use of gas, you know, 2 or 3 expensive compressors are needed and some kind of gas cleanup, and if the volumes are relatively low, which they probably are, then that could easily lead to that kind of difference in gas value. So the in-field pricing is probably not a very good guide.

To what the LNG supply contract should look like. Thank you. Further questions? Seeing none, we'll move on to slide 6.

Okay, thank you. So really, slide 6 and the following slide— let me get this up on my screen— we're really an attempt to kind of dig a little bit deeper into some of the questions around, you know, well, you know, what does LNG Canada sell their gas for? You know, are we competitive with that? So two slides really. This first slide deals with what I would describe as the conventional approach to pricing LNG, even right back to the original, um, uh, Nikiski contract with Tokyo Electric back in the '60s.

Crude oil indexation was included in that contract mainly because gas was displacing crude oil in, in, or certainly oil products in Japanese power stations. So it made sense to price the gas accordingly. Um, that pricing convention has remained with us and certainly for Asian buyers, um, other than for US Gulf Coast purchases, which I'll come on to. But for Asian buyers, they continue to have a preference for some degree at least of oil indexation. So, uh, the graph on the top, uh, it gives you a good perspective of how the oil indexation can change.

And it's a feature of a number of things, you know, largely supply and demand. So you can see there that I would say, you know, pre-2010, the almost a standard price for LNG was about 14 or 14.5% delivered to Japan.

Subsequently the gas and oil markets disengaged somewhat. You know, gas started to become its own commodity and that started showing up in some of these changes in oil indexation. So basically you can see there a sort of rough erosion in oil slope. That's the term used for the percentage number that you multiply oil by to arrive at the gas price. You can see a gradual sort of erosion from, you know, 14, 14.5 down to a low point of around 10, 10.5% in about 2021.

A lot of that was to do with, you know, supply and demand and mainly the introduction of US LNG onto the market. So some of those numbers in the tens there, they reflect very low Henry-Hudd numbers and relatively low cost of liquefaction. So to turn that into an actual number, in terms of dollars per million BTU, first of all if we take the upper limit, say 14%, so you'd multiply the price of Brent or the Japanese equivalent by 14% and you'd arrive at a gas price. So the, the top line in red corresponds to the bottom box in red in the chart. So for example, if, if we have a 14% indexation at a price of $50 per barrel, it generates $7 per million BTU, and at a price of $90 a barrel, it generates a price of $12.60.

Similarly, If you take the lower range, which I've taken here as 10.5%, those prices are $5.25 at 50% and $9.45 at 90%. So the question then is, well, where does Alaska sit in that? So what I've done on this graph is I've taken the two breakeven numbers from the DOR heat map the first is the existing property tax, which is shown in the yellow zone, and the second is the 6 cents originally proposed AVT.

And for the purposes of this slide and this analysis, I think you can more or less assume that the yellow zone also corresponds to the volumetric tax number that we have in front of us today, which is the 55 cents So it's, it's about the same. So what you can see in here is that depending on the oil indexation adopted, this shows how competitive Alaska could be in relation to that. So I looked at the last 4 contracts where we know the oil index that was, that was used. And these are really in the last year, well, certainly prior to things in the Middle East, I should say. So they averaged out at 12.4%.

So that you could say that's the kind of current market rate for delivered gas into Asia. And that corresponds to the gray zone. So what you can see on here is that Alaska would be competitive/profitable at a 12.5% oil indexation at around a $65 or $70 oil price.

So this gives you a sense of, you know, how competitive Alaska is. And it's useful to look at this slide because you see it reported very frequently that Alaska's uncompetitive because it's too expensive. Well, again, I would say, you know, the infrastructure is expensive, the gas isn't, and nor is the shipping. So I think on this slide you can see that by and large Alaska has the potential to deliver gas profit— profitably into Asia.

But of course, as you impose additional costs on the project, and these, these use use a $1 input price from the upstream and they also use the base case CAPEX. So you can see that as those turquoise or yellow zones move to the right, then you'll need a higher oil price to be profitable and therefore the potential for the project lessens. So I'll pause there. And, um, take questions. Thank you.

Senator Dunbar. Thank you, Madam Chair. Thank you, Mr. Fulford, for this graph. And I think if I'm interpreting this right, at 10.5%, which is a 12-month average, the breakeven point under the current price structure is about $76 a barrel for oil. You know, if you, if you make the proportionate change, uh, you know, amount of gas, uh, dollar for gas.

And then if we pass the, the, uh, some version of the ABT, um, I'd say the governor's version, it drops to $72 a barrel or $71 to $72 a barrel. And so it's a pretty big chunk, but I look at your assumptions here and in the bottom left it says based on DOR heat map presented to Senate, uh, Resources using $1 upstream price. But that's not the price that we're being told that the producers are going to charge. They're going to charge $1.50. And this gets to a point that Senator Wolkowski has made.

We're talking about somewhere between $0.43 and maybe $0.50 that we can knock off by switching from the property tax to the AVT. But the producers can make an even larger change by going from $1.50 to $1. And you can see how if your assumptions are correct here, but you're at $1, if the producers are instead charging $1.50, then even with the governor's AVT passed, this project doesn't break even. Uh, it looks like they'd have to get Well, I mean, it basically is an equivalent— it's an equivalent change. Even if we passed the AVT, they still wouldn't break even at $75 a barrel, $75 oil.

Is that— is my analysis correct there using the numbers presented here? Thank you, Senator Dunbar, through the chair. I didn't quite follow, but But one, one, just one correction from the start of your question. So right now, well, I say right now, the last few oil-related, oil-indexed LNG contracts that we looked at, they averaged about 12.5%, not 10.5%, which I think is the number you quoted there. So really that gray box in the middle of the table there, you could argue is where the LNG market has been over the last year or so.

But nevertheless, the fundamental question, which is, you know, what happens if you, you know, if you add 50 cents to the gas price, in broad terms, you'd move about one— those blue and yellow boxes would move about one box to the right, roughly. Looking at those numbers, it's not quite one box. So your point, I think, is that, you know, these 50-cent changes in upstream gas price, you know, are broadly equivalent to, you know, major changes in the ABT and property tax. So the point is correct that But the upstream price has this major effect and can move economic rent up the chain. Thank you, Matt.

Okay. Yeah, brief follow-up. I'll just say, try to state it a little clearer for the public. Even if we pass a 90% tax cut, the state of Alaska has less ability to impact this project than the gas producers, the major oil and gas producers on the North Slope. They can, through changing the upstream price, basically determine whether this project goes or doesn't go.

Um, they, they— we have evidence from Department of Revenue that they are— they can make a profit at 45 cents upstream. Now, I'm not suggesting that they are going to do so, but if they can make a profit at— let's, let's call it 50 cents— then they have twice ability in their hands to make this project go or not go than the state of Alaska currently has. And so I just hope that the public and the governor recognizes that, and hopefully they make a healthy profit but don't, don't determine that this project shouldn't go forward because it's mostly in their hands is what this is. It's, it's about two-thirds in their hands, one-third in our hand, and actually it's 100% in hands of the financial market. But thank you, Madam Chair.

Further questions? Seeing none. Mr. Fulford. Okay, thank you, Chair Giesler. Let's move then to slide 7.

And again, taking Senator Dunbar's advice to keep it real simple, the current AVT is 55 cents per MCF. The difference between $1 and $1.50 in the upstream price is roughly the same. So, so I think your, your statement is on point. So moving to slide 7 then. So what I've done on this slide is to look at, instead of looking at the oil-linked LNG market per se, I've looked at where Alaska's competitiveness sits against U.S. Gulf Coast exports.

So in the table, we have a calculation of roughly the landed cost of LNG from the Gulf Coast to, to Asia. It's made up of Henry Hub. I looked up the forward price yesterday. It's $3.55 in 2030.

Bearing in mind this is a forward price, it's not what the price is actually expected to be, but I think as a conservative estimate it's probably good enough. Typically there'd be a 15% surcharge for fuel, other charges. Currently the price of liquefaction, I'll put it that way, on the Gulf Coast, it changes depending on, you know, construction costs and so forth, but you could take it to be about $2.80. And the shipping charges, call it $2.40, maybe a little bit more than that at the moment because, you know, Suez Canal's out of use. But anyway, it gives you a delivered cost of about $9.28 per MMBtu.

So what you see on there, again, to give the project some you know, credibility and benefit, what you see on there is based on the $1 and the base CAPEX. Alaska deliveries to Asia are quite a bit more competitive than Gulf Coast deliveries. But obviously, as the capital cost is increased or the upstream gas cost is increased, then that differential between Alaska and Gulf Coast is, is used up. So if you do the math on it, under the existing property tax, or I think we could take that as being under the currently proposed ABT, if the gas cost rises to more than $1.65 coupled with the base CAPEX, or the gas cost stays at $1 but the CAPEX goes more than 16.5% over the base case then Alaska loses that competitive edge against Gulf Coast. Um, if we look at the 6-cent, um, per MCF ABT, the numbers are slightly different.

You can push the upstream gas price up to $2.17, or you can push the CAPEX, uh, 31% over the base case. So either of those steps would, um, push you up into this, uh, comparable zone. With US Gulf Coast, that is based on these assumptions, I should say.

So one way of looking at it is if, for example, the gas cost is more than $1.65 but less than $2.17, then the project would fly with a 6-cent AVT but not the 55 cents that's tabled. And again, with the CAPEX, if it's more than 16.5% over but less than 31, then again, that would create an environment where the project could go with a 6-cent tax but wouldn't go with a 55-cent one. So really, The purpose of the slide is to sort of put that into context and quantify it. I'm happy to take questions.

Senator Myers. Yeah, thank you, Madam Chair. So you've got a Gulf Coast comparison here, and we, we did talk about that with AGDC when they were in front of us a couple of weeks ago. But a couple of days ago when Glenfarn was here, we were talking primarily about a comparison to Kitimat and the Canadians, and I was wondering if you had a good comparison price for them. I understand they just got started, so I don't know if that's something that's open market, easy to find.

Thank you, Senator Myers. Very happy to provide a short written account on that, but Basically, the, the way to look at, um, the comparison between Kitimat and Alaska is, uh, the shipping is almost identical, so you can ignore that part. The gas cost potentially is a little higher for LNG Canada because they're buying it on indexed. I think I mentioned a week or two back, um, AECO and Station 2 are the gas price references for that, but they would certainly be above $2 and potentially rising. But then the cost penalty that Alaska has to address is the gas processing plant.

So— and a slightly longer pipeline. Well, quite a bit longer. So a higher pipeline cost higher cost of processing, so potentially lower cost of gas. So what that tells you is that the cost of gas into the plant on the North Slope has to be materially less than the cost of gas that LNG Canada are buying at, uh, at ACO, uh, in order to support the additional pipeline and the GTP. Okay.

I can do the numbers for you. Follow-up, Senator Myers. Yeah, it would be helpful if you could do the numbers. But along that line with the price of gas, something— just kind of doing the math here in front of me with what you've got on your second— or with your third and fourth bullet point, talking about kind of where our headroom is on both the CapEx and on the upstream gas cost. Effectively, what I am seeing here is while you can interpret that as a lower, uh, AVT gives us more headroom in, in case the cost of the, of the project, uh, you know, in case of the cost overruns for the project, but I'm also interpreting that as you could then sell the gas for a higher price and still be competitive and of course we make royalty and production off that gas price.

So, you know, just looking at the difference there between the $1.65 and the $2.17, that extra, what, 52 cents, we can make about 13 cents more per MCF potentially as well on the upstream side if we're willing to lower the AVT. Is that a fair comparison?

Thank you, Senator Myers. And through the chair, I, I don't— I didn't quite write the numbers down, but I think, yeah, you're on the right track. And these kind of trade-offs between setting the tax, where the capital numbers come in, where the gas prices— these all go into the mix.

But ultimately if, if LNG deliveries from Alaska can't compete with US Gulf Coast, if the prices and the costs and the upstream gas and so forth comes in higher, then that, that would make it a very, very difficult project to, to get over the line. So the key for the project is to keep the, that zone of profitability, if you like, slightly to the left of the, of the red oval on the chart. And the thing I would add, you know, the, the $3.55, which, which is in the top of that box, it's, it's what the forward market is saying, but it's not really what upstream operators in the Lower 48 are expecting.

There are some suggestions that that Henry Hub cost could be near $4 or even $5 by 2030 and rising subsequently. So I think you should look at that US Gulf Coast number as being quite, quite a conservative one. Follow-up, Senator Myers. Yeah, on that, on that note, I just ran across an article I think last week that was talking about some— not Henry Hub, but some places in West Texas where both before and after the Iran War, the gas price at the hub has actually been negative for most of this year. And it sounds like it's a capacity issue, not just an LNG capacity issue, but just a pipeline capacity issue to get the gas out of the field and into a market, whether that's domestic or international.

But you can build pipelines relatively quickly. You can build pipelines in a few months or a couple of years, depending on how long of a pipe we're talking about here, is— you're talking about farther out, we're looking at $4 to $5 gas as opposed to $3.50. Is that something that could rapidly change if the producers saw that the market conditions were rising, that they could rapidly, you know, relatively rapidly bring on more capacity?

Thank you, Senator Myers. Through the Chair, the negative gas price is quite a local phenomenon, and it's because with the oil shortages currently caused by the closure of the Strait, oil producers are ramping up production very rapidly in the Permian And for every barrel of oil in the Permian, you produce 5,000 cubic feet of gas comes with it. And so the focus there is producing the oil. The gas is just a byproduct and as you say, the takeaway capacity for that gas is so limited that effectively it's way more gas than the system can handle.

So it's a particular feature of the current push to increase oil production in the US, but probably not something that could be relied upon. I, you know, I could talk about the sort of gas dynamics in the lower 48, but, you know, generally speaking, a lot of additional burden from additional LNG, extra gas-fired generation for data centers So the ability of the Lower 48 gas infrastructure to support that extra demand, I think, is in doubt. And I think it's likely that we'll see higher prices. Okay. Thank you.

All right. We have about 5 minutes left. Are there further questions for Mr. Fulford today? Any closing remarks, Mr. Fulford?

Thank you, Senator Giesel.

I think perhaps my closing remark would be to summarize some of the things we talked about today, which is that iterative progress on any of these LNG projects is beneficial. And, you know, even if we can't get to a final solution today, Progress on the project in the form of an alternative tax framework, for example, I think would be well received by the market and by other interested parties.

A way in which a more transparent and manageable flow of information from the project to the legislature, I think, would be very beneficial to consider right now. To remove some of the impasse that it's causing. So I think those would be my two main remarks. Great. Thank you very much for joining us today.

Appreciate your time. With that, we will conclude today's meeting. Our next meeting is tomorrow at 3:30 PM. We are stepping away again from the Supporting Gasline for Alaskans Act, and we will be considering governor appointees for the Board of Fish, Board of Game, the Big Game Commercial Services Board, the Alaska Assessment Review Board, and the Commercial Fisheries Entry Commission. At this time, we will stand adjourned.

Let the record reflect the time is 10:11 AM.