Senate Resources, 4/16/26, 9am

Senate Resources Committee meeting to order. Today is Thursday, April 16th, 2026, and the time is 9:01 AM. Please turn off your cell phones. Members present today: Senator Dunbar, Senator Myers, and myself, Senator Giesel. I am expecting the rest of the committee to come very shortly.

Um, oh, Senator Rauscher, pardon me, Senator Rauscher is on the phone, so welcome, Senator Rauscher. Yes, I am. Thank you. We have a quorum to conduct business. Heather and Kyla are helping us out with the audio and keeping the record today.

We are hearing the subject matter in Senate Bill 275 and 280. Welcome, Senator Kawasaki. These deal with the natural gas pipeline. We are continuing yesterday afternoon's presentation by Gaffney Klein. So online to speak to us and continue this is Nicholas Fulford.

He is the senior director of LNG and energy transition at Gaffney Klein. I want to also let folks know that Ryan Farnsworth, assistant attorney general, Department of Law, is online for questions. Dan Stickel, chief economist, is listening in here in Juneau also for questions. Uh, after we hear from Gaffney Klein and they complete their presentation, we'll be moving on to a presentation by Pegasus. So welcome, Mr. Fulford.

We finished slide 15 and we are moving now to slide 17 for today. So welcome.

Thank you, Chair Giesel, and good morning, committee members. Just doing a quick sound check. Yes, can hear you loud and clear. Excellent. So for the record, my name is Nicholas Fulford.

I'm head of LNG and energy transition at Gaffney Klein. So continuing yesterday's discussion, and perhaps this next section relates back to the day before yesterday in terms of the committee and some of the questions that were raised really around the project economics. So, um, starting on slide 17, uh, what I've represented here on the graph is effectively the cumulative revenue that a 6 cents per MCF alternative volumetric tax would generate, um, right up to 35 years, which probably not an unreasonable expectation in terms of a project of this sort. The math is relatively easy and, you know, the committee and people at home I'm sure will remember that the— that basically the volume of gas being produced by this project every year is about 1 billion MMBTUs. So if you multiply that by 6 cents per MCF, you get $60 million in revenue per annum.

And so on and so forth. So at 6 cents, it's 60 million. At 10 cents, it's 100 million, and so forth. There's been some discussion about the 1% indexation, and I know other— you've heard other testimony related to this too. Effectively, with a 1% nominal escalation, you would expect to see a slow decline in real value of that tax over time.

So to give you some idea, the $60 million per year in real terms using 2% inflation and 1% indexation would have fallen to about $47 million in real terms after 35 years. And the cumulative value would be about $2.23 billion in nominal terms, but just under $2 billion in real terms. So clearly there would be an expectation of a slow decline in the real value of the AVT. I have also— excuse me— I have also put another graph on here with a 10-cent just for illustrative purposes. You can see there that you get the same divergence of real and nominal value.

The further you go out in, in years. So I'll pause there for any questions, otherwise I'll move on. Senator Dunbar. Thank you, Madam Chair. Thank you, Mr. Fulford.

I have a couple questions on the math here. And so I guess my first question is, why doesn't the nominal— why don't the nominal curves actually look like they curve upward on the on the graph here. And I guess this gets to my other question about what the 1% is actually the 1% of, because it's certainly a 2%, you know, 2% of 6 cents. But the next time you increase by 2%, it should be, you know, 0.0612 that you're doing 2% of, correct? And then you see how it would be cumulative and you'd think that it would slope upwards in nominal terms, even though it would be below inflation and flat in real terms.

So that's my first question. Unless we're— unless the 1% is not altering the cents, but the, the 6 cents, but something else. And then my second question is, um, so we've got 6 cents here and we've heard it stated that's equivalent to 2 mL. Does that mean that every 3 cents is about equal to 1 mL, or does the math not operate like that? So, so for 20 mL, for example, it would be 60 cents.

Uh, thank you, Senator Dunbar. Um, so the first question, um, I, I think to some extent there's a little bit of an optical illusion with the graph. Um, the— there is a— there is effectively a curve in, in the, in the bottom of, of the two lines. Um, so that the dark line and the blue line, it's not very apparent from the graph because it is such a gradual erosion in value, so the curve isn't as pronounced as it might be. So, you know, but we can delve into this more on a future occasion if you'd like to.

And the second question, the— it's a slightly more difficult one to answer because the profile around property tax is different. It changes over years depending on the taxable value of the asset, which typically will fall.

On one of my earlier slides, I think I approximated the value of the current property tax over over the first 10 years at I think around 70 cents, perhaps a little less if you apply the municipal tax rates. So in very, very broad terms, this 6 cents per MCF does equate to about a tenth of the current mill rate, if you like. But, you know, over a period of years, it would change, put it that way. But if you wanted a very quick rule of thumb, it probably equates to about the $2 mil property tax rate. Follow-up question?

Yes, follow-up, Senator Dunbar. Well, thank you, Madam Chair. And, um, so I, I certainly think 1% is too low. It doesn't even remotely keep up with inflation. But the percent change here because it's percent of a cent leads to some very complicated rates and some very complicated math, I think.

Um, and, uh, and, and it should be accelerating. The, the increase will be accelerating in the out years. And so I'm wondering if it would make more sense— sense for us to change it to a 1-cent increase, you know, 6 cents 7 cents, 8 cents, and it would still be something like 54— actually, as you said, 7— 70 cents. It would be, it would be something like 64 years before we got back to that 20 mils, but it would, uh, accelerate a little bit faster and a little bit flatter, uh, particularly in the, in the close years. And as you've talked about before, the time value of money is a real thing, and Alaska needs some revenue in the short term, not just 50 years from now.

So is there some other important reason why we shouldn't change 1% to 1 cent?

Um, Senator Dunbar, through the chair, around the world, um, you know, different projects, not just oil and gas, but these sorts of mechanisms are fairly common. It is more common to see an indexation which relates to some kind of inflationary measure. It is not often that you see a fixed inflation rate which is manifestly less than what you would expect from inflation. So that element of the proposal is a little unusual.

The other feature is simplicity and the ability to track and audit. And in that sense, some kind of structured increase, perhaps not every year, but, you know, for example, after 5 years, 10 years, that might be a another alternative way of doing it to protect the value in the long term.

Follow-up, Senator Dunbar. Thank you, uh, Mr., Madam Chair. Um, so in other jurisdictions, do they just index it to inflation, or do they say 1% per annum? I would be sort of surprised if other jurisdictions agreed to 1%, because as we said, that's below inflation. But if the idea is to protect the real value, then, then should we index it to inflation?

Uh, thank you, Senator Dunbar. A couple of points here. I think, um, first of all, given that, you know, we're looking at 35 years or more of project life, you know, given the amount of gas that, that has potential to exported. There's a lot of risk involved in setting a fixed percentage for anything over such a long period because, you know, as everyone's aware, you know, inflation changes. It can go up, it can go down.

There can be other kind of geopolitical features which affect exchange rates. So there is some risk, I think, in fixing a nominal percentage like this over such a long period of time. And from experience, I would say that if that's what were done, at some point it would probably be revisited because it would be out of kilter with what had happened from inflation, exchange rates, and everything else.

So there is that factor of it, that anything which is fixed, which operates over a period of decades, has risk both to the state and, frankly, to the project developer as well. So some kind of— that's why some kind of inflationary measure is more typical. Thank you. Follow-up? No, thank you, Mr. Fulford.

Thank you, Madam Chair. Further questions? Senator Rauscher, any questions?

Okay, hearing none, um, I think I'm good. Thank you. We're ready to move on to slide 18.

Okay, thank you, Chair Giesel. Yes, slide 18, um, is just a reminder, if you like, that, um, the, the greatest competition that Alaska faces is from the south. The LNG export economics from Canada are broadly similar to those in Alaska. So it's useful to kind of continue to make that comparison in terms of what the Alaska project looks like vis-à-vis government take compared to, compared to Canada. It's impossible to make an exact comparison because there are other taxes in Canada which operate that their upstream tax and royalty is a little bit different But I think you've seen the top part of this slide before with the natural gas credit that was offered to the project in order really to just push it over the line and enable it to operate economically.

There's roughly a 24% federal and provincial tax rate in Canada. The combination of US federal and Alaska state comes to about 28.43%. That's the way the two combine. And with the 6 cents volumetric tax, that would move that number up to about 33%.

In the scheme of things, it's not huge, but nevertheless, it's a consideration. And it's something that you probably want to keep in mind as the project develops and as the fiscal regime that applies to it is further fine-tuned. The existing property tax, of course, would push that up still further and would make a material difference. Senator Duncan. Oh, pardon me.

Go ahead. No, no, I think that's all I had to say on that slide. Very good. Thank you. Senator Dunbar.

Thank you, Madam Chair. Uh, Mr. Fulford, that 33.2%, does that take into account the 45Q tax credit funding? The federal— we, we learned 2 days ago that the, the project relies, I think, pretty heavily on the 45Q, at least for the Phase 2 portion, um, that even— that drops the federal you know, revenues to a negative number for the first 10 years, I think, you know, to the tune of several billion dollars. Does that number include that?

Uh, thank you, Senator Dumbaugh, through the chair. Uh, it's an excellent point. Um, this, this doesn't include the secondary effects of, um, of the, um, 45Q tax credit So that's one feature which would align it. The detail I would add is that the Canadian projects operate on relatively dry gas with low CO2 content, so they don't actually need the gas treatment facilities that would exist on the Slope. But as I've explained before, You know, it's a very expensive facility, but the CO2 created— and I think this was featured in the DOR presentation— that the CO2 that originates from that plant will also enhance oil revenue.

So it's a very complex thing, but quick answer is the 45Q would bring that number down. Thank you, Mr. Fulford. Thank you, Madam Chair. Mr. Fulford, the other caveat to remember is Alaska state corporate income tax is not levied against S corporations, which the producer is, or the company is. Senator Kawasaki.

Yeah, thanks. I just had a question. Just generally, we're comparing Canada and Alaska, and Canada does have some advantages in that they've developed liquefied natural gas and have a pretty developed transmission lines across the countries. And I'm wondering, I mean, is it really a fair— is that really the fair thing? Because what we're doing is we're creating a brand new LNG project versus these other, um, versus the Canada stack that you've shown us as comparison.

Uh, yes, thanks, Senator Kowalski, through the chair. Um, so LNG Canada is operating today. They've got 2 7 million tonne trains which give a total of 14 million tonnes. They're, they're at an advanced stage with Phase 2, which would be another 2 trains, so it'd be another 14 million tonnes from there. And given, given what we're seeing geopolitically, I, I would be very surprised if if we don't see some kind of decision on that fairly shortly.

But then if you look at the, um, Xiloxem's LNG project just a few miles south of Ketchikan, that's 12 million tons. It's, um, it's at a relatively similar stage, I would say, to AK LNG. There are other features and complications and The development involves considerable input from the First Nations group that own the site. So as we look at these comparative taxes and how they might influence decisions about the flow of capital, that probably would be a good project to consider as being competitive with Alaska. Thank you.

Any further questions on slide 18? All right, seeing none, we're ready for slide 19. Okay, thank you, Chair Giesel. So slide 19, I know 2 days ago there were a lot of questions about the DOR data and how it was presented, and one of the questions related to you know, relative to these breakeven prices, where do international prices sit? Um, so, so what I've done here is I've taken the, uh, DOR breakeven matrix for gas exports.

And so then I've looked back and, and said, well, what, what was the average, uh, long-term price? So this is, this is using both, uh, Japanese import data from their customs government department and also a kind of an oil index proxy. So these would be the sort of long-term prices that I think Mr. Kissinger sort of referred to. And I've looked at the matrix and said, okay, which part of that matrix would have enabled the project to exist at a 10% post-tax return? Or better.

And not surprisingly, what you see is that the— based on these historical prices, which of course, you know, may not exist in the future, um, you can see that it's really the top left part of that matrix which generates realistically a financeable project. Um, so the difference between the top box and the bottom one, of course, is the replacement of property tax with the 6-cent volumetric tax. So what you can see is that by changing the property tax basis, you're creating a slightly bigger envelope in which the project can exist. So I was saying— excuse me— I was saying yesterday that, you know, at this stage in an LNG project, it would be very unusual to see what I describe as robust economics. These usually emerge, you know, a few years or decades down the road where, you know, they typically will produce very significant cash flows.

But in terms of getting the project financeable and started, we're usually dealing in this kind of very narrow margin of project economics. So it's a good illustration of how economic the project might be and the difference that the property tax change might make to the operating envelope for the project where it can, it can produce, as I say, the 10% post-tax return. The following slide illustrates it in a little bit of a different fashion, but I'll pause there for any questions. Questions? Senator Myers.

Thank you, Madam Chair. So, Mr. Fulford, I guess there's a little bit of a debate about what the appropriate comparison is. So on this slide you've got the 10-year average contract price. I assume that's for Japan.

AGDC was here previously and said their comparison, they were looking at Gulf Coast prices where they're aiming at around $10. We've got the— and then DOR was in here a couple of days ago and was mentioning the, the JKM method. And at 2031, that's sitting around, well, a little under $9 right now on the futures market. So I guess the question is, you know, which, which one is the most accurate comparison for us to go with as we're trying to judge whether this thing is meeting the economics?

Uh, thank you, Senator Mizen, through the chair. Um, that's, that's a great question because really it's kind of all of the above. Um, if you like, as you think of increasing LNG demand globally, based on the laws of economics, that, that demand would typically be filled by the cheapest LNG And for the last many years, that cheapest LNG has been— other than Qatar, which is much cheaper than anything else— other than that, that marginal MMBTU has typically been Gulf Coast LNG. And so, as we discussed, there's other advantages of Alaska, um, the, the security supply, the, the shipping logistics are quite significantly simpler than the Gulf Coast. Um, but ultimately one of the goals of the project would be to be able to compete roughly with, with U.S. Gulf Coast exports.

Um, otherwise, you know, the, the economics will dictate that the Gulf Coast is where the gas will come from. One point I would make about Gulf Coast economics, which I've made before, and, you know, remains to be seen how it pans out, but if you, if you look at the additional demand on the sort of U.S. domestic gas portfolio of the LNG, if you look at the demand from data centers for new power generation Um, it is a very significant burden that's being placed on Lower 48 gas producers. And from time to time, we have seen Henry Hub prices coming up, settling down. And so the, the real exposure of those Gulf Coast projects is to Henry Hub and what might happen to wholesale prices. Um, and of course in the context of an LNG project you have to look at that not just next year or the year after, but 10 or 20 or 30 years from now.

So, so that there's, there's other factors there other than a straight comparison with Gulf Coast economics. Um, then, you know, LNG, it's bought and sold typically, you know, sometimes using a straight oil index You know, as the Kissinger mentioned, 12 to 14%, that's typically what we've seen. The, the line on the next graph is based on 14.

These days, because the different indices kind of vary and depart from one another, it's quite common to see a hybrid gas price. So for example, it could be 50% oil, 50% Henry Hub, adjusted. Sometimes it would include some JKM. And for a spot purchase, you know, that might just purely be index-based on JKM. So it's quite a complex mishmash of different indices and prices, but all of these things will drive the ultimate economics of the project.

Okay, thank you. Senator Wielechowski. I'm curious how ownership interest affects these numbers or affects the economics of the project. If, for example, the local communities were to get an equity stake in the project, the state were to take its 25% equity stake, how does that impact these numbers?

Thank you, Senator Wieleckiowski. That's— I'm just trying to think of some sort of general comments one could make about that.

The— obviously each equity partner will have their own set of financial criteria on on the basis of which to invest.

It's also possible that the dividend structure might look different depending on the equity owner.

The example I talked about briefly yesterday for Papua New Guinea, that included a preference share type deal to essentially smooth out the revenues continuing the, the comments I made yesterday about stability for local communities. So the, um, those features would typically affect these numbers. Uh, I, I would say probably on the margin rather than a significant change in, in the number we're seeing. But, you know, the— it would depend on the detail. And the risk appetite and willingness of the different participants to accept certain types of rate of return.

Typically, a government entity might accept a lower rate of return than a private one. So if that were the case, then these numbers would potentially go down a little.

Follow-up.

The total cut in property taxes is $600 million or so. If the local communities were to say, okay, we'll give $600 million in tax breaks and accept this 6-cent alternative volume tax, but in exchange we want an equivalent equity stake in the project. I guess that's maybe to— I don't know if that changes your opinion or refines it a little bit.

Thank you, Senator Wielechowski. I think through the chair, you know, we're talking about quite complex nuances in how this is being looked at. You know, I made the comment yesterday that, you know, these projects, they come together in a very iterative manner. And I would fully expect that the scenarios that you're describing there around equity stakes, acceptable rates of return, forms of dividend structure, I would expect all that to form part of the dialogue. With the project developers and potentially with some of the communities affected in the coming months and years.

And it will— it will move these numbers around. And it may dictate what you do on other taxes as well. So, you know, there are so many moving parts and there's so many outcomes. You know, the important thing is to delve into them, you know, have a dialogue on which may or may not be possible and move the definition of the project forward.

Further questions?

Senator Clayman.

Thank you. First question I had is, to some extent, this is looking at trying to look at this from the standpoint of a government. If, if I'm a private business coming to you for your advice on whether I should go down the line as a business to invest in or start the process of trying to build this gas line, what does this sheet tell you about what you would advise a private business about this as a, as a good business investment?

Thank you, Senator Clayman, through the chair. I think what this emphasizes is some of the dialogue that's been going on for some weeks now, which is that, you know, very, very detailed cost control, design optimization, you know, a real rigor in terms of design efficiency and cost is absolutely required to push the project outcome towards that top left-hand corner, which relates to the gas price as well. It's not just the capital cost.

So really the levers— the levers that will affect the ultimate outcome. One is capital cost. One is property tax. You know, we've been talking about that today and yesterday. And the third is federal support in the form of loan guarantees or other types of support.

So those are the— those are the three big levers which, in addition to the cost of the gas, will dictate whether this is a good investment for a private investor. Follow-up. Thank you, Madam Chair. The other place I note you have notes that Gaffney Cline's model has a slightly higher base CapEx at a dollar compared to what Department of Revenue has, and you also have a lower base CapEx price for the baseline, spring baseline, as opposed to proposed legislation. And I, at least I'm getting a different— your differential would be 39 cents between baseline and legislation in the DOR is 57 cents.

Is there a significance to the different calculations that you've got? And if there is a significance, what's the significant difference?

Yeah, thank you, Senator Clayman. Well, one difference we talked about is the 45Q. The other differences are likely to be depreciation methodology, And, you know, various— and capital structure as well. Um, you know, I think we, uh, we typically carried our slightly higher interest rate for, um, cost of debt. But I think in— given where the project is and given that we haven't conferred with DOR on, on the model and the methodology, I, I would say I would say what this slide shows and the numbers in terms of where we're coming out is that by and large our model and our approach, given the same inputs, does align with the DOR one.

And as we were saying yesterday, it may be that using that DOR model, which I think has had the— some degree of input from AGDC, and refining it with different scenarios and approaches would get us close to this kind of open book approach that we talked about. Thank you. Senator Dunbar. Thank you, Madam Chair. I apologize, Mr. Fulford, I got momentarily distracted, so if you already answered this, feel free to give me a very short answer, but if you look at the The difference between $1 and $1.50 gas, it's a 50-cent difference, but the difference, the impact, you know, one row below that is 69 cents in both cases.

So why is the impact on the project so much larger than the difference in the price of gas?

Thank you, Senator Dunbar. I think it may have to do with upstream tax, but if Mr. Stickell is on the line, I think that might be a question he could very quickly answer. Mr. Stickell, I see you are listening in. I wonder if you would be able to answer Senator Dunbar's question. He can certainly repeat it if need be.

Sure, this is Dan Stickell, Chief Economist with Department of Revenue to Senator Dunbar through the chair. So there's a, there's a couple reasons for that. One, there's calculations that include impact of fuel. Gas are one of the pieces here. So for each molecule of delivered gas in into the market, the project actually has to purchase additional gas above and beyond that.

And so that's one of the reasons that the, the impact on the delivered price doesn't exactly align with the impact of the purchase price. Follow-up, Senator Dunbar? Yeah, I mean, the other thing that's striking about this number is that there's a 59-cent difference. I think a different model, I think you said 53-cent difference between the baseline and the proposed legislation at that $1.50 price. But that's significantly less than the benefit the project gets from going from $1.50 to $1 gas.

So I guess the question is sort of, why is the pressure on the state to change our portion rather than the producers, who could have a greater impact— according to this chart, could have a greater impact on whether or not the profit— the project is profitable? And then a follow-up to that, uh, Mr. Stickel, is, do the producers— are the producers still making money at dollar gas?

Senator Dunbar, through the chair, under our— so we have some baseline modeling assumptions for the project generally, which include both the revenue from the gas sold into the project as well as associated oil developments. Under our baseline modeling assumptions, um, generally yes, there would be a positive overall income to the producers.

Okay, I guess the follow-up question then to Mr. Fulford, uh, I don't know if you can answer this question, but why is there so much pressure on the state to to change our tax structure when just through these we can see that the producers of the gas on North Slope can have a significantly larger impact on whether or not the project is profitable.

Thank you, Senator Dunbar. Through the chair, one of the other considerations is the difference in taxation structure, obviously, in, in the upstream, um, with, with typically a much higher, um, uh, government take regarding oil production in particular, potentially gas. So, um, all I would say, I think, is, is it, it comes down to this kind of, um, iterative approach as, as you as you pull away the level of detail and really get down to a very, you know, a very almost forensic examination of the project economics, the subtleties around, you know, moving pricing, changing taxes, they become more visible. And I've said it many times before, but projects like these are exceptionally complicated. And the sort of dialogue we're having now probably requires a day or two of kind of analysis and scenarios to examine.

So it's a good question and one which which, you know, would need to be examined. Follow-up, Senator Ardenbach? No, thank you, Madam Chair. Senator Wilkowski. Thank you.

This question is probably directed to Mr. Stickell. What is the producer's rate of return at $1, $1.50, and $2? What is your estimated rate of return for them?

Senator Wilkowski, through the Chair, as I mentioned the other day, we don't have the exact rate of returns, and we'd be happy to— we're going to provide some information looking at producer returns generally as part of our upcoming response to the committee. Follow-up, Senator? I don't have a direct answer off the top of my head. Follow-up, Senator Wilkowski? I think that's Certainly worthy of committee discussion, at least to have a ballpark number of what the rates of return are for the producers and sort of what the role of the state is if a producer comes in and says, "We demand $5 an MCF," hypothetically, and when in reality they can make a very good profit at, say, $1, $1.50.

And shifting the burden of accepting lesser revenue really to the state, possibly, or to the pipeline producer. And also, I think it will help inform us in terms of how we get our constitutional obligation to get the maximum value. Maybe we'd want to change the upstream terms and figure out a way to tax or capture revenue at a later place. So just, I think, some more analysis on the upstream would be very helpful. Thank you.

Further questions?

All right, seeing none, we'll move on to slide 20.

Thank you, Chair Giselle. Just getting that up on my screen. Um, so slide 20 is just a, a kind of a visualization of the, the sort of red box at the top left of the, of the matrix on the last slide. Um, what I've, what I've done here, I've used, um, the Japan Customs price, which is the orange one, and I've used the 14% oil index, which is the blue one. Um, there's a little bit of a lag between the two because the way pricing works in LNG.

So the, the, the peaks and troughs typically do align. I haven't, I haven't shifted the line by 3 months, which I would need to have done. But the, the key takeaway I think from this slide is, and, and bearing in mind these are you know, the, the price volatility wouldn't be quite as much as this, but, um, it gives you a sense that the, the turquoise box represents the, the zone where the project is able to make its 10% return. Uh, this is at $1 and, and at the base capital, uh, cost. The dotted line underneath it represents what that box would look like with the change to the ABT.

So you can see that it takes in a higher proportion of time in, in this kind of profitable area. You know, clearly this is historical, and there are a host of market supply-demand factors which affected this curve, which, which don't necessarily point to where the prices might be in future. But all the same, I think it shows that the project is on this kind of cusp of economic viability, and moving to the AVT structure would significantly help the project capture that kind of profitable zone of operation. So as I say, it's just, just illustrative really, but it, it helps allows you to visualize where the product is in relation to where international LNG prices are.

Questions here? I have one, Mr. Fulford. We have seen the news report of the school district in Texas, the Texas project now that Glenfarn is pursuing, who denied property tax exchange for the project. Now, I believe that was for the LNG project portion. You would know more than that.

But Glenfarm determined they would go forward without the tax abatement. Can you comment on that?

Thank you, Chair Giesele. I believe the school district omission was, uh, was a Texas-wide change. I—. It did affect the Glenfarm project. Um, the, um, clearly if you— it's on the slide, I think, uh, further back, but, um, you know, the 10-year tax holiday value to Glenfarm for Texas LNG was quite considerably less than some of the other projects.

Um, but Again, you know, the economics of Texas and exports from the Gulf Coast are quite different. I don't believe that project has gone to FID yet. I may be mistaken, but I think it's still awaiting FID. So it, you know, whether the economics are where they need to be to launch that project remains to be seen. Well, thank you for that, but could you clarify?

Are you saying that the FID has not been reached yet for the Glenfarm, Texas project?

I, I would have to double-check, but that's my understanding. Thank you. And is that predominantly an LNG facility with a short pipeline? Do you know what the components are of that project?

It's, um, it's located among many of the other LNG projects in that part of Texas, and it would be procuring gas through a relatively developed network of natural gas pipelines at something similar to Henry Hub. Possibly a slight discount or a slight premium. The, um, I, I think it's a, a similar LNG design to the one that's being proposed for, uh, for Alaska, but it is much smaller. Um, let me just, uh, double check. Yeah, it is 4 million tons, so It's, it's a fifth of the size of, uh, of the proposed Alaska project.

Thank you. Senator Wilkowski, do you have any analysis of what the breakeven prices are in a typical Texas LNG facility or Louisiana LNG facility?

Thank you, Senator Wielechowski. Yes, in, in round terms, you would take the prevailing Henry Hub price, um, call it $4, you'd add about 15% for fuel. Um, the, the cost of liquefying the gas would be about $2.50, but then the cost of shipping to Asia would be maybe another $2.50, especially currently with so many of the usual routes unusable. So I wasn't adding that up while I was talking, but that will give you a rough number. Follow-up, Senator Wilkowski.

So that my rough math, you said $4, so they have $4 gas down there, and it sounds like average plus 15—. Give or take, yep. So we—. 15%. So we're probably a little more competitive on the gas end, or a lot more competitive on the gas end, plus 15%.

Exactly. Plus 15% would be, is that $4.60 roughly? Yes. And then add $5 onto that, so you're looking at $9.60.

And then—. Follow-up, Senator Wielekowski. So $9.60, and is that factoring in the— that's factored— that's all in? That's profits and a 10%— is that 12% pretax or 10% post-tax or what? Similar taxation?

Similar, probably on an infrastructure project like this, probably 10% post-tax is not a bad guess. And what I would say is that that $250 million for the liquefaction, if a project is highly efficient and has leveraged, you know, good supply relationships and EPC contract terms, you know, it could be in the range of $220, $230 up to about $270, $280, put it that way. And that depends on the location of the project, the way in which it is being managed, and the way in which the contracts have been let.

Thank you. I see no other questions. So I believe we are at— that was the last slide. Are there any other—. Yes.

Very good. Are there any other questions from committee members for Mr. Fulford?

All right, seeing none, Mr. Fulford, thank you for being here and for this presentation. Thank you for taking all these questions. Any closing remarks?

Thank you, Chair Giesel. It was a pleasure to speak to the committee. Appreciate the opportunity, but no, no extra remarks today. All right, thank you. We're going to go on now to a presentation from Pegasus Global Holdings Incorporated.

The presenters available today are Jeremy Clark, he's the Chief Operating Officer of Pegasus, and Joe Miller, President and CEO of Pegasus. Pegasus. Gentlemen, welcome and thank you for joining us today. I will invite you to introduce yourselves and begin your presentation.

Yes, Joe Miller, President and CEO of Pegasus Global. I'll turn it over to Jeremy, who will be leading us through the presentation today. Thank you, Joe. For the record, I'm Jeremy Clark, CEO of Pegasus Global. Mm-hmm.

We previously presented to the legislature in January of this year as well as last spring, and were initially engaged back in 2019 to review the risks of megaprojects. Today our presentation continues to focus on megaproject risks, including specifically looking at distinctions between mega and gigaprojects, a couple of case studies from recent gas pipeline projects in in the US, a discussion around the phased approach being implemented for the Alaska LNG project, and review of lessons learned from the TAPS project.

We can go to the next slide, please.

A quick definition of megaprojects I'm sure all of you are now well familiar with. In essence, they are extremely large and complex projects with many complexities and interfaces.

Typically over a billion dollars, multi-year planning, multi-year construction, many stakeholders. That is kind of the facets of the complexity there.

Jump to the next slide if there's no questions. No questions. Perfect. So now looking at Megaprojects to gigaprojects. In the simplest terms, a gigaproject is a very large megaproject.

Um, what this means in practice typically is a project with such scale that they can be transformational for the region, which can mean new energy systems, new economies, even entirely new cities being built. And with that scale, of course, the complexity and risks also increase. You can see we've kind of had some quick highlights of the cost, scale, risks, et cetera, of the kind of distinction between mega and giga. But again, the giga is really just a larger, more complex version of a mega project.

I see no questions. No questions. All right. Thank you. Next slide there.

So the challenges with gigaprojects are really common with the megaproject challenges. The iron law that Ben Flyberg has penned, that over budget, over time, under benefits, over and over again, is very relevant to both mega and gigaprojects.

With their large size and complexity, they face many challenges beyond typical projects. One of the overarching drivers to the challenges is just that long timeline from initiation through planning and execution to the final delivery of the project. Of course, with the Alaska LNG Project, everyone's aware that, you know, it started really in earnest with the creation of AGDC in 2014. 12 Years later, now we're just nearing the FID of the project.

So these extended timelines, beyond just leading to the higher risk exposure, also open them up to Increased likelihood for black swan type events, just outside the normal risk management practices, like a COVID-19 type event. And then with the gigaprojects, the scale just means those impacts also have a higher degree of impact. A quick example would be a $5 billion project with a 1% cost increase would equate to a $50 million impact. While a 1% cost increase on a $25 billion project is a $250 million impact. So the scale just rises with everything on a gigaproject.

Now, despite these challenges, um, completed megaprojects still generally provide their intended benefits, even if at a higher cost than planned. Um, we were part of a team that reviewed the prudency of the Georgia Bogle Nuclear Power Plant. This project had a slew of challenges from being executed during COVID-19, the bankruptcy of key project partners, the first deployment of advanced reactor technologies in the U.S., and more. Cost rose from nearly $14 billion to final cost of over $36 billion, as well as taking 7 years longer than planned to complete. However, despite all that, it now provides reliable energy to over 2 million homes and will operate for another 60 to 80 years.

Jumping ahead, if there's no questions there. Senator Kawasaki had a question. Thanks. And I guess this goes back to the prior slide, but would you consider this AK LNG one giga project, one medium-sized giga project, or independent small giga projects?

That's— thank you, Senator Kawasaki. That's a very good question. From our perspective, we would treat the overall program as a, as a giga program, essentially. And then the three main components, the pipeline, the treatment plant, and the terminal, those are kind of right on the threshold between a mega and giga project. You know, you could call it either way for most of them, but the— I think the key distinction is the overall program would certainly be a giga program.

Follow-up, Senator Kawasaki. Yeah, and I know you're gonna— I see there's a slide just a couple ahead, but I guess the underpinnings of the economics are based on exporting LNG, and so even if we had a pipeline that's not going to help anybody. And even if we had a gas treatment plant, that won't help anybody. It's really the LNG export facility at the terminus that is the, the big project.

Yes, Senator Kawasaki, that would be the— certainly the revenue driver of the project.

Okay. Senator Kiliman.

No, I decided at the last minute. So I've been reading the, the Flyberg book. I mean, he may have more than one, but I've been reading one of them over the last few weeks. And one of the topics he says is you have to think of these projects not going from left to right, but from right to left. And if we're looking at these whether— well, the whole pipeline project with the 3 components, what's— if we're looking at the end product, what is the picture that it is on the right from your perspective?

Um, Senator Clayman, I'm not specifically familiar with that exact passage from Flybird, but I Imagine he's getting that you want to define what the end product looks like and kind of the parameters around that and work backwards from that. So yes, you know, for the state of Alaska, it's providing that in-state supply, which the pipeline would achieve, and having that revenue generated from the in-state resource, which the terminal would provide. And there's obviously a slew of specific details and interfaces that go along with that.

Follow-up, Senator Clayman? Not at this point, thank you. All right, I see no further questions. We can move on.

All right, here we've summarized the scope and issues associated with two recent natural gas line projects that were executed in the United States, and I'll turn it over to Joe to add some discussion to that. Just for the public. Sure, thank you. Again, Joe Miller for the record. Just for the public who are listening, we're on slide pipeline case studies.

The slides are not numbered, but that's the title on the slide we're on.

Yes, I live near Charlotte, Carolina, and these are a couple pipelines that I follow pretty closely. And I spent quite a bit of time working for an electric and gas utility that was a partner in the Atlantic Coast Pipeline specifically. Um, in the Southeast and Mid-Atlantic and really Northeast, historically much of the natural gas has come from the Transco pipeline, which transported pipe, which currently transports gas from the Gulf to those regions. That pipeline had become completely full with increased demand over the years, and so there were many utilities scrambling to find additional gas. The Northern Appalachian gas region developed based on advances in horizontal drilling and fracturing.

However, there were not pipelines to get that to market. So these were a couple very important pipelines that were attempting to do that. I just wanted to go over briefly their history. Um, you can see the Mountain Valley Pipeline, about 300-mile pipeline initially estimated at $3.5 billion, ended up at $9.6 billion. Um, construction commenced in 2018 and ended up coming into service in June of 2024.

Um, and the Atlantic Coast Pipeline, 600-mile pipeline from Virginia to the very bottom of North Carolina, was a $1.5 billion BCF per day pipeline. Initially estimated to be $4.5 billion, and its last estimate ended up at 4— or pardon me, $8+ billion. Construction commenced in 2018, and the project was canceled in 2020. At that point, had about a 3.5-year delay. On that pipeline, there was not a formal communication on the amount of costs that had been incurred but many put that cost north of $3 billion.

And so I just mentioned these as examples as you're considering taxation and you're considering gas supply for the state. And I might add that the Mountain Valley Pipeline, it did get completed, and it is providing a very significant, meaningful source of gas— lower-cost gas, I might add, as well— to the region. But both of these suffered from cycles of agencies issuing permits, opposition challenging those permits, courts vacating those permits, the agency then reissues the permit, and then another lawsuit is filed. But both of them suffered from that significantly, and it was a primary contributor to the demise of the Atlantic Coast Pipeline. Mountain Valley Pipeline was over 90% complete and hung up on permits.

There were many that thought that it was not going to ever get completed, even though it was 90% complete. And a primary reason it did get completed is Senator Manchin agreed to the Inflation Reduction Act, and one of those— what he got— one of the things he got in change was the ability to complete Mountain Valley Pipeline. And so I just wanted to go over those two examples. Um, I think, you know, the points are that the pipelines can take longer than originally expected, they can start and not finish, and I think those two things are important relative to considering taxation treatment. We've heard a lot of discussion related to the impacts of municipalities and those costs not getting recovered until later.

And we just want to point out that construction can take much longer than expected, and those impacts can last for longer.

There can be a scenario where those construction impacts are felt and the project does not get completed.

And again, also considerations in terms of meeting gas supply needs. Mega projects can take quite a bit longer than expected. And we had the opportunity to meet with John Sims, and of course, the reliability of options is front and center in his mind as well. Any questions on this slide? Yes, Senator Myers.

Thank you, Madam Chair. So, Mr. Miller, with that Atlantic Coast pipeline, you said it, It began construction, but then it was canceled midway through. I'm curious as to what happened— excuse me— with what was already in the ground. Did they have— did somebody have to go pull it back up? Was it left there?

Has it been sold off to another developer who might consider completing it at a later date? What's going on there?

That's a very good question, and I'm not certain of that. If they had reclamation funding that allowed them to bring that back to original condition. I'm not certain. I've not heard of that pipe being reclaimed. So I'm not— I just can't answer your question.

I'm sorry about that. Okay. Thank you. Senator Kawasaki. Yeah, thank you for being online.

I just had a question about the two pipelines. Were these pipelines at final investment decision knowing what the gas at the terminus was going to cost or was going to sell for? And where was the terminus? Was it a facility? Was it a—.

It wasn't an export facility. It was— it sounds like it was to meet demands.

Um, I believe the terminus for the Mountain Valley Pipeline was into the Transco pipeline that I spoke about earlier, um, in, in what— and pardon me, in Virginia. Uh, the terminus for the Atlantic Coast pipeline was at the very southern border of North Carolina, very close to the South Carolina border, if that helps. Does follow-up, Senator Kosa? To follow up, were they I mean, it sounds like— were they already fully subscribed when the companies that built Atlantic Coast Pipeline decided to commit?

Yes, I believe, um, you know, in my, my previous employer, Duke Energy, was, was a part owner in that pipeline, but probably as important was a co-anchor, co-anchor shipper. For that pipeline as well. I believe both pipelines were largely subscribed. Thank you. I believe, I believe over, over 70 to 80% subscribed.

Senator Wilkowski. Thank you. You have the two, uh, the two pipelines here you have initially estimated, and I'm I'm curious when it was initially estimated, how far along in the process was that? Was that the FID initial estimate or was that a FEED estimate? How far along in the process was that?

Are you basing those estimates? That is a good question. Jeremy, do you recall that? I'm not sure if it was— this is Jeremy Clark for the record. I'm not sure that it was specifically detailed in the records that we reviewed, but my assumption would be that that was— initial estimate would have been probably at the FID phase in this case.

Follow-up, Senator Wilkerson. Subject to check. And just comparing the issues, it seems that there were permitting issues, there was regulatory uncertainty, and I think by and large permits are issued for our gas line. I don't think there is regulatory— well, there's some question about whether the RCA applies or not. But it seems like probably one of the bigger issues is the permitting, which we have the permits here.

So I'm curious, trying to do an apples-to-apples comparison on where we are versus where these are. Maybe you can give us some input on that. Sure. And a good point. Again, Joe Miller for the record.

And one of the reasons we presented these is they had federal permits prior to construction. These challenges occurred— many of the challenges occurred after construction. And so those challenges related to questioning the analysis that underpinned the issuance of those permits, but also claims of construction not abiding to the permits, if that helps. Follow-up, Senator Wilkowski. So the construction was completed and they wouldn't let them start flowing gas through the project?

Is that your— no, um, so when construction completed, some of the opposition, uh, attained information relative to those construction practices and challenged whether or not that construction, while it was ongoing, was complying with the permit requirements, if that helps. Follow-up. So in addition to the, the construction issues, they were also questioning and challenging the analysis that the permitting agency conducted ahead of issuing those permits. Okay. Senator Wilkowski.

That's interesting. And I'm—. So what I— my thought process all along, and I think many people's, is that, well, we have the permits and we're not really exposed to those problems. But you're saying that there still could be, after construction, there still could be challenges? Yes, that is one of the important issues why we included this slide and wanted to review these with you.

It is significant that, that this project does have federal permits and many state permits. Those are not easy, take a lot of engineering, a lot of work, and so that is significant. But we just want to make the point that that does not mean that challenges are over. Don't know that this project would receive the type of challenges these two did, But it is possible.

And one of them got through those challenges and is providing great benefit. I want to make sure that's clear. Senator Wielekowski. And I'm just trying to figure out how a company, how a pipeline company deals with the situation where they initially, they buy their gas, they sell their, they have gas contracts. They estimated it to be $3.5 billion, it turns out to be $9.6 billion.

Like, how does that project—. Who—. I mean, I'm just—. What's—. How does that project deal with the economics of that?

It seems like it just blows the economics to pieces. How does that stay financially viable at that point?

You know, it's, um, I've seen economic modeling of of large projects before, and I've seen sensitivities performed based on changes to the ultimate construction cost. And it just depends. You know, it's— it depends on the contracts that exist with the, in this case, LNG off-takers, or their contractors, or gas producers. You know, is some of that capital cost overrun risk shifted to some of those other entities?

It depends on the ROE that they begin with. You know, does it leave room for some capital cost overrun? So, you know, projects that do come in twice what are expected can still earn a level of return for owners. Granted, maybe not what it was originally planned to be, but still can earn return.

Senator Dunbar. Thank you, Madam Chair. And I unfortunately have to step out, but I wanted to ask one question before I go. And I apologize if this is later in the slides, but, you know, we're in sort of a unique position where we have a state corporation, AGD, ABC that is invested in this project, uh, not sort of literally at this point, a co-owner of 8 Star. And a couple days ago, um, someone from that organization was speaking to us about, um, their cost estimates.

And there was some challenge about, you know, $46 billion, $53, $57 billion. And they spoke about how they're going to get a new cost estimate soon, and I apologize if I use the terminology wrong, it was either Type 2 or Level 2. What was that? Class 2. Class 2.

Thank you, Madam Chair. So Class 2 estimates, and then that would bring the band of possible outlays down to about 15%, I think, you know, that they'd be— they could get into that zone where they're certain that it would be within 15%. How certain are you that once we get that Class 2 estimate that 15% is the upper limit of possible cost overruns?

Jeremy, do you want to take that? Uh, sure. Uh, thank you, Senator Dunbar. Uh, Jeremy Clark for the record here. So the, the Class 2 estimate refers to the AAAC International, which is kind of the industry standard for a lot of project control-related efforts, including cost estimation and schedule development and all everything related to that.

They, they have a kind of graduating scale where, as you kind of refine your estimate, you build up from a Class 5, 4, 3, 2, 1. And the idea is that as you gain more detail on the project, as it gets more developed, more refined, your confidence in the estimate increases because you have that greater data and greater certainty. The—. They also do prescribe those suggested estimate accuracy ranges for the different classes of estimate. With those estimate accuracy ranges, the key qualifier is the— really the quality of the estimate itself.

You know, what were the inputs, what were the assumptions, what type of risk exercises were modeled to look at, you know, the potential impacts to the project. So with a higher-risk project, you're more likely to have pressure against those upper bounds than you would on a lower-risk project. And again, it's all related to the estimate inputs and the quality of the estimate that's going to really define that ultimate accuracy range. Follow, Madam Chair. Senator Dunbar.

Thank you, uh, Mr. Clark. So just before I go, would you consider this a high-risk project? And can you give me some kind of metric, a letter grade, a percentage, something where you can, you can help us conceptualize what, uh, the likelihood is that that 15% upper limit holds after that Class 2 estimate?

Uh, thank you, Mr. Dunbar. Um, I would say this is certainly a risky project. You know, we've highlighted the risks associated with mega and gigaprojects. All those would definitely apply here, you have, you know, the Arctic terrain that you're crossing with the pipeline that has its own slew of challenges associated with it.

Relative to being within that upper bounds of the estimated accuracy range for the estimate, it would really— I'd be hard-pressed to make an opinion on it without having really kind of insight into their types of risks that they modeled and the assumptions that they used into the estimate. Follow-up, Senator Dunbar? Thank you, Mr. Clark. I think we are in a similar seat as you, and we look forward to seeing that Class 2 estimate. Thank you, Madam Chair.

Thank you, Senator Dunbar. Senator Myers. Thank you, Madam Chair. So, um, you know, sitting in Alaska, you know, we're kind of We've got two projects to compare. We've got TAPS and then we've got the current project before us.

TAPS, wildly over budget as everybody knows, but the oil companies were willing to accept that over budget because they weren't making money off of the pipeline. They were making money off of the sale of the oil itself, whereas the current project, project developer separate from the producers, so they're going to be a lot more risk-averse, I guess, when it comes to the, the capital cost overruns. So what were— of the two that we've got in front of us here, Mountain Valley and Atlantic Coast, what were the ownership structures there? Are we talking developer, uh, producer, different, something different?

Atlantic Coast Pipeline, uh, really shippers, I would say.

Electric and gas utilities. Oh, okay. Were the primary owners on that. Um, Mountain Valley Pipeline, Equitran was an owner, and NextEra was an owner. And so I would, I would say midstream companies, if that's helpful.

Oh, that's interesting. Okay, thank you. And that speaker was Mr. Miller. Further questions on this, on the slide pipeline case studies? Senator Kawasaki.

Yeah, this is, this is really interesting because, um, you know, we've told, we've been sort of told, and I just assume it's concluded, that we have these permits in hand and that there won't be any sort of potential for litigation. And, um, I guess I was just Googling the Atlantic Coast Pipeline and some of the litigation that followed, including, um, including some of the— well, it looks like there were parts of it that didn't, um, that were going to cross an area disproportionately impacting Native Americans, it only proposed, uh, located 1 mile from the proposed route, and the percent of Native Americans in that area was only 13% of the base population and only 1% of the total state's population. That was part that led to eventually the courts, the Fourth Circuit, going all the way There was also brought before the courts the exaggerated claim of job creations in West Virginia, brought up as part of why the project wasn't necessary. And finally, just that the volumes weren't proved out to be necessary for the project to have been sanctioned. And so it looks like it went to the Court of Appeals, where they ruled in favor of the groups.

And I'm just curious, 'Cause again, I've sort of foregone conclusion, we've got the permits in hand, so we're good. But you're—. This like kind of freaks me out a little bit that, you know, it could still come to haunt us if we don't have enough jobs that we said we were going to do or we don't have the volumes that we expected we're going to have. Before you respond to that, could I ask anyone who's online listening in to please mute themselves? We're getting a little background noise.

Mr. Miller or Mr. Clark?

Well, I would just— I think, you know, permit durability is important. I think that's the point we want to make. Durability in terms of can it stand the test, a legal test, in terms of the foundation of that permit being issued.

Pipelines get permitted, pipelines get completed. There were very significant challenges on, on these two. Um, so I, I don't know the level of rigor behind the permitting. I don't, I don't know what kind of challenges could be awaiting this project, but, um, certainly that's— it's possible. I will say these And he's got tremendous challenge at every turn.

Thanks. Thank you. Thank you. I will comment that we did find a 2020 EIS that was issued to FERC. It's about 200 pages long.

Very interesting to read the recognition of the impacts to the local areas, air quality, Caribou movement on the north slope, traffic, interesting contents, probably pretty typical EIS. I would share that we have someone on our team that has 40 years of pipeline experience and led a team of pipeline project managers, and he reviewed that EIS for this project. Was, uh, complementary of the amount of engineering that went into that. Um, and so we know additional engineering continues, but I just wanted to pass that along. Thank you, that's really helpful to know.

Um, I would pause here and just see if perhaps Senator Rauscher, who's online, might have a question. If the LIO could unmute him and find out Senator Rosier, do you have a question?

My questions were asked and answered by Senator Murkowski. Thank you. All right. Thank you very much. I think we're ready to move on to the slide that is titled "Phased Approach Introduction." Sure.

Thank you. This is Jeremy Clark again for the record. So we're taking now a look— this is just to introduce the phased approach discussion for the Alaska LNG Project. And you can see from the AGDC quotes on this slide that the intent of the phased approach was to quickly provide gas to Alaskans, reduce project risk, and increase the outlook for the LNG export investment. Under this phased approach, the pipeline execution would start ahead of the gas treatment plant and LNG terminal.

Based on information from AGDC, it suggested the phased approach could deliver first gas roughly 2 to 3 years earlier than the full program approach.

We note that, you know, when they introduced this, they were targeting first gas in 2029, so presumably that has been pushed out along with, you know, everything that has kind of shifted.

If there are no questions, we can jump into the next slide. We continue the phased approach discussion. I see no questions. All right, so some considerations around this phased approach. Any strategic change, like splitting the project into phases, will influence the risk profile of a project.

Project, ideally lowering the overall risk but certainly changing the risks, which may involve some existing risks being mitigated as well as some new risks that may emerge as a result. As AGDC recognized, the phased approach does reduce the initial capital for the project and provides earlier in-state gas delivery, but it does also introduce structural risks as the economics of the pipeline are tied to the LNG export import revenue. So Phase 2 is delayed, it would further increase that risk.

And on the execution side, essentially the same risk exists for the pipeline whether it's delivered on a phased approach or not. It's, you know, the same technical requirements, same terrain, same labor requirements. There's a potential that doing the phased approach would reduce the overall labor burden to the project by kind of staggering it. But that also does introduce waves of resource-related efforts. We'd have multiple waves of logistics, labor camps, community impacts, etc., and then the potential for a longer overall duration as well.

Any questions on this slide here? Senator Clayman. I think this is a— I'd say this— well, it's a follow-up on my earlier question about what's the end plan. And if you're going with the 3 phases, any delays in Phase 1, any delays in Phase 2 make the completion of Phase 3 get further and further away. And if that's the financial— financial reward at the end, doesn't having those phases actually make it even more complicated with the mega project risks because they're the 3 phases than you would have if you only had 1 project and you could get to the end of Phase 3 more rapidly?

Senator Clayman, yeah, that is, you know, something we, Joe and I, discussed while we were, you know, reviewing and preparing for this slide. There's a number of trade-offs on this approach. It's impossible to say ahead of time which one, you know, is more advantageous. Doing the pipeline first, you know, as AGDC recognized, reduces the capital investment up front, but it does induce— introduce those risks if the later phases of the project are delayed or possibly not even started. Because of the staggered FIDs that these phases also have.

So there's a number of trade-offs involved, is the ultimate answer. And that was Jeremy Clark responding to that question. Did you have a follow-up, Senator Clayman? I did. So again, in the kind of the mega project analysis, let's assume a scenario in which Phase 1 gets completed, but then for whatever reason they don't go forward on Phase 2 or Phase 3, or they get started but problems arise and they stop both of them.

Is Phase 1 now completed even— does it become viable for anything, or does it become a complete loss?

This is Joe Miller. I would say that's an interesting scenario. It appears that splitting them in this manner and starting one early could lead to just Phase 1 getting completed. You know, the export facility and the gas treatment plant are very large complex projects on their own.

One question we have is, is Phase 1 financeable on a standalone basis? Can you, can you kick off construction of Phase 1 without having the overall program financing in place?

And I thought there was interesting information provided by Dan Stickel Department of Revenue, where he has done a level of analysis and related to Phase 1 in-state gas supply cost and put that on the order of $12 to $13.

I was encouraged to hear that kind of number relative to the cost of alternatives, primarily LNG importing. It's good to hear it was generally on par with that. I wondered what kind of volumes that was anticipating. That price has everything to do with volumes. But, um, I think I'd also heard in, um, I don't know if it was from AGDC or Glenfarm, that for Phase 1 there might be some pushing out of Phase 1 costs in terms of their amortization so that those costs more aligned with the LNG off-takers since that overbid relative to the in-state needs was more tied to them.

But if, you know, the Phase 1 contracts do not cover the Phase 1 costs, that sounds like a very difficult financial situation.

You know, another consideration is, you know, FERC approved this based on it being an LNG export facility. And so, you know, if only Phase 1 was completed, FERC would have effectively approved an intrastate pipeline. And I know that's not the intent of the project team. They've never— I've never heard them communicate, you know, this not being one complete program that they're focused on. But those are just a couple considerations.

There could be benefit in doing it earlier on that previous slide, it, you know, it does show that, you know, at least in 2024, they believe phasing it could get that in-state gas flowing 2 to 3 years earlier than otherwise.

So just some considerations.

Follow-up, Senator Clayman? Let's assume, assume that the pushing some of the finance for Phase 1 into later phases that have better economic prospects than Phase 1, assuming you don't have that shifting it to the later phases to fund. And so Phase 1 essentially has to get funded on its own merits. What's your perspective about whether Phase 1 could get financed on its own merits, at least what— on what you know today? I think that financing would need to be based on the amount of gas supply contracts, how firm those contracts are.

Um, and so, you know, I would defer to Dan Stickel. I've had an appreciation for the modeling that Mr. Stickel has done, and I think it's been very informative. But, um, you know, in terms of volumes, we've heard that Donlin may be pursuing or is in discussions relative to a demand of maybe 50 million cubic feet per day. Um, you know, NStar's average demand is on the order of 100 million cubic feet per day. Um, so that would be 150.

So we're not sure if the $12 to $13 was based on 500 million cubic feet per day or 350 or what that was based on. But, and we've heard it communicated that Phase 1 may cost $16. I think we heard that in a previous committee. And that that would go down to $5 if Phase 2 was completed.

Senator Klimas. So just to summarize, it would seem that, you know, a pretty high volume would need to be established on Phase 1 for that to be viable on its own.

Senator Kawasaki. No question at this time. Further questions? All right, we'll go on to the slide titled Gas Supply Risks.

Thank you. And this is Jeremy Clark again for the record. So we've understood that the Southcentral Alaska supply was particularly strained this winter and continues to remain tight for the immediate future. So we've taken a high-level look at the key risks associated with the three primary gas supply options of Cook Inlet production, the Phase 1 pipeline, and the LNG imports. For the Cook Inlet production, the key risk is really the gas availability itself.

You know, many studies have been done over the years highlighting that the production is declining and recent exploration success has been limited. So, again, the supply is the key risk from the Cook Inlet production option. For the pipeline, it's obviously a high capital investment and has more uncertainty in the schedule for meeting the needs, the in-state needs. So it's really the timing and the project costs represent the key risk there. And there's, you know, as we near FID, there's That's a big milestone for the project, but there's also a large gap between getting to FID and getting to COD as well.

And then on the LNG import option, it offers lower capital costs than the pipeline, but then you add the increased exposure to the market price risk for the gas.

Any questions on this slide here? Senator Myers. Thank you, Madam Chair. So, um, gentlemen, this, this slide to me kind of illustrates, I think, why Phase 1 is viable. Um, kind of, let me, let me just kind of run through my thinking here, and you please tell me where I, where I get anything wrong.

Um, so what I see is that the, the change in the Cook Inlet production, the lack of production there, is, is really the key that has, has made things viable because you, with, with a lack of gas, you either have to build a pipeline or you have to do imports. Those are your, your effective alternatives. The price of the imports, the price of the imports effectively puts a cost ceiling on Phase 1. So as long as Phase 1 can, can reliably get completed to make the gas cheaper than the imports, then it's, it's viable. The difference from a consumer perspective with Phase 1 versus imports is Phase 1 provides effectively a ceiling on how high your gas price can go.

It might be high right now, but it's got the possibility of coming down as you bring on more volume. You mentioned Dawnland in particular has come out, but, you know, might be other possibilities as well. You know, whether we talk the agrion plant or something like that. But then the imports, on the other hand, if we, if we, if we make the decision to just rely on imports instead, rather than providing a price ceiling, now you've provided a price floor. So that might be slightly better right now than phase 1.

But because, as you point out, we don't have any control over the gas supply cost, you know, and we've just seen in the world markets what can happen there. That's got nowhere to go but up, effectively. So is that a proper analysis of the situation of where we could stand if Phase 1 is as far as we get?

Uh, Senator Byers, this is Jeremy Clark on the response. That, I think, was a very fair assessment. I would just add that the pipeline does have a high degree of schedule risk. So the timing of when that pipeline will actually be completed and the gas flowing is very uncertain. So that, I think, is just one point that I would highlight.

Okay. Follow-up, Senator Myers? Yeah, just to say, to offset that risk in terms of gas supply for South Central, you know, we've got two possibilities of import projects that we're talking about. One would be the very large one that Glenfarn and Enstar are getting together on, and the other being a much smaller one that Harvest is putting together from the old, uh, from the old Conoco, uh, or Phillips, or one of the two of them, one, the old Phillips export terminal from the '60s, um, which my understanding is on the, on the second one, it's, it's much smaller but it can be completed much faster. And so that kind of removed— well, while we still have the uncertainty as to when the pipe going to be done, that at least removes some of the uncertainty for the gas supply in the short term for South Central.

Is that accurate? Senator Myers, yes, that is our understanding as well. Okay, thank you. This is Joe Miller. I would just say initially when we came onto this project, I didn't understand the pursuit of both Alaska LNG and the LNG importing, and I've since developed an appreciation for the pursuit of— the potential pursuit of both.

Um, the LNG importing options, uh, being more— being lower risk in terms of getting those completed in a timely fashion versus the LNG export facility. And so, and I have an appreciation for what I'll call the Glenfarm LNG project in it being able to provide short-term relief and then much of that equipment being able to be used for the LNG export project as well. And so we know that gas supply is tight in Alaska. You're coming through an extremely tight winter, and we've heard testimony and read reports showing the next few years are tight. And so we have an appreciation for how LNG importing and the Alaska LNG Project could work together.

Very good. We have about 20 minutes left. I think we're ready to move to the title slide. Trans-Alaska Pipeline System.

Thank you. This is Jeremy Clark for the record. So as we noted on the key gas supply risks for the pipeline included the capital cost of the pipeline and overall execution uncertainty, we now look at the challenges and resulting cost overruns on the TAPS project. So, the TAPS project, while constructed back in the mid-1970s, faced many of the challenges that still exist for the Alaska project today: varying groundwater, underground conditions, the permafrost, and lower-than-planned productivity. These were all site-specific related challenges that are very applicable to the the Alaska LNG project.

The construction cost overruns that resulted generally related to underestimating costs, required scopes not in the initial estimate, inadequate contingency to address the risks, and no escalation in the estimate, while they also faced a 4-year delay to the start of construction. So right off the bat, they were facing some significant cost pressures there. And this highlights the importance of having thorough estimating processes, including the independent reviews to validate the estimate. It also raises the importance of having robust risk assessments to inform how much contingency is included in the estimate, as well as how much float to have within the project schedule.

Any questions on this slide? I see no questions.

So moving to the slide that says Lessons Learned. All right. Yes, so the GAO conducted a study of the TAPS project and identified several lessons learned that are particularly relevant to nearly all megaprojects. And they also specifically included a note that the experience gained from the TAPS should be applied to projects like the Alaska LNG project.

These lessons learned include incorporating as much project-specific data as feasible while having awareness of existing uncertainties and other risks. It also ties government approvals and expenditures to detailed planning and ongoing government audits. On the planning for the TAPS, the issue was really on the cost control system. Systems itself. Again, this was back in the 1970s, so the project management systems have come a long way since then.

I doubt that that would continue to be a risk. It was more the number of parties involved in the project and consolidating all that data under one system, but again, IT systems are well capable to handle that today.

On the future project the expenditure should have an ongoing government audit note. That really related to informing the degree of costs that were recoverable through tariffs and understanding the resulting cost impact to customers.

And concerning the note of viewing the cost estimates with skepticism, as we've discussed, you know, there's a multitude of factors that can influence the estimate accuracy. One factor relevant in particular to mega and giga projects is the multi-year development efforts ahead of multi-year execution. So even just general market conditions changing over those periods, which is often the case, can have large impacts on the ultimate cost of the project, not to mention the— all the other project-specific risks.

Any questions on this slide here? Yes, Senator Myers. Thank you, Madam Chair. So regarding your last bullet there about government audit to protect the public's interest, we did have some testimony here a couple of days ago about how the gas contracts between Glenfarm and Enstar would have to be approved by the RCA likely before even construction even started. And so that the potential cost overruns most likely would not be able to be easily passed from Glenfarn onto the end consumer.

Do you believe that that is an adequate protection?

This is Joe Miller. First of all, we were very glad to hear that from Glen Farm, that capital cost overruns would not be passed on to customers. That was, I would say, our largest concern coming into this. And so that just needs to be memorialized in some fashion, um, either in the contract between NStar and the project, or through the RCA process, or through legislation. But it needs to be memorialized in some fashion.

But it certainly reduces risk for in-state customers. Follow-up, Senator Myers? No, thank you. Senator Kawasaki? Yeah, thanks.

I asked the question earlier about how litigation had stopped one of the other projects down down south. And I'm curious because TAPS was done just after the NEPA was done. So are there— I mean, we're kind of in a different era. It seems like things get litigated a lot, especially in Alaska. And so I'm just curious if we should discount for those types of things to happen past tap, past TAPS?

What types of things again? Any sort of, uh, through the chair, any sort of litigation that might occur? Because during TAPS, I don't know if there was a lot of litigation, to tell you the truth, but it seemed like there were— there's more now than there was 30 years ago or 40 years ago.

Certainly.

I'm not sure I have a sense of that. I know there was a tremendous focus on fighting the pipelines that were being developed to get gas out of that northern Appalachian region. The gas that is being produced in that region is very cheap in terms of the commodity. There's just difficulty in getting it out of there. And so, you know, one change that has occurred has been instead of bringing lawsuits against producers and, you know, against each wellhead, so to speak, they found it to be more effective and efficient to fight the pipelines that are getting high volumes of gas out of that region.

And so But I don't have a sense of what the opposition and litigation might be on this type of project. Thank you. Senator Clayman. I want to follow up on your answer to Senator Myers' questions, um, specific to— there's an assurance that the Alaska consumers won't be asked to pay cost overruns from Phase 1. And let's assume that that's true, that the consumer will not be asked to pay for the cost overruns.

From the business standpoint, doesn't that actually put greater pressure on Glenfarm in terms of what it's doing if it doesn't have an avenue to collect the cost overruns or some means to get those paid? Doesn't that put greater pressure on Glenfarm as they go forward if they get to a point at which they they realize it isn't working, costs are getting high, does it create a greater likelihood that they stop construction even sooner? They get started a year in, they suddenly realize costs are going way up, there's no way to collect those costs, and then I say, well, this, this project's dead.

Yes, uh, certainly provides greater risk. And so that increased risk would go into negotiations with potential financing counterparties.

Follow-up? And likely ultimately—. Wouldn't that be—. I was just going to say likely would ultimately show up in a risk premium in terms of, you know, expected return. So what they would potentially see is that the people that would be lending money for the project might very well raise the interest rate significantly because they see a greater risk because there's less avenues to pick to cover additional costs that may arise in the course of the project?

Yeah, I would say all else equal, you know, greater perceived risk would come with a greater expected return. Senator Myers. To follow up on Senator Klayman's line of thought there, It sounds to me like effectively what you're saying is, well, uh, you know, having the, the, the gas contracts and everything finalized early on could potentially raise the financing costs some. Uh, I don't want to say a little, little, little or a lot. I'll leave that up to, to your judgment.

But it could potentially raise the financing cost some. It also gives us a greater assurance that once the project gets started, it's going to get completed too. Is that accurate?

Uh, could you, could you restate that question and make sure I understood? Yeah, yeah, Myers. Yeah, thank you. So, um, what I'm, what I'm trying to say is, is, um, going off of what Senator Clements, uh, was, was asking about in your response to it, it sounds like while greater assurance that the cost cannot be passed on to the consumer because of RCA regulation could potentially raise the financing costs to some extent, it also gives us greater assurance that if the project goes to FID and gets approved and the construction commences, it much less lowers the risk of having massive cost overruns and lowers the risk of the project not being completed in the manner of the— what was the— the Atlantic Coast Pipeline because the contracts have already been finalized, and so they already know ahead of time that they have to have all of this stuff accounted for before they get started. Is that accurate?

I think that's fair. Not— this is Joe Miller. I think that's fair that, you know, not having a regulatory situation where cost overruns can be passed on to customers, uh, puts more motivation on the project team to get it accomplished in the time frame and on the schedule originally envisioned.

Thank you. Senator Clayman, I will point out we do have a hard stop at 11 with a floor session. Senator Clayman. Thank you, Madam Chair. I guess my query, if you're locked in On gas price, if you've got contracts in place at a certain price that justifies the project going forward and you have no means to go to the consumer to cover cost increases, on the one hand, that gives an incentive to get it done on time and under budget or on budget.

But the flip side is that if you already fixed in your gas contract prices, you have almost no room to move if you do have extra expenses. That doesn't necessarily make it more likely. It just means if you have the extra expenses, there's no place for the company to go because you're locked in your gas price and you can't go to consumers to pick up the difference.

Am I missing something?

This is Joe Miller. I would say it just has everything to do with the assumptions in the economic modeling and how those various contracts are structured. And their thoughts on the future market value of exported LNG.

All right, we'll move on to cost control strategies now.

Uh, thank you. This is Jeremy Clark again, for the record. So at the highest level, the project owner, the main contractors, and the end user end users— sorry, collectively— each have exposure to the project cost overruns. Between the owner and contractors, the construction contracts provide the mechanism for which cost overruns are allocated, and between the owner and end user, tolling and sales agreements similarly provide the mechanism for which cost overruns are allocated.

Ideally, the contracting approach should support the strategic vision of the project's owners while providing alignment amongst the contract parties and allowing adaptation to complexities and uncertainties. And the better aligned the stakeholders and partners are, the more prepared they will be to address and mitigate risks.

Practices for aligning stakeholders and partners include early engagement of key stakeholders, shared governance, collaboration, shared financial incentives, risks and rewards, and a no-blame culture of open communication amongst the key stakeholders that works towards supporting common goals and objectives.

Any questions here on this slide? Any questions? I see none.

And that looks like your last slide. Thank you very much, gentlemen. Do you have any closing comments?

None from me.

Uh, none for me as well. I just can— well, one minor comment, uh, the stakeholder management. I would just continue to work to get the parties aligned that it's important to the success of the project and for everybody to reach their objectives. Very good. That is something we are aiming for.

So thank you very much for your presentation today, gentlemen. Um, that brings us to the end of our meeting. I do want to follow up on a question, uh, we had for the Department of Law. So on Monday, Senator Myers asked if Fairbanks had an LNG spur line owned by the Interior Gas Utility, a municipally owned utility. How would it be taxed?

Parker W. Patterson is the Senior Assistant Attorney General. His response was, under the Alaska Constitution, Article 9, Section 4, it states the real and personal property of the state or its political subdivisions shall be exempt from taxation. AS 2945.030(a)(1) codifies this constitutional requirement stating that a municipality must be— must exempt property owned by the municipality, state, or federal government from ad valorem property taxes. Because the state and municipalities are constitutionally barred from taxing each other's property, any spur line owned by a municipal utility is automatically exempt regardless of whether it falls inside or outside the new alternative volumetric tax framework. So I wanted to read that into the record.

We have gotten that reply on the taxation issue. We will also be having RCA, uh, speak to us next week concerning the regulatory questions that we've had. Um, I've spoken to them and there's some very interesting answers. Uh, so this concludes today's meeting. Our next meeting will be tomorrow, Friday, April 17th at 3:30 here in the same room, and we will have these same bills under consideration.

At this time, the meeting will stand adjourned. Let the record reflect the time is 10:57 AM.