HFIN-260527-1330

Okay, I'm going to call this meeting of the House Finance Committee to order. Let the record reflect that the time is currently 1:36 PM on Wednesday, May 27th, 2026. And, uh, present today we do have Representative Allard, Representative Stapp, uh, Representative Moore is online, uh, Representative Bynum, Representative Kocher-Schragg, Representative Kocher-Josephson, Representative Jimmy, Representative Galvin, Representative Tomaszewski, Representative Hannan, and myself, Kocher Foster. And Just a reminder, folks can mute their cell phones. We do have a number of legislators out in the audience as well.

We've got Representative Holland, Representative Mears, Representative Colon, Representative Mena, Representative Costello, Representative Johnson. Did I miss anybody? Thank you all for being here today. And before we start, let's see here, we only have one item on the agenda today, and that is House Bill 381. That's the Gas Line Bill, and we do have a presentation by the Alaska Gas Line Development Corporation, otherwise known as AGDC.

And so it looks like we've got two folks here today. It's Frank Richards as well as Matt Kissinger. And if you can maybe both put yourself on the record and thanks for being here today. And maybe let's see, I see— maybe if you could just note your positions at AGDC as well and kick us off. Thank you, Mr. Chairman, members of the Finance Committee.

My name is Frank Richards. I'm the president of the Alaska Gas Line Development Corporation. Good afternoon. I'm Matt Kissinger. I'm the commercial director for Alaska Gas Line Development Corporation.

Mr. Chairman, today we are going to provide a presentation that is somewhat of an update, but also to provide some history about AGDC and the role that we have played, but also in terms of the advancements that have been undertaken for the Alaska LNG Project while it has been under our responsibility. So we wanted to make sure that we were providing some background, but also addressing some of the questions and the issues that have been raised during most recent hearings. So we've been listening, we've tried to follow what the committee's concerns were and be able to present that in today's presentation. So, with your indulgence, we'll proceed forward.

So for the committee and for those online, the AGDC, the Alaska Gas Line Development Corporation, is a state corporation that was created by the Alaska State Legislature in 2013, really at the time to be able to take on the mission to look at the opportunities to bring North Slope natural gas for use within Alaska, meaning interior Alaska and Fairbanks and the North Star Borough, but also in Southcentral Alaska to be able to meet the concerns concerns at the time of the declining Cook Inlet reserves. So it was the opportunity for the state to create an organization that had the responsibility to look at the opportunities to number one, develop a pipeline, and number two, to ultimately be a participant in the state's interest in what will— was to become the Alaska LNG Project. So the mission that was granted or provided to us by the legislature was really to maximize those North Slope natural gas resources. Through infrastructure development. So when we talk about the Alaska LNG Project, it is really an infrastructure project to be able to allow those molecules to flow from the North Slope down into Alaskans in Alaska, and ultimately for— to monetize that gas for the international markets.

So it was in 2013 that they originally created us, and in 2014 with Senate Bill 138 provided the additional responsibility to represent the state's interest in the Alaska LNG Project. With our partners at the time, Exxon, BP, and ConocoPhillips. Mr. Chair. Thank you.

I'd like to just note that we'll also have with us Representative Sadler. Thank you for joining us. I'm going to take a question. I apologize, I should have noted we worked with AGDC to come up with some good breakpoints for taking up questions, and we're going to take questions after slides 11, 14, 19, 23, and 30. So I'll pause after those slides.

Slides, but because I didn't announce that earlier, we'll take question right now. Representative Stapp. One more time. Could you repeat those slides one more time? Oh, they're going to be after slides 11, 14, 19, 23, and 30.

And I'll pause and look to the committee after each of those slides just as a reminder. But Representative Stapp. Yeah, thank you, Chair Foster. Through the chair to Mr. Richards and our folks at AGC. So I went through the whole slide deck real quick.

I didn't see this. Yesterday we had a discussion, kind of a back and forth about what the state's financial liability would be in the event that Glenfarm failed to move forward on FID. And my understanding is they currently hold all financial liability for the project. This is not going to be another TransCanada. And I was hoping if you guys could just take some quick time to clarify that, and then you can give it back to the origin story through the chair.

Mr. Richards, through the chair, Representative Stapp, you are correct. In the definitive agreements that we signed with Glenfarm and provided them 75% ownership rights, it was that Glenfarm would carry AGDC in the state of Alaska through to final investment decision, meaning there is no additional funding necessary for the state of Alaska to advance the Alaska LNG project with Glenfarm. A'ah. Okay. I have a question.

Let's see, while we're on this subject, we'll do a follow-up. Representative Galvin. Thank you. This is just a follow-up to that very issue because we just want to make sure you have it all out there. So under any circumstances or any scenario, would AGDC or the State of Alaska need to, or at any moment, have to return funds or give funds to Glenfarm?

Through the chair, Representative Galvin, there is not an instance where AGDC has a financial responsibility to repay any expenses by Glenfarm. Okay. I think that—. I think we have one more. And Representative Pannon.

Thank you, Chair Foster. We're going to ask it a third time in a different way. Just Believe it or not, we're getting comments from people who say, we're aware of this, and so we want to make sure that on the public record, we've asked the question so that we're showing that we heard you. And that is, if this doesn't go forward, we don't owe Glen Farn any backout fee, any— whether it was an expense or a promise. But if the project for some reason doesn't come to fruition, AGDC is not on the hook nor is the state of Alaska for any financial contingencies or costs.

Through the chair, Representative Hannon, you are correct. I mean, I heard the reference yesterday to a GIA, and that was again a contract between the state of Alaska and at the time TransCanada that was also had a specific statute associated with it that identified a dollar amount and a repayment structure. That is not what we have with Glenfarm. We have definitive agreements that set out the, the contract terms that for 75% ownership rights that we provided to Glenfarm, they then took on the financial responsibility to move the project through to final investment decision. That meant that they were going to take the project and all the project components through the front-end engineering and design, continue the regulatory permit compliance process, go out, contract for gas sales and gas offtake agreements, as well as bring in— have the opportunity to bring in other strategic partners, which they did.

If you recall, AGDC over the preceding years had been seeking strategic partners, and we identified we were looking for $150 million to be able to accomplish that, to get us to final investment decision. Glenfarm signed up and took on that responsibility, and that's what they've done. Mr. Kissinger? Yeah, if I may add, this is Matt Kissinger for the record. Perhaps some of the confusion comes from the beginning of last legislative session last year when there was discussion of this backstop.

Some people referred to it as the ADA backstop, etc. These discussions were done separate from our discussions with Glenfarm and ultimately in our negotiations with Glenfarm. We came to an agreement where that was not necessary. So that was discarded. Representative Hannon.

Thank you, Chair Foster. Mr. Kissinger, thank you for putting that in such succinct language because I think that is probably where it stemmed from. And since we've not been party to the contracts that you sign, and when we last heard it on the official open record, it was, mm, there might be some backstop, maybe it's ADA. And then ADA is saying, "No, we don't. We're not a party to this." So, you know, sometimes the absence of information creates an illusion that there's something being left out.

So I appreciate you going all the way back to that, which I think is probably the origin story because the public record had that talked about before you went into contract with them, and we want to make sure that it's not in there. I'd also like to note that we have with us Senator Gray Jackson. And also Representative Aishide, thanks for joining us. And Representative Galvin. Thank you.

And I'd just like to follow up again, just to kind of COVID all of our bases. You'd mentioned the $150 million, and I appreciate that. And I know that so much energy and resources has gone to putting together all of the permitting and everything else that has been done by your organization. So I'm going to ask just a couple of questions. Can Glen Farm demand that we buy them out if we don't get there?

And what about the exit if there is no FID? And how do we get that 75% back if there is no FID? And I appreciate this is a Probably not in your slides, and that's why we're trying to get this out just to clear the air before we get into our deeper discussion. Thank you, Co-Chair, for allowing this discussion. Mr. Kissinger.

This is Matt Kissinger again for the record. Representative Galvin, through the Chair, the developer, so Glenfarm, they have a requirement to undertake diligent development efforts, and we have diligent development efforts very carefully defined. I think there are 8 8 or 9 different distinct things that they have to do, such as maintain the permits, for example, not allow them to expire. They have to do that, which means expending serious amounts of money, which is really what we were trying to achieve with Glenfarm. We were trying to get them so heavily invested into the project that we were kind of on shoulder-to-shoulder terms, which is— we do believe that that's where we are getting.

If they no longer wish to pursue diligent development efforts and spend money then they need to exit the agreements or default out of them one way or the other. But there is not a provision in there that would require us to buy them out in that instance. No.

Okay. And thank you for that. And last follow-up, if I may. Representative Gilbert. Thank you.

This is— so there's been— I think there was a document that was floating around. I don't even know where it came from and marked confidential, and it's it had something about, I guess, how that default out would look. But to your recollection, there is nothing there there with regard to any— the default out point won't be anything that's left on Alaska holding a bag for anything that you're aware of. Is that correct? Mr. Kissinger.

Mr. Kissinger, through the Chair, that is correct. Thank you. Okay. And just for the record, that was Mr. Kissinger. I think that was a good question to get out there.

I think that was one that everybody was probably wondering about, and so good that we had that discussion. And so with that, please proceed with the presentation.

So, Mr. Chairman, again, Frank Richards. For the record, just to provide the— a basis point for those online or watching, we're here to talk about the Alaska LNG Project, and that has been our primary mission since really since the legislature gave it to us. And ultimately, we closed down the in-state project back in 2015. So that's what we've been working on diligently. What this project is, is a very large mega project that is comprised of 3 main subprojects.

It requires the gas on the North Slope to be conditioned through a gas treatment plant. That has been called by AGDC previously the Arctic Carbon Capture Plant. And that was really a marketing term at the time when, again, under the Biden administration, there was a lot of opportunity around looking at carbon capture. But it is one and the same. So on this slide, you'll see gas treatment plant, aka Arctic carbon capture, is one and the same.

It's one plant. It removes the carbon dioxide and hydrogen sulfide from the gas streams coming from Prudhoe Bay and Point Thompson Gas. Those are the two primary units that this project was designed on, and it's what we went through the permitting efforts for. That represents between approximately 40 trillion cubic feet of gas between both units, and that's enough for 30 years of production from this project. That treatment plant, again, will remove the CO2.

It will be then captured and then sequestered back into geologic reservoir. For about— to the tune of 7 million tons per year. This has always been the design concept, and with it then, there's the opportunity to utilize what is known as 45Q tax credits. Now, that doesn't mean this is truly a revenue-generating aspect of the project, but it reduces the overall cost if we can utilize this CO2 as a carbon capture or even oil enhancement to be able to take advantage of some of the tax credits that are currently under the IRS code. The project will then— the gas will flow from the gas treatment into the 807-mile pipeline, which will run from Prudhoe Bay south through interior Alaska all the way to Nikiski.

If there are opportunities for Alaskans or Alaskan resource development or any other new economic opportunities, there are the opportunities for off-takes from this pipeline to be able to help support the economic opportunities and growth within Alaska. Primarily, there's an offtake for Fairbanks. And I know that's been a general discussion, the spur line, and we'll talk about that later. But Fairbanks has always been a primary offtake, as has the existing distribution systems in south-central Alaska, in the Wasilla area and then in the Nakiski area. The terminus of this pipeline is at the liquefaction facility, which is located in Nakiski, where 20 million tons of liquid natural gas will be produced and then sold on the world market.

So I just wanted to, again, give the basis of what is this project. 3 Primary subprojects, so you'll hear us talk about that later: pipeline, gas treatment, and liquefaction.

Now, just to provide a little bit of history, in 2020, AGDC went through what is known as an economic stage gate. And here is where we— the board asked AGDC to make a determination. Was the project economically viable? Were the cost estimates sufficient to identify that it was not going to have Blow the budget. And were there markets available for the cost?

So we provided and went through a process that was called a stage-gate process where we developed information and provided that to our board to say yes. There was a decision support package that identified that yes, all of those three things were met and that it was a project that should continue to proceed. The alternative was if it was too expensive or if the market wasn't there, then the opportunity was to shut the project down. But the board at that time felt that based on work that we're going to describe next, that the project still had good viability. The world markets were there to be able to take the LNG and that it would be a great benefit to Alaska overall.

All right. This is Matt Kissinger for the record. Last time we met, I was, I was online and apologies for the bad connection that time, but I spoke a little bit about this— the different phases of the project that we've been through, and I talked about this economic stage gate, but we thought it would be worth actually pulling out those slides from our 2020 President's Report from our public board meeting and kind of walk through, because this is a real inflection point for the project. The first big inflection point was when the producers left the project. So this was obviously a producer-led project, the Exxon era.

In 2016, they brought in Wood Mackenzie, and they asked Wood Mackenzie to do a competitiveness analysis of the project. And Wood Mackenzie said that the project ranked poorly in terms of competitiveness. And they recommended that we adopt a debt-funded third-party tolling structure rather than what would normally be your IOC, your International Oil Company balance sheet financed project. Project finance had become a common tool in the development of all the LNG projects at the— along the U.S. Gulf Coast. It's a tool that has allowed these smaller, more nimble investors to build the creditworthiness of individual projects and move them forward.

The way it works, if you don't know a lot about project finance, is you don't have recourse through the project sponsors. Generally, when the IOCs used to do big projects, any cost overruns, any default, anything like this, the recourse was straight to their balance sheet. This structure allows banks to have recourse really just into the project, and if these developers fail, the project doesn't necessarily have to fail because it's underpinned by creditworthy contracts. And this is where the shift really went from producer-led to buyer-led, and later I'll call this state-led because that's really what it was at the time. But buyer-led is the approach where you go out to the market, and this is actually what a lot of the developers in the lower 48 did, though, you know, obviously not led by a state agency.

But they went out to Asia, to Europe, and they got these long-term contracts in place. And we worked really hard on doing that same exact thing, but we did it in more of a government-to-government sort of tone. There was a lot of leaning forward towards China. Obviously, China does, you know, represent a humongous growth opportunity for the LNG market. So it was an obvious place to look.

But ultimately, it failed because we didn't have really the right leader involved. So under the producer-led effort, it failed because they just had the wrong structure. The producers shouldn't be building big projects like this. It's not what their investors want. They're looking for higher returns, and those higher returns drive up the cost of capital.

So producer-led failed because ultimately cost of capital and the fighting for capital within these companies. The buyer-led efforts really failed just on the credibility of AGDC running the project and being out in the lead on this thing.

And so there was another inflection in 2019 where we said, okay, we're going to set forth a normal stage gate process, a normal developer's process. We're going to find the right parties to come in. We're going to align everyone. So that's why I called this alignment first. Later, we've referred to this as developer-led model.

But under the alignment first model, we, um, we set out these stage gates and the first one was, should we even progress at all? And let's do an economic assessment stage gate, look at the sort of core numbers and see if this project actually floats. Go on to the next slide.

So we worked very closely with BP and ExxonMobil in this. We created a joint economic model. We had that model peer-reviewed by the likes of Gas Strategies, Goldman Sachs, Exxon and BP themselves. And Exxon and BP also provide subject matter experts and funding to AGDC for the whole year. And the first thing we did is we looked at all the project costs at places that we could optimize it.

There had been a tremendous amount of modularization that had gone on as they developed these Lower 48 projects. And it was observed that as well as modularization worked down there, it probably would even have greater economic benefits in Alaska. And so we worked with—. Great. Exxon BP, and we brought in Fluor.

Fluor is a very large EPC contractor who worked as our kind of owner's engineer. And through the year of 2019, we adjusted the costs. Coming out of the Exxon-led effort, the cost estimate was $44 billion. Coming out of this cost optimization, that had dropped to $39 billion. $19.

So there was inflation between 2016 that was absorbed and the costs had lowered to $39 billion.

If I may, Mr. Chair, Frank Richards. That effort again was utilizing senior Exxon BP personnel who came in with project management experience, process engineering, and cost estimating. So they really rolled up their sleeves and they looked at the the pre-feed cost estimate that had been done with ExxonMobil-led team back in 2017 and said, oh, we have some gold plating over here, like in what it was going to take in terms of the project management costs. ExxonMobil put in their fees, which are extremely high and almost on a 1-to-1 basis between owners, engineers, and the project management team.

So they— we looked to say we can optimize there. We looked at modularization that Matt talked about. We looked at the contingency level based on the level design that we had on the project as well. And that's why they were comfortable in the new rolled-up number at $39 billion in 2019 as opposed to the $44 billion in 2017. So I wanted to just identify that because you'll hear us talk about the evolution of the cost of this project.

So from $45 to $65 in 2012 to $44 billion in 2017 $39 billion in 2019-2020 numbers. Yep. Go on to the next slide.

For this economic stage gate, we set up an evaluation based on the viability of the project, meaning, you know, can it be done, and then the competitiveness of the project. You know, can it be done at a cost that actually is attractive to the market? With respect to viability, it's— It meets all the marks quite easily. We have the resource base. We have a resource base that's under production.

We produce and re-inject enough gas to supply all of Germany every single day up on the North Slope, or enough for all of Japan, or if you want to be U.S.-centric, for the entire West Coast— California, Oregon, Washington. And we know that there are enough molecules of that gas to last over 30 years for this project. We export under 1 TCF per year. You have some in-state demand. But as you saw, there's 40 TCF of gas available, and that's just in the developed known fields.

There's obviously a lot more gas than that. The scope of the project, it is, it is a complex project, but ultimately lots of gas treatment plants have been built around the world. Lots of pipelines have been built. There's 40 or more pipelines this big, this long, and through thousands of homeowners' properties, as opposed to up here where you have actually a fairly simple pipeline. It's, you know, it's difficult terrain, but it's not difficult in terms of the access.

We have all the authorizations. We have the AOGCC export or offtake authorization sufficient to supply this project from both Prudhoe Bay and Point Thompson with room for growth and room for flexibility. We have the Department of Energy export authorizations to free trade and non-free trade countries. These are We have very good authorizations in Alaska. They have longer expiration periods than the ones that were given for the Lower 48.

We have the FERC authorization to site and build, construct this thing under Section 3 of the Natural Gas Act. And then as you look towards the market, there is the market demand for this. The question then shifts to the second part of this evaluation, which is, can it be competitive? And the way we do that is off of cost of supply. So you factor in what your debt is going to be, you factor in what your return on equity and your equity is going to be, you include your contingency so that you're not underestimating your costs, and you come up with what does it cost per, you know, per MMBTU, how many dollars does it take to get over to Asia, and then you compare that with what it takes for everyone else to get over to Asia, and that's really how you do the levelization of that.

Mr. Chairman, if I may, in our slide pack and for those online, at the end of our presentation, we do have a list of acronyms. So if you hear us speaking in LNG speak, there is a list of acronyms that can help you understand. Okay. And just for the record, that was Frank Richards, Mr. Richards, and Mr. Kissinger. So now on slide 8, you can see what the result of You know, the restructuring of the project, that was a huge improvement, as Wood Mackay had estimated these cost reductions.

And then the last thing that we looked at was a lower gas prices assumption. We felt that the producers were going into this with a very high gas price assumption. It has to be noted, this is unprocessed gas. It has CO2 in it to the extent that it's not usable. Point Thompson, around 4% CO2.

Prudhoe Bay up to 13%. To get into a utility system, you need around 2% CO2. It has to do with metallurgies and corrosivity issues and things like this. So these are true technical limits. And when it comes to LNG, you know, you have to take all that CO2 out because the temperatures that you liquefy methane at -263°F, the CO2 would turn into ice and just block everything.

So it's a technical reason why you have to take that out of the gas up at Prudhoe Bay. And then you put it back into the reservoir because you— A, that's— it's a lot of molecules to remove from a reservoir and not put back in for pressure support. And then there's potentially, you know, going to be some benefits from CO2 being miscible with the oil, though we don't fully understand that as AGDC, though we understand the producers have looked at that a bit. When you put all these three together, you get to this new, what we call unoptimized cost of supply. And these are from our 2020 slides that we were referring to this.

And what we meant by unoptimized is we know that there were more ways that we could make this project more attractive. We'll deal with that in a second. But the first question is—. Sorry, good. So we're now on slide 9, and slide 9 is where we stack up our cost of supply based on all that modeling.

And again, this is peer-reviewed modeling and all the other projects that are coming into the market. And we were working with Gas Strategies at the time. Gas Strategies are an intelligence firm out of London. They've done a lot of work like this, quite trusted organization. And we were seen to be right in the middle of the pack.

Now, you know, Qatar, obviously, Qatar expansion is the cheapest gas out there. They don't sell it for the low price. They sell it for the price that your marginal supplier comes in, and that's where you get into your, you know, Mozambique, the high case for some of the US Gulf LNG, which, you know, we've seen a lot of those projects struggle because they are not quite economic getting into Asia. LNG Canada, LNG Canada Phase 1 was quite a skinny project as well, kind of like the way we're structuring Alaska LNG now with Phase 1. But it allowed Canada Greenfield to be more attractive and more of an obvious FID later.

And I think that we will see that ultimately, probably quite soon.

Alaska LNG being in the middle of the pack is probably not good enough because this is such a complex project. You have to have this pipeline. You have to have the— a very large gas treatment plant up on the slope. And you have to bring all these projects together. Together in a way that exposed you to something called project-on-project risk, where maybe you're finished with the LNG plant, but you don't have the pipeline in place, and you've got lenders on the LNG plant expecting their debt to be paid back.

So we had to make it more attractive, and we identified— and go on to the next slide, so slide on page 10— and we identified a number of different optimization, you know, opportunities. But 3 of them really stood out. The first one was what we called state and federal support, such as the loan guarantees, but really it was focused on the loan guarantees. The second one was an even lower gas price, which we have continued to negotiate a lower and lower gas price with the producers. And then finally, even back then, we identified that property taxes were one of the biggest triggers that you could pull.

The loan guarantees we got. So these loan guarantees, when I talk about these, are federal loan guarantees that came about because of the 2004 Alaska Natural Gas Pipeline Act at the federal level. In that act, which was to build a pipeline to North America, we were provided with $18 billion worth of loan guarantees. Loan guarantees means you go out to your lenders, you set out the loan, but then you go to the federal government and they back the loan in case of a default. So the lenders know with 100% assurance that they're going to get paid back.

Because of that, the lenders will provide you a lower cost of debt. And so it has quite an impact on the project by taking down that cost of debt. It also just makes it easier to try and put together that much debt, because this project is really going to stress the debt markets. It will be one of the largest placements of debt in history.

In 2000— I'm still there. You're still there. Okay. In 2022, we had the bipartisan infrastructure law. Our congressional delegation down in Washington amended that original Alaska Natural Gas Pipeline Act so that these loans could be used on this project.

And from October of 2004, when the original act was put in place, these guarantees have continued to to be inflation adjusted with CPI, which puts that at just over $30 billion worth of loan guarantees now. So we have those, they are in statute, you know, have to work through the Department of Energy to put those into place, but at least we can see a line of sight to using them. Again, lower gas price, we continue to negotiate those. Property taxes, though, we really didn't know where we really stood. We just knew that they were high and that everyone who looked at our project said, "Oh, that's weird.

Your property taxes are much higher than we see everywhere else." So again, we worked with Gas Strategies. Can you go on to the next slide? Again, we worked with Gas Strategies. We had them come in and compare it with every other jurisdiction, especially around the U.S., Canada, but also some overseas jurisdictions. And what they found was that our property tax in Alaska, the way it's structured, assured would result in property taxes a whole order of magnitude, so kind of 10 times higher than the next highest.

The next highest that they had identified being Cove Point, Maryland, that had about $50 million a year. I think LNG Canada has around $27 million per year, and if you just go by statute, this project could be well over $800 million a year.

We also had Question. We also— we also had Wood Mackenzie come back in. So they were in in 2016, said the project wasn't economic. We took their advice, we structured it the way they told us to. We had them come back in and look at it.

And this is all online on the AGDC website. And what they said was, yeah, you are— you are now competitive. And there are several levers that really stand out. And again, they pointed to property tax, which You can see on this slide there is the wood max slides out front with this what we call a tornado chart showing you upward and downward sensitivities. And you see that aside from capital cost, the property tax is the largest single impact on this project.

I'll switch over to Frank if there's no questions. Again, Mr. Chairman, Frank Richards for the record. Again, we wanted to just bring this issue back to the Committee really because it was something that In our presentations at the time, both in the public setting and the board, but also in terms of our updates to the legislature, we are providing the outputs from the work by, as Matt said, Gaffney, Klein, and Wood Mackenzie. And it's really— we're trying to show what those levers are. So as he described, the loan guarantee is a very large one indeed to help reduce the overall cost from debt financing.

But in terms of what Alaska can do, it's really around the property property tax and how we are, you know, far out of our field compared to our competition in other portions of the world. So we wanted to bring this back just to really identify that property tax is an issue within the state of Alaska for this project because, again, it's not an oil project. This is a natural gas project. And so the margins are much smaller than an oil project. Okay.

And we're at slide 11. I do have questions from Representative Step. Galvin, Hannan, Tomaszewski. And so first we will go to Representative Stapp. Thank you, Mr. Foster.

Through the Chair, to folks at AGDC, Mr. Richards, etc. Obviously, kind of begs the question, if you have 3 studies identifying that property taxes were a big issue in the project, the bill to restructure property taxes in Alaska in the project didn't come before the legislature, I want to say, until nearly the end of March. So obviously here we are in special session given the time constraints. And I'm just curious if you guys knew about this for so long, why wasn't at least a skeleton structure presented for us last year or year before or year before that? Through the chair.

Mr. Richards. Through the chair, Representative Stapp. Again, in our discussions with the legislature, we continue to identify that it was an action that the state of Alaska would have to undertake. Take. Now, AGDC can only propose and identify what the issues are, but in terms of affecting legislation, then that has to come through the legislature.

So again, should we have been more proactive and more forceful in saying, "You guys need to do this now"? In hindsight, that's probably the case. Unfortunately, though, when we were presenting these, we were also out in the market trying to entice investors coming in. So we weren't at the point where we actually had a developer on the hook working with us to advance the project. So now we are, and we've got Glenfarm working to move this project forward.

We started last year in the conversations initially with the boroughs directly to talk to them about it, and that was kicked off in the fall period and worked its way through. It's unfortunate timing, but again, we find ourselves here again talking about this issue, but it is ultimately to the advancement of this project. Yeah, follow-up, Mr. Kocher. Representative Stell. Yeah, thank you, Chair Foster, through the Chair.

You know, we've had you guys at the finance table for many years now since I've been in the legislature.

I think it probably would have been helpful to give some sort of structure. What we have before us is a volumetric structure. I think it's totally fine because it helps de-risk the project to capital cost overruns. But I still don't see— I mean, it probably would have been helpful, I think, for members of the committee, for you guys, even though I know you were out doing other things, because I remember those discussions very well, to perhaps at least bring a little bit of a framework to us. Because I feel like we are in a position now where we are going to go with the volumetric structure because that is what the developer wants.

But I can't tell you if there is a more inducive structure to get the project off the finish line. So I am supporting this because it is what the developer wants. De-risk the project. But, you know, I haven't looked at any alternative structures and I don't have time to do that. So I'm going to be supporting the structure.

And I'm just saying that, like, hindsight being 20/20 is one thing, but it would have been nice if we had had a little bit of a more of a heads up other than we might have to do something at some point. Thanks. Mr. Richards, through the chair, Representative Snap, thank you for that. Again, the volumetric approach that we are discussing now really came out of ultimately discussions with the boroughs, too. So it was the option, as you know, we talked about our 20-mil rate is high.

We were talking through our work with Wood Mackenzie that maybe a 2-mil rate was appropriate. But in terms of the discussion points with the boroughs, they came back in support of a volumetric approach as opposed to just a straight reduction on the millage rate. Okay. Next up I have Representative Gelvin. Thank you, Co-Chair Foster.

Through the Chair, first of all, I have a lot of questions around the volume, but I think I'm going to settle on these first slides and just ask you a couple of questions on slide 10. Let's see. So you said some very interesting things along with what we're looking at, and I really appreciate HEARING went from $18 billion discussion of loan guarantees to $30 billion, and that sounds very helpful. And it implies, in looking at this, in the first bullet here, that it says state and federal, that maybe the state would be considered a possible entity to the loan guarantees or somehow partially involved in that. With regard to that, I wondered if you would share your thoughts, Mr. Richards, on, you know, how does that look for Alaska in terms of the state of Alaska?

Should we expect, you know, anything surrounding that statement in terms of that? You know, commitments and fiscal stability, I think, are very important to us. And will the state be asked for perhaps additional gives as this project progresses? Mr. Richards? Mr. Kissinger?

This is Matt Kissinger for the record. Representative Galvin, through the chair, when we mentioned state, we were really focused actually on the fiscal stability. So federal more on the loan guarantees, potential capacity commitments. You can see Department of Defense perhaps taking capacity commitments. With respect to the state fiscal stabilization, and this goes back to some of the experience that I have had before AGDC career when I was working overseas.

I have worked in a lot of different tax regimes around the world or fiscal regimes around the world. And most of them where it is an owner state, they use something called a production sharing contract or production sharing agreement. And in those, you almost always have a fiscal stabilization clause, which means that if the legislature or the parliament in these countries changes the tax laws, that the contractor and the way those are written, or the developer IOC, would be made whole. And This is something that I have seen drive investment in countries that otherwise would not have attracted investment, including not unrecognized countries like Somaliland. You can get these in, in the Kurdish Republic of Iraq.

You can get these and you can't get them in Alaska. So they— it does hold us back potentially with respect to attracting investment, the fact that it's not on offer. But this isn't something that we anticipate anticipate coming back to the legislature for. In fact, I think that the producers probably bring this up from time to time themselves. Follow-up, if I may?

Follow-up, Representative Galvin? Thank you. I think that most everyone would find that reassuring. The part where there is some uncertainty, from what I'm hearing, many letters about this, is if there are protections in place, if you could share with us what that is to protect the consumers themselves if Phase 1 of the project has cost overruns, which of course would be— result in extremely high rates. So if you could tell us what measures are in place to protect Alaskans.

Mr. Kissinger. Representative Galvin, through the chair, the structure really is the protection. The structure going into project finance means that you have to have the contract first and then the debt. That means that the gas sales agreement between the project, 8STAR, and the anchor local utility, which would of course be NSTAR, that contract will be put in place before you go into financing. And that contract, of course, will also go through the RCA process as we stand it.

So, and that would be seen by the public. And so the fact that that contract wouldn't have any exposure to cost overrun risk means that the developer can't just come back and demand a higher gas price. It's not able to. So the developer, and this is, you know, how it should be. Someone has to carry the cost overrun risk bag.

It's almost been a hot potato on this project as you've looked at it from year to year. No one's saying like firmly, I take that risk. But we do have a developer now. And, you know, I hope that when they're up in front of this body that you'll ask them the question. They'll tell you, we'll— we will take and manage that risk.

That's what we're here for, because they're in the best position to mitigate that risk. Representative Galvin. Thank you, Co-Chair Foster. Uh, so, but we know that cost overruns can occur, right? We heard that from Pegasus and many other groups who are trying to inform us about what, uh, to expect from a, a giga project and how we might be good legislators doing our due diligence around this.

And so I, I want to make sure I'm hearing this on the record again. From your understanding, is that they must have somehow come up with enough extra, let's say, on top of— extra meaning investors or investor money— that would allow for some space in cost overrun. So with that then, they won't be turning to RCA because my understanding now is that what happens typically is that a producer would say Here is what it cost us to bring this molecule of energy to you. So you then need to turn it over to— you then need to use your judgment and then make the cost to the consumers, Alaskans. And so— but you're saying that they're not going to do that.

They're just going to say, listen, this is our cost. We're going to stick by it and hold on to the— if we went over, will hold on to the bag, will carry it, so to speak. Mr. Kissinger. Representative Galvin, through the chair, there's a number of tools, and this is really why the developer is the one best placed to take on the cost overrun risk. One of those tools is how they structure all their contracts with the EPC contractors and with all their subcontractors.

It was not uncommon in this industry to have lump sum turnkey on certain aspects of major projects like this, certainly not all of them. These have changed through the years. Some of them, they still exist, but they have certain indexes on things like labor costs or commodity costs, etc. But that's one way that they'll mitigate that risk. The other way, of course, is to have sufficient contingency and to have a cost estimate that has been done with enough rigor that the developer has the confidence they'll be able to land it within cost-plus contingency.

And that's the situation that we're in right now. Follow-up, if I may? Representative Galvin. Thank you. So I assume that cost estimate is making some assumptions about what the state is willing to help work together with you on with regard to property taxes, right?

Because the overall cost of this has to include something around moving the costs of property taxes. So I just want to make sure we're clear here that we will be partners in that way in helping to make this cost within the bounds of what you are saying that they've come up with that is— and we don't know that yet, just for the record. All of us have no idea other than what we heard from the Department of Revenue, which has been a pretty big window of what that price is. So what you're telling us, though, is that they've got that, they've got it down, and they have the financing to make sure that they will keep Alaskans safe with regard to the cost of energy to us in our homes. Yes?

Mr. Kissinger. Representative Galvin, through the chair. So a couple of things with respect to what you just said. Mm-hmm. First is whether there is a change in the property taxes.

I would suspect— I would expect that any contract going in front of the RCA for utility sales in Alaska would look very different with or without the changes to property tax. Simply because it's more than— it's well over $2 impact per MMBTU, which is the unit of measure that is normally sold in. And so I don't believe that they could just simply absorb it. That's my own— that's an AGDC view. We don't think that they could just absorb it.

Absorb it because it's such a big number. With respect to the rest of it, I think that you laid it out correctly, that they have done their homework. They have brought in Worley, which is one of the premier EPC companies in the world. I believe it's the largest engineering firm in the world. They have already gone out to the steel manufacturers.

They've already gone out to the pipe manufacturers that roll that steel. They've got a good understanding. They've spent the last year doing a tremendous amount of work actually in nailing down that cost. We wanted them to take this project to a Class 3 cost estimate. We believe that that would be financeable, and a lot of Class 3 projects do get financed, but they took it to a Class 2 cost estimate on their own dime and on their own volition so that they could have more confidence in what they are doing.

Thank you. It is—. Coach Harry, I have one very simple yes/no, so I just want to hear it again on the record that There will not be— you will— you meaning the collective you, you are now 25% or Alaska is plus the 75% Glenfarm will not pass cost overruns to Alaska consumers. Representative Gallman, through the chair, I say that with the certainty of having heard that directly from the developer. Thank you.

I would rather the developers speak for themselves, but I have heard them say that directly. Thank you. Thank you. And on record. Okay, and that's Mr. Kissinger for the record.

And I do have Senator Giesel who's joined us in the audience. Thank you for being here. And I've got next Representative Hannon, Tomschewski, and Joselson. Representative Hannon. Thank you, Co-Chair Foster.

I have some questions on page 3 but also one on page 10, so I'll start there because that's where Representative Galvin left us. And I want to just go— Mr. Kissinger, when you were describing loan guarantees, you used "we" as the collective pronoun. We were provided with the loan guarantees. And then you went through some history of that. And I want to know now where we sit today when you refer to those loan guarantees and the "we," is that 8 Star Alaska, AOGC, or— Glenfarn is the— who is the "we" that has access to— so if Glenfarn applies for a federal loan, do they need sanctioning from you or they just do it on their own?

Mr. Kissinger. Representative Hannan, through the Chair, when I say "we" in this particular context, I mean the project. So the project was actually giving— given these loan guarantees. First, the project was defined as a project to to send gas to North America, the highway route. And then again, that was later amended so that it defined the project to mean a project that also delivers LNG from Tidewater in Alaska.

Mr. Richards. Again, through the chair, Representative Hannon, again, Frank Richards. The way that the legislation, the original legislation was written in 2004, it was actually to the developer of the project. And as Matt just described, that original project was from Prudhoe Bay to America. And in this case, with the, with the revisions that Senator Murkowski got for the project, is now for the Alaska LNG Project.

But it again is to the developer. So the person that is going to be putting forward and getting the debt financing that would benefit from the loan guarantees is the one that will be applying directly to the Department of Energy for the loan Senator—. Representative Hannon. Thank you. So follow-up to that.

Thank you, Chair Foster. So Mr. Richards, is that Glenfarn or is that 8 Star? And to your knowledge, has the developer defined by the Murkowski modifications already applied for any loans from the federal Department of Energy? Through the Chair, Representative Hannon. The, the loan guarantee language is actually quite flexible.

So because this project is— has 3 main subprojects, the gas treatment, the pipeline, and the liquefaction, it could be that the developer, in this case 8Star Alaska, would apply for loan guarantees for a specific phase of the project, such as the pipeline. And that's where we know that Glenfarm has been in direct consultations with the Department of Energy and the Trump administration on the opportunities for the loan guarantees for Phase 1. Okay. All right. Thank you.

And now, Chair Foster, if I could switch to my questions on slide 3. Representative Hannan. Thank you, Chair Foster. And I'm going to start sort of broadly with the natural gas pipeline. We've consistently talked about a Fairbanks spur line and the importance of that.

And you've seen different renditions of it. I have heard about spur lines or off-takes. I've not heard the term spur line, but off-takes for both— for Donlin, for Clear as a Department of Defense, for Wasilla, Matsu. And my questions have to do with, does— do spur lines and off-takes such as those to serve a future base In your— should they be incorporated and talked about and acknowledged in the legislation we're talking about? Because we're talking about one spur line project, one off-take, but these others that get talked about as making it more economic, we haven't seen any language of.

So I'm looking to see if those others are just spaghetti we're throwing out there to see if anybody bites, or are they important to the project development at the first phase to make the economics viable for in-state use. Mr. Richards, through the chair, Representative Hannan, when the legislature created AGDC under House Bill 9 and augmented with Senate Bill 138, it gave us the responsibility to make sure that if there were economically capable entities that wanted gas from the the project, that we would provide them that opportunity. So that was written into Alaska Statute 3125. I'm sorry, I don't have the exact citation. With the specific language that Fairbanks and the interior— Fairbanks North Star Borough have a spur line option.

So as the project is advancing now and looking for offtake or in-state consumption, any of those projects that you described, whether it be Donlin as a gold mine or whether it be a data center as a new economic driver or be a community, have the opportunity to come to the project and say, we would like to have offtake, and then, and ultimately show that they have the financial capabilities to essentially buy that offtake amount. And the project will then provide them an offtake for them at that location that is best suited for them.

Representative Hennig. One more, which is— and this is a little bit out over my skis of understanding. I've heard it described— Point Thompson is one of the fields that we are expecting to take gas for, especially in Phase 1, that it's critical. I've also heard that, hey, geology evolves as we have knowledge, and Point Thompson, that is also producing oil for us, may not be able to provide as much gas because as we're taking gas out, that affects the geologic pore space. So if we get to a point where our oil needs from Point Thompson is in competition with our gas needs from Point Thompson.

Does the Oil and Gas Commission then adjudicate who gets what? Because by taking more gas out and shrinking our pore space, we reduce our oil recovery from it? Or is this set in a contract by the developer at the outside of this project, and even if it brings our oil take from Point Thompson way down, tough beans, because we promised it to the gas line?

Mr. Kissinger. Representative Hannan, through the chair. So that's already been adjudicated at Point Thompson, and so there already is an AOGCC offtake authorization for 900 million standard cubic feet a day from Point Thompson. Now, Point Thompson couldn't deliver anywhere near that right now. They have this initial production system in place that has a nameplate capacity of about 200 million standard cubic feet per day.

So Point Thomson is a place where they're going to have to expand. But because of the high pressures, again, our understanding just from our discussions, and, you know, invite you to talk to the operator of Point Thomson to get more clarity on this, but our understanding is because of the high pressures that you end up reinjecting in, that being able to cycle a sufficient amount of gas, you know, up to a billion standard cubic feet a day, to truly, um, complete that reservoir has never really been in the cards, is my understanding. That the— in fact, the alternative was always a blowdown. If it were not blowdown into the gas pipeline, what I've seen as a plan of development was blowdown to Prudhoe Bay by still building a pipeline over to Prudhoe Bay. But again, that's just from our own understanding, us not being the operator.

Representative Hannon. So to be clear, and again, I appreciate your technical understanding because I'm a little— that supplying Phase 1 of the gas line, you're saying that AOGC has already made that ruling, and even if it impacts our oil recovery from Point Thompson, Phase 1 of the gas is a commitment that we have to adhere to as the primary extraction from Point Thompson shifts? Representative Hannan, through the chair, actually what I was saying is that all the gas sufficient even for Phase 2 has already been approved by AOGCC. So the offtake authorization has already looked at the expansion, and that's what the AOGCC would have done, is looked at which of the alternatives results in the least amount of waste and the most amount of production.

Okay. Representative Tomschewski. Thank you, Co-Chair Foster. Through the chair, thank you to the good folks at AGDC for being here. You mentioned that as far as the North Slope gas supply, we have 40 trillion cubic feet in Prudhoe Bay and Point Thompson, and you characterize that as a 30-year supply.

Is that correct? Mr. Kissinger. Representative Tomaszewski, through the chair, we represent it as more than a 30-year supply. So the LNG facility uses just under 1 trillion cubic feet per year. In fact, it's close enough that you can use that as your sort of simple math number.

Then there's, you know, a bit of local demand, which would take you over that. Okay, follow-up. Follow-up? The other 82 trillion cubic feet that you say is proved producing reserves in Alaska, I know it's got a link here with an asterisk, I didn't get to that link. Is that gas located— I mean, it says in the North Slope gas supply, so is that gas anticipated to use the pipeline and the facility after that first initial 40 trillion cubic feet is used up?

Representative Tomaszewski, through the chair. So that number comes from EIA, which is the database for, you know, where— what U.S. reserves and resources are. But unfortunately, they do not break that down or identify where that comes from. So we put that number out there because it is a large number. It kind of, you know, a number one— another number we put out there is the 200 trillion cubic feet that the USGS has identified as conventional resource available as prospective resource.

But in reality, we don't have line of sight, and the one that we really focus on is the 40 TCF. Plus, there's an additional, you know, nearly 10 TCF that's been identified at Great Bear Pantheon. And we did do the due diligence on that one. We had a company called Ryder Scott come in and do due diligence for AGDC. On the results of, of the drilling there to confirm that the gas resource is there.

Okay, so looking at a pretty significant supply for many, many decades in the future, um, for not only for Alaska but for the world, whoever wants to come buy it. Okay, I'm just gonna change subjects real quick. I'm gonna go to, um, Qatar. You talked about the Qatar Qatar being the cheapest, the Qatar expansion as it is, as it is labeled here on the slide 9. So March of 2026, Iran hit the Ras Laffan facility in Qatar, setting them back.

I think it's, they're looking at a 3 to 5 year timeframe to replace that facility or to repair it, whatever they have to do. Is that what you're talking about in the Qatar expansion? Um, because it looks like about 623 billion cubic feet of gas, um, loss of export loss for Qatar. Is that changing that number as Qatar being the cheapest, or, or what is that, uh, going to do with the price of what we're looking at here now. Representative Tomaszewski, through the chair.

So this was done in 2020, this chart, and at that point in time, Qatar expansion referred to something called the North Field Expansion Project, or sometimes just NFE. It was a major expansion that Qatar is undertaking currently to grow their supply from over 70 million tons to to something over 120 million tons per annum. To put that into scale, we're talking 20 million tons per annum here from Alaska. Just for your awareness and anyone listening, we jump around in units, and I apologize for that. It's the way the industry is for some reason.

When we sell gas, we sell it in British thermal units, in million British thermal units. So sometimes you'll hear me say MMBTU. And this is where all the cost comparisons are. We used to pay around, you know, $8 to $9 per MMBtu out of the Cook Inlet. The latest numbers I've heard were getting up towards $16 per MMBtu.

We talk about million tons per annum as well. This is really just the way big projects compare each other. And so we're 20 million tons. You don't go sell it that way. You don't do anything other than brag about your project using that number.

Okay, so follow up. Follow up. So, so what is Qatar producing now with that expansion? Is that the expansion that was hit, or, um, are— is their capability of, of export, um, going to affect the cost of gas and, and what's happening here? Representative Tomaszewski, through the chair, sorry.

Um, so their Northfield expansion was being built at the same time that train 4, I believe it is, of their existing facility at Rostelefon was struck. And so they have new capacity that is coming on over the next sort of 3 or 4 years. But at the same time, they've lost this capacity that they have to rebuild. And my understanding is that that could take up to 5 years. So they have contracts already in place for their Northfield expansion volumes.

And they have contracts that are now under force majeure for the trains that were struck. And some of our close customers, in fact, I'd say our closest customer, uh, has a tremendous amount of gas that comes out of that train. Um, so it has impacted our customers, and I'd say that it has driven them into more and more serious conversations with us. The problem is we can't react fast enough to plug that particular gap. You know, they're out now and they're out scrambling now and probably will be for some years.

Okay. Thank you. And one other, one other question I just want to ask about the fiscal stability that we were talking about earlier. And you said the company will have hold harmless clause involved in that. But when you talk about fiscal stability, I mean, what you're really talking about is that AVT.

Is that the fiscal stability, that number that kind of guarantees and gives the investors the confidence as well as the company confidence that the legislature is not going to come back and change the rules in some certain amount of time. Mr. Kissinger. Representative Tomaszewski, through the Chair. When I was referring— so this is in 2020 we put those slides together. When we were talking strict fiscal stability, like on the upstream oil and gas contracts, we see that, you know, we see that there are a lot of places where owner states have fiscal stabilization clauses and are able to attract a lot of investment because of that.

Now, the AVT, you could see that as somewhat stable, but I don't think it gets around this whole concept of not binding future legislatures. So I think that is always going to sit out there as an issue. And that's the one that I'm talking about. When we say fiscal stability, we mean being able to enter into 20-year durable contracts with the upstream developers So they know exactly what their taxes are going to be for the full 20 years. And this is what they get in a lot of other places.

And that's really what they should demand, I would imagine, to have that fiscal stability and know that their money is going to actually come back to them at some point. So, well, thank you. Thank you for those questions— answers. Okay. Representative Josephson.

Yes, thank you. Good afternoon, gentlemen. On this question of cost overruns, you talked about how you wanted a Class 3 cost estimate, you received a Class 2, um, and there was a lot of dialogue about who would bear any cost overruns in Phase 1. And I know that there's real concern about, uh, if, if in the event there is no Phase 2, we have a— we all share a significant problem. But in terms of explaining that exchange you had, I think principally with Representative Hannon, I need to be able to tell my constituents what document speaks to it, right?

So I would assume that if they're really going to bear the risk of cost overruns, there's a contract reflecting that. Is there a contract reflecting that? Mr. Kissinger. Representative Josephson, through the chair, there will be a contract because that is the gas sales agreement between the project and Enstar, for example, as a utility, and also any of the other utilities and buyers in Alaska. Those particular contracts, that's where you would look for, for that protection.

Okay. So, so there'd be a prospective contract that would come in after the passage of 381 or some sister bill that would tell constituents that they would not pay for cost overruns? Mr. Kissinger. Representative Josephson, through the Chair, that contract as I understand it will just be for a gas price that everyone can see. It will have adjustments obviously because because of inflation, et cetera.

But that'll be it. And so there'll be no way for the developer to then come back and demand cost overrun be absorbed into that contract because it's just a set price for a 30-year duration. And that's, again, with project finance, this is the real difference between an oil project and a project finance gas project is in oil projects, people go, oh no, oil's at $120, are we getting our fair share? Well, with gas contracts, gas can go to $60, $70 as it did in 2021, but your contracts are already in place. You're already selling 30-year contracts, or in the case of LNG, usually 20-year contracts at a price that's already established, sometimes indexed, but certainly not fluctuating to the extent the spot market is moving up and down.

All right. I'll follow up on that later. I appreciate it. I do have a question about Point Thompson. So I've been lucky to visit there.

And just so I understand it, it's known for producing— I think it's condensate.

I'm not sure I could tell you what that's for, but it's what God put there. And less so oil. It was really— was it not something that Governor Murkowski forced be essentially built by Exxon for purposes of future gas development. It's principally a gas field. Is that right?

Mr. Kissinger? Representative Josephson, through the chair. So it's technically called a retrograde high-pressure gas condensate reservoir. It's over 10,000 PSI. So think about that in terms of, you know, if you've ever had a racing bicycle where you're pumping the tire up to 100 PSI and, you know, you ping it with your finger and it sounds like something that you just don't want to be around.

So 10,000 PSI is what they have to re-pressure this gas to in order to re-inject it back into the ground. Right now, they are producing gas to strip out condensate and then they're just re-injecting the gas. So it's there to produce the condensate right now, that initial production. System. With respect to oil condensate and gas, condensate's a liquid.

And so condensate gets blended with crude oil and just becomes part of your crude oil mix. And it gets blended up to what's called the vapor pressure limitation of the Trans-Alaska Pipeline System, the oil pipeline. So you can only put so much propane into that mix before it's turning into gas as it flows down the oil pipeline, which you can't have. That's the vapor pressure limitation that I'm talking about. So what happens is— and this is with respect to Great Bear Pantheon— this is also how that field will act.

This is—. That field has crude, it also has a lot of condensate, and it has natural gas. And this is also true for U.S. crude oil liquid production in general. Right now the U.S. produces more you know, liquid production than the next two largest producers combined, I believe Saudi Arabia and Russia. But the vast majority of that is these lighter end components that you'd call condensate.

They're better suited for the chemical— petrochemical industry making plastics, things like this. And so different refineries shop around for different qualities of crude and these crude qualities change over time as you move from more oil to more and more condensate. Getting back to Point Thompson, Point Thompson's value, we've always understood it to be in the condensate. But it's a lot easier to produce massive amounts of condensate out of that reservoir, even if you leave some of your reserves behind because of this retrograde nature. But even if you do that, By blowing down, you'll have more production over a quicker period of time and better economics.

And so one of our arguments, obviously, as the gas developer is that project should hopefully make most of its money off of the condensate and we should get a cheaper gas price. Okay. Thank you. Okay. And so we'll get through the next 3 questions.

3 Slides, I think up to slide 14, where we will take some more questions at that point. And then what I would like to do is maybe take a— committee members get up, stretch their legs a little bit, use the bathroom if they need to, so get some more coffee. So Mr. Richards. Thank you, Mr. Chairman. Again, on this slide, we really wanted to again provide kind of a history of where we were again in 2010.

2023. You heard all the previous actions that we had gone through an economic stage gate. We were— had our permits in place and we were out looking for partners to be able to come in and take on the, the development lead for the Alaska LNG project. So in 2023, we represented this execution strategy to our board, and it was to be able to work with the likes of Goldman Sachs to be able to help in identifying to us who those partners might be around the world that would have not only the credentials, the financial capability, but the wherewithal to be able to advance a project of this size to final investment decision. So in this case, the offering and what we put forward was a— essentially a commercial prospectus that we used in our discussions with these interested parties is that we would utilize the 75% ownership stake that was given to AGDC by ExxonMobil and BP and ConocoPhillips when they left the Alaska LNG Project, use that as the enticement for the developer to be able to come in and gain that equity or ownership stake in the Alaska LNG Project with the commitment to take the project to final investment decision.

And at the time, we were envisioning that that would take about $150 million to conclude the front-end engineering and design, to wrap up commercial contracts and be able to get to a position to be able to advance the project. And we were also directed by our board to be able to develop the 8STAR Alaska subsidiary. And that's where, again, this— as a subsidiary to a state corporation, we could put the assets, which were the designs and the permits and the authorizations that were granted to us by not only the federal government but the state, into a mechanism that could have divestment to a private party. So that's why 8Star Alaska was originally developed, because you couldn't divest AGDC, which is 100% state-owned corporation. So— but the legislature, when they created us, gave us the ability to create these subsidiaries, and that was the ability to be able to then to use— to entice folks to come and work with us.

Then we— as Matt described earlier, the three— I'll call them stages that we went through from originally producer-led project to a state-led project to now a developer-led project. That was the evolution that AGDC DC has worked under to be able to keep the project moving forward. And it was with the legislative appropriations and the legislative mission that gave us the opportunity to be able to continue moving through the project development. Now, there weren't times where it was very challenging, and the legislature as well as our board asked us if it was actually going to be viable to continue. And that's why that economic stage gate was really important.

But we wanted to identify on this slide again where the costs— who would bear the cost and where those cost contingencies would be factored in under the various lead— various projects. So for instance, ExxonMobil was the lead party in the producer-led project. That's where the state and all the other parties had about 25% ownership and would have 25% of cost responsibility, including cost overrun responsibility. So that's where AGDC, representing the state, had that 25% through the project, through construction, and ultimately into operations. And then when the producers left the project and gave AGDC 100% ownership rights, AGDC then had the responsibility to conduct not only the front-end engineering design at our cost, but also would be looking to cover the cost of construction as well as construction risk.

So it was very risky for the state at that time. And again, as an organization, we didn't have the capability to accomplish that. So we shifted to this developer-led project where we retain the 25% ownership that we have within the project and sought a developer to come in and take on that 75% owner— given them 75% ownership, but for covering 100% of the ownership cost to get to front-end engineering design. So that's why we have a zero cost under the column called FEED, or front-end engineering and design.

Under construction and construction risk, we put in a 0 to 25% as an option, because that's what we negotiated with Glenfarm, is the opportunity should the the state of Alaska or Alaskans want to invest, they would have the opportunity to invest up to 25% of the equity portion of the project. And we'll get into that further in subsequent slides.

So where we find ourselves after agreeing to definitive agreements with Glenfarm is that they are meeting the objectives that we had put out for them. Matt described to you the diligent development efforts. They have come up with the capital to move the project through front-end engineering design on phase 1 of the project. As he said, that they have advanced not only the FEED to beyond a Class 3, but to a Class 2, which means that they've refined the costs, they've reduced the contingency levels, they've gotten price quotes from major pipe mills and actually have contracts with them to be able to provide the pipe. They're working with pipeline contractors, they're working with early works contractors, and they're aligning their project cost to a Class 2 level.

That's a standard that's out there by the American Association of Cost Estimators. So this isn't something that we have just come up with. It's called AAACE. And the smaller the number, the higher the confidence that you have in what the cost is going to be for the project. So the contingency shrinks as the smaller number goes up.

And you get to a point where you get to a Class 1, which is actually the bid, and Class 0 is actually when you've completed your project and you know what the overall costs are. In the objectives that we had from the state was to move the project forward and bring in a developer. We did that. We gave them milestones to achieve, which means moving forward with the front-end engineering design on Phase 1, keeping compliant with the permits that we have, and developing And moving forward with H-Star Alaska, with ownership rights that AGDC as a minority owner has in oversight of the project development. And then most importantly for us is the inclusion of the Alaska Advantage principles.

And this is where it's a set amount of 500 million standard cubic feet a day for Alaska's needs. It's use of Alaskan contractors to construct the project. It's to deliver the cost to Alaskans at the lowest cost. So they are working to those principles, and that is our job to oversee them.

So that takes us through slide 14, Mr. Chairman. Is that what you wanted to do? Okay. Looks like we have got a couple questions. I'll start down at the end here.

Representative Hannon, Tomaszewski, Galvin, Josephson. Representative Hannon. Thank you, Chair Foster. So first, on the Class 2 price estimates, price development, that's on the gas line. What stage of cost estimates are we at for the other two parts, for the carbon capture and for the liquefaction?

Through the Chair, Representative Hannon, the cost estimate level for the gas treatment plant and the liquefaction are currently a Class 4. And so, as I started off, you know, we were at $44 billion, we reduced it to $38 billion in 2020. And what AGDC did is we had engaged with Fluor as essentially our owner's engineer over the years, and we asked Fluor to keep up with the cost and we would recast that cost estimate, meaning we would go out, we'd get price quotes, uh, to make sure that we were up to date as best we could. So we did that in 2022, we did that in 2024, and then what you've most recently received was a CPI index update from the Department of Revenue that took us up to that $46 billion level. So we feel that the work that has been done up to 2026, we kept current with the industry costs, meaning we wanted to make sure that we had what was current, that contractors were bidding on, that pipe suppliers were providing, what process equipment manufacturers were costing, to be able to make sure that we had something that was viable for— to entice investors and entice the market to come into the project.

Okay, thank you. And then I have a I have a different question for follow-up, and I was quickly trying to find my most recent Department of Revenue. This comes back to— so AGDC is a 25% carried interest in 8STAR, but my recollection is Department of Revenue talks about us being able to be an equity shareholder, and I guess I need to understand that. 25% Interest does not make us an equity shareholder, and when Department of Revenue has some modeling, if we took certain percentages as shareholders, that that's in addition to and different than this 25% stake as an 8-star owner. Is that correct?

Mr. Richards? Representative Hannan, we have a series of slides coming up that will go into a deep dive to identify equity or ownership interest that AGDC has and the options that we have within each of the 3 subprojects and what that— how that revenue stream would flow back through AGDC to the state. So if I could ask for your indulgence, we'll go into that in great detail. Okay. Thank you.

Okay. Representative Tomaszewski. Thank you, Co-Chair Foster. Through the chair, we're talking about 25% ownership. Now the State of Alaska owns a lot of assets in the state.

State buildings, DOT, uh, infrastructure, et cetera, et cetera. I don't know if we pay property taxes on any of it. Does a 25% equity share of this, um, project give us any kind of property tax exemption when we are running through particular boroughs, cities, anything like that. Has that been discussed or is there any information on that currently being discussed? Mr. Richards?

Through the Chair, Representative Tomaszewski, the original legislation that created AGDC gave AGDC essentially tax-exempt status should we have ownership in the project during construction. And then it was going to fall to the tax structure under 4356 for oil and gas property taxes. Now, the, the concept that is now in front of us with House Bill 381, this alternative volumetric tax, would— is really going to be based on the volumes of gas flowing out of the project. And just because AGDC is a 25% minority owner It doesn't matter. It's that the tax or the AVT will be applied based on the volume depending on— independent of ownership.

Okay. Follow-up? Follow-up. So during the creation of AGDC, you're saying that during the project's construction, tax-exempt, afterwards not tax-exempt. Was that under the assumption that AGDC or the state wouldn't be an equity owner of it, or was that under some other assumption?

Through the Chair, Representative Tomaszewski, the rationale and reasoning behind the legislative decision at that point, I don't recall. I think it was recognizing that when they created AGDC, it was really around the in-state pipeline project. And they— so they wanted to make sure that the ratepayers of Alaska weren't going to be essentially charged a property tax for a molecule that was going to be consumed by Alaskans in Alaska. So the purpose, again, of having it a tax exemption during construction is really because it helps keep the cost of the construction down. So you don't have that high upfront tax burden.

Similar to what you would— you heard from Gaffney Klein as any property tax that applies to a full project at the outset when gas volumes are starting to flow up has a significantly large financial impact on any project. Okay, thank you. Representative Galvin. Thank you, Co-Chair Foster, through the chair. And I'm going to, I guess, follow up on a couple of the different things I just heard with the questions by Representative Hannan and Tomaszewski.

Firstly, You had mentioned that we have on the pipeline— gas line itself, we're at 2 in terms of classification, 4 for treatment center, and I don't believe I heard for the treatment— for the liquefa— liquefa— the export project what that number is. If you did say, then forgive me, but I didn't hear it. Mr. Richards. Through the Chair, Representative Galvin again. 4 For the gas treatment plant and the liquefaction facility.

Oh, both the same. Okay. 4. Thank you. And then to follow up, if I may.

Representative Galvin. Thank you. We were hearing conversation about current law as it stands, wherein if AGDC is part of the project, that we will enjoy the tax abatement through the building of the pipeline. And then once— and then that changes up with this legislation. There will be abatement of a certain percentage, and then we switch to AVT.

My question is that current law, I wasn't sure if we have definitive answer around if you, if you're a part owner with another entity, does that still give the same abatement, if you will, if you're a 25% owner? Is that implied that that is still part of that? I just want to double-check that. Through the Chair, Representative Galvin, again, under current law If AGDC is an owner of the project or a partial owner of the project, then that construction exemption would apply. Okay, so 25% applies.

Thank you. And if I may, one more. Representative Galvin. Thank you. And this is related to slides 12 and 14 about the ownership.

As AGDC is now the 25% ownership, I wondered if you could share with us What decisions are at the table wherein you get to exercise your authority as a 25% owner? What does it look like? I'm not sure what decisions are being made and what— if there are anything— any decisions being made related to what investments need to happen, what must be invested, what dollars must be invested in and where. Give us a sense of that, what, what this looks like for you at the table. Mr. Richards, through the chair, Representative Galvin, again, as minority owner within AStar Alaska, AGDC has the responsibility to again look out for the interest of Alaskans.

As we described earlier, that is following the Alaska Advantage principles that we wrote into the agreements, but also to assure that the project developer is moving forward with diligent development efforts. And what that really means is that— is— are they working to industry standards? Have they done a significant amount of engineering work that really meets FEED standards, or front-end engineering and design? Does that meet Class 3 or Class 2 cost estimate standards? So it's our responsibility to look over the shoulder to see the work that is being done and to validate or to essentially assess that, yes, they are meeting that standard.

So the decisions that we have are, again, one of governance and oversight at this point, and identifying that there are the responsibilities that Glenfarm has to move forward with the front-end engineering and design and move forward with the contracts, such as for gas purchase off the north slope or gas sales in to South Central and into Fairbanks. And they are doing that and they are actively pursuing that. Now, the challenge that we all have is again around are they achieving it in as timely a fashion as we would like? Well, that's— with any large project, again, schedules are a blessing and a curse. You need to have a schedule to accomplish and to monitor how the projects are progressing.

But they're a curse when you overrun those projects. This, as you've described as a gigaproject, has the challenges of being just that, a gigaproject. So there— it's very complex, it's very large, and it means that there is a significant amount of effort that must be undertaken in developing contracts for gas sales, for offtake, the contracts for contractors, the contractors for supply of materials, the logistics plans that must go into it The purchase agreements for parts and pieces, the project labor agreement necessary for, you know, to be assured that there's workers for this project. And then making sure that you have everything in a timely enough fashion to be able to meet your construction schedule. So that's what we do in our day jobs is look over and participate because, again, we have a significant amount of experience, Alaskan construction experience and aptitude.

And so that's where they help and ask us to assist them in helping move some of these work efforts forward. Thank you. Last follow-up. Thank you. Through the chair, has AGDC shared publicly these Alaska Advantage standards?

That they say are included in the agreement. I know you have an agreement, you've mentioned that, talked about the Alaska Standards. I don't remember seeing them. Perhaps this is gonna come up later in another slide, and forgive me if that's the case. Happy to ask you more then.

But I do wanna make sure that that's something that we have on record for you to kind of expand on. Mr. Richards. Through the Chair, Representative Galvin. Yes, we have in our presentations, and I'm trying to— this should be as part of this presentation— identified what those Alaska Advantage principles are. Thank you very much.

Okay, next two questions I have are for Representative Josephson and then Moore. Representative Josephson. Thank you, Mr. Chair. I'm curious about the, the carried interest.

Is our carried interest as a 25% shareholder of 8Star. Is that because we're sovereign, or is it partly because through the Stranded Gas Act and AGIA and then TransCanada, we had invested and have invested so much of our own revenue to get where we are? It— I get— and really where I'm going with this is With, with Glenfarm now sort of in control of the project, which we wanted, or at least we delegated to you to want, um, they now control, for example, the TransCanada, uh, deliverables presumably, and, and all these other documents. And I, I just am curious are we a 25% shareholder because of, because of that transfer or because we're the state of Alaska? Mr. Richards, through the chair, Representative Josephson, the 25% ownership retention was really— we felt that we had been granted essentially a gift with BP, Conoco and Exxon on the ownership of the Alaska LNG project when they gave us the 75%.

And that we had earned the 25% through all of the previous efforts that you described, as well as the in-state pipeline project and the Alaska pipeline project and all those other efforts. That repository of information, all those designs and the permits and the environmental compliance efforts, all resides within 8STAR Alaska. So that wealth of that information, that wealth of knowledge is what has been made available to Glenfarm as the developer to be able to help in advancing the project. Now, what's different, I would say, between EGEA— again, remember, it was a design concept was a little bit different where it was going from Prudhoe Bay to America or to Western Canada. This is all within Alaska.

But that collective design on the gas treatment plant, on the compressor stations, on the pipeline alignment, all sits within the information database that we have held and contributed to the project. That 25% we retained because of the state's true sunk cost that from 2013 through 2024 essentially represents a significant amount of money that the state of Alaska has pushed forward and funded to be able to move this project forward. And we felt it was important that the state have an ownership right because of that sunk cost. So that's why we retained that 25% as the carried interest. Okay.

One of the differences in the bills, and there are now 4 of them to my understanding, is I believe the other body's draft would allow— and I'm staying within our confines here, Mr. Chairman, because we're talking about the AGDC option at slide 13, would give the legislature 12 months rather than 6 to elect to become an equity shareholder in, I guess, any or all of the 3 components. Is that— that strikes me as reasonable. Is that the kind of thing that I should think is a deal breaker? For this bill. You may not be privy to that, but I'm hoping it's not.

I'm hoping that that sort of adjustment is reasonable. Mr. Richards. Through the Chair, Representative Josephson, again, in our definitive agreements that we entered into with Glenfarm, we had put in place this, what we call preemptive rights, which will allow us to come into the project and elect an equity position should it be— should the legislature appropriate the funding for it or Alaskans compile enough cash to be able to want to have an equity participation. And with that, though, we have a 6-month window in our agreement post, you know, financial close to then be able to make that decision. 12 Months— and I'm not sure which version of the bill that's in anymore— but 12 months would add significant amount of time to that and make it very challenging.

And my colleague has something to add. Yeah, Matt Kissinger for the record. Representative Josephson, through the chair, it's important to think about the investors coming in. So let's say we go out for FID and we have institutional investors and the likes come in. They're going to come in with the knowledge that they can be preempted back out.

6 Months actually seems like a long time to me when I think about that, because over the course of time after they have made an FID decision, they are paying cash, they are paying bills, and you are going past your risk exposure to a certain degree. So, a year down the road, you have a different risk profile than you would have had 12 months earlier at FID. And so, I think that that is a burden on the investors of the project that makes it far less attractive. I think 6 months was a bit egregious, and luckily we got that. Okay.

Excuse me, Mr. Chair. Mr. Richards. Through the chair, Representative Josephson. I see you got an inquisitive look on your face and just wondering Does that make sense in terms of— the project is going to go out and it's going to acquire, let's say, $10 billion of equity.

That means that those investors have to put that money up front, and therefore they know that at the initiation of that, they're not going to be making money, but it's a lost cost of capital because they've given it to the project and they're going to be getting the returns farther down the road. This 6-month, as Matt described, is a fairly long period of time because they can be, you know, 25% of their investment could go away. So they would lose capital and they would be receiving it back. So from them, it's a lost opportunity cost. And so that's why going to 12 months makes it even larger.

So it will come at a cost, is what I'm trying to get at. It will come at a cost that these rights that we are asking for to be able to invest.

I'm just aware that because I have been through so many of these that to find the time, as proved true with these bills, during the January to May session for the next legislature potentially to decide whether to invest something just over $4 billion for the full 25% share is it's got to be among the most significant decisions any legislature has made in 60 years. And, and of course, it'll, it'll come down to what are the opportunity costs? What could we do otherwise with $4 billion? I suspect it'll come down to that.

So it sort of guarantees a special session, potentially. But I guess that's survivor survivable. I just was curious about that. Thank you. Okay, I've got Representative Moore and then Galvin.

Representative Moore.

Hi, can you hear me? Uh, yes, we can. Might have IT turn you down just a little bit. Go ahead, Representative Moore. Sorry about that.

Uh, thank you, Co-Chair Foster, and through the chair, thanks for being here, Mr. Kissinger and Mr. Richards. I have a couple questions, and I think one of them kind of bounces off of what Representative Galvin was asking a little bit. And I think I'll just— I just want a little bit more clarity on what rights does AGDC actually retain as a 25% minority partner? And maybe you can give a little bit more intel on that. Does AGDC— can AGDC block major decisions?

Was it mostly advisory oversight? Just maybe more of a clear answer on that. Yep. Mr. Kissinger. Yep.

Representative Moore, through the chair, as Frank had mentioned, the Alaska Advantage principles are a core element of that. So you generally have a board and there are board approval items. But in this particular instance, through these agreements, we also have a lot of just minority approval rights, and one of those minority approval rights is we get to approve contracts and— or I should say we get to disapprove contracts that are not in line with the Alaska Advantage principles. And we do have a slide where we'll go through those principles shortly here, so I'll leave that to that slide. That's one of the mechanisms, but we also have approval rights on certain milestones that they reach, like, you know, viewing the feed work product and making sure that it was done to a standard as, um, uh, an industry standard, for example.

So mostly our rights come through these minority kind of approval, uh, rights rather than through our position on the board. Okay, excellent. And follow-up. Representative Moore.

Thank you. Um, okay, I also— I have a question about the Alaska Advantage principles, but, um, and you know, and what is included in those agreements, but I'll wait on that question and maybe just go down to, um, my last question that I have here, and I can wrap it up so you can continue on with your, um, with your presentation. But I was just curious with around the risk, um, how is the risk divided between Glenfarm and AGDC if LNG prices weaken or the conditions change around the, this original agreement here. Representative Moore, through the chair, this is Matt Kissinger for the record. Um, what we've created, and actually near the end of our presentation, uh, we're going to walk through 3 slides and we're going to walk through them several times to talk about the evolution of 8-Star going forward, what to expect.

But it really comes down to creating alignment between AGDC and Glenfarm as the developers of the project in sharing the developer rewards. And the best way, I think, to— or the best analog for this is if you've ever watched the TV show Shark Tank. In Shark Tank, and hopefully most people have watched it because it's a good example of this, In Shark Tank, the developers come up in front of the investors and, and they say, hey, this is our great project. In this case, we're going to make a lot of natural gas, we want you to invest. And the investor goes, okay, well, I'll tell you what, I'll give you half the money that you want, but I want 80% of your equity.

And then the developer says, well, wait a second, no, I'm going to give you 40% of the equity and I want all the money. And they either reach an agreement or they don't, but ultimately the developer is trying to defend to defend their retained interest in the project. This same mechanism is going to happen with respect to 8Star at the top level. And again, we're, we're going to go through this in real detail later, but I'll just touch on it. Uh, you have this 8Star Alaska as the holding company, so to speak, and underneath that you'll have these 3 subsidiaries that the actual assets are in.

When we raise capital, 8Star Alaska will exchange equity in the subsidiaries in exchange for capital. So let's take the pipeline, for example. We will exchange 30, 40, 80% of the equity in that company in exchange for the capital to build it. And then whatever we retain, that 20%, that's the developer reward. Of the developer reward, we will always get 25%.

There is no dilution. There is— and I'm probably going too far without the slides in front of us— there is going to be some dilution of 8Star Alaska's ownership of 8Star Pipeline. And that's— we don't even put the developer economics into any of the estimates. They're not in any of the DOR estimates. They're not in there.

It's pure upside because we just don't want to set it as an expectation yet. But the reality is we should be sharing— well, we will be sharing 25%. The unknown is what that reward will be by the time we're done building the project and dealing with cost overrun risk.

Okay, all right, well, thank you so much. I guess I'll— sounds like you got some slides coming up that'll answer my following questions, and I'll be able to get some more information on that. Thank you so much. Representative Hannon. Thank you, Co-chair Foster.

I want to go back You answered some questions from Representative Josephson that have now spurred— you know, I'd asked you earlier about equity investment versus owner investment, and I guess the 6-month timeframe has caught my attention because in legislative time, I understand from investor time, 6 months is a long time, but from legislative time, 6 months is a short time. Short time, especially— it depends on when those 6 months are. So let's say July 1, FID is announced, and we have 6 months to make a $4 billion, 25% equity investment.

Gosh, you have a lame duck legislature and a lame duck governor trying to make a $4 billion decision. That, that's a long time if you are a equity investor, but we're not. We are a sovereign trying to make 30-year policy with, you know, sideboards on there. Our concerns are both investment but long-term policy.

So that 6-month horizon for making an equity investment has a lot of alarms going off for me because I could foresee a lame duck legislature making a very different decision than, say, a brand new legislature and a brand new governor. And at a minimum, we know we're going to have a new governor. And the likelihood is that some of us who aren't even lame ducks find out retroactively we were lame ducks. And depending on how we make that decision, more of a, you know, in a 6-month window, it might move more of us into the lame duck category than others. So how do we work through that?

Because sometimes we struggle. You answered a question to Representative Stack, Mr. Richards, at the very beginning where you think you've been very clear and direct and said something that had a lot of exclamation points of you must do something about property tax to ever get a gas line project. And I don't feel like we heard it that way over the last 4 years.

But I understand that it is a significant policy decision. So with this equity investment question, that really has me concerned from where we sit here, the end of May. I'm going to call it June 1st and go, do we have— are we expected to make a $4 billion equity investment decision between now and the next formal legislature, the 35th legislature being sworn in. And gosh, most people are going to want that after, say, mid-November to make that decision so it doesn't have undue influence one way or the other. So help me understand those timeframes of decisions for policymakers that are laid out over the next 6 months, because in the legislative calendar, 6 months is not a long time for a bill— $4 billion decision to be made.

Mr. Richards, through the chair, Representative Hannon, again, I completely understand the legislative time sequence that you just talked about. I would add this to the equation for your knowledge, though, is this is going to be a 6-month period after a financial close. So this means that the other investors, the other equity participants have gone through all the books, looked at the cost, verified with third-party independent engineers and other consultants and resources that this is an equity investment that meets their standards. So they will have done that. Now, this is the likes of BlackRock, BlackRock or GIP or major infrastructure companies, infrastructure funds that have literally trillions of dollars that they can put— of capital to put at risk.

So I'm telling you this just to say that this— you'll— the legislature will not have to start from scratch, so to speak, and go in and look at everything. This will have been done. The, the resources will be provided to the legislature so that it will hopefully be a starting point that won't necessarily take as long to achieve in legislative time as it would if you were just going in for that initial equity offering. So, but please recognize in the financial world, the equity offering will be presented to these option— these potential investors. They're only going to have a very short period of time, significantly less than 6 months to be able to make their decision on what their commitment is for the billions of dollars that they're going to be putting up front as equity participants.

But to your point about 6 months versus 12 months, we, in the discussions that Matt described in our negotiations with Glenfarm, they wanted something much shorter than that. We pushed for something longer, and 6 months is what we actually agreed to in the agreements. So when I saw the 12 months coming into legislation, I could see that there was going to be an issue raised by a 12-month versus a 6-month timeframe that we have under agreement.

Rep. Buchanan. Thank you, Chair Foster. I guess I just want sort of to remind you, though, as you described it, we'll have all the benefit of all these equity investors' financial analysis. You need to remember that we as policymakers are not making it purely on an equity investment. Our lives would be much simplified if all we had to do was make dollars and cents and two-column investment.

Our policy decisions have a lot of other constraints on them. By our constituents' request, right? We're not running the state just for dollars and cents. We are running it for a more complex— and I know that Representative Staff would like the decisions to be simpler. Just, you know, give it to them for free and see if we make money.

But we have a lot of people who ask us to have more evaluation than just the return on investment is a major part, especially at the finance table, but it's not the only part in policy that we need to deliberate on. Okay.

And I next have Representative Allard, then Galvin. Thank you. Through the co-chair, I hear, um, lame duck and other comments, and we need to do right by our constituents and those in Alaska. I'm concerned that there's individuals within the state, lawmakers included, that we as Alaskans are being so greedy— and I say greedy in the sense of we want it all— that it could possibly just kill the project. And that there's not really negotiating.

It's either this way or no way. And I'm not sure how that's going to pan out. And I've been reviewing other countries, other states. I mean, Texas is thriving with it. They're smart with how they're doing it.

And if Canada is moving forward and us as Alaskans can't seem to find a path forward, I'm a little bit worried. I don't even know if you can comment, but I know negotiations are here, but I want this to happen. And I know other Alaskans, majority of Alaskans want it to happen. So if you want to comment, Mr. Kissinger. Representative Allard, through the chair, I think, um, bringing up the Canada comparison is really valid.

If you look at Canada versus Alaska, they have It's a fairly well-known resource, but it's an undeveloped resource that requires drilling and development through the life of those projects. It's the Montney and the Horn Rivers, tight, tight oil and gas up in northern BC and Alberta. They have the pipeline that had to go over the coastal range. We get to avoid the coastal range. It's the hardest part of building TAPS.

It would have been the hardest part of building this project. It was a very difficult part of building theirs. They don't have land rights resolved. They still languish behind us, now 50 or so years behind us, whereas we have the land rights resolved in a way where you have more alignment because you have corporations that you're working with and you're somewhat aligned in driving project. So we have so many positives working for us, it's important to look at that project and go, what made it happen.

Now, part of it was, you know, that it had Shell at the helm, and Shell really wanted to get the project done. But you can also see that the provinces and Canada made necessary concessions to put that over the line, and it benchmarks well with other projects that have moved forward with respect to property tax and corporate tax. Thank you. So Canada is moving forward They did some concessions. It's looking positive for them and we need to get on the ball.

Okay. Thank you for your comments. Okay. Repson of Galvin. Thank you, Co-Chair Foster.

Through the Chair, quick question for you. So this is around the investment. If we choose to invest in extra, this $4 billion folks have mentioned, if we choose not to? I guess is my question. Is that going to slow down or stop the project?

Through the chair, Representative Galvin, again, as we've described the preemptive rights, investment will have been made and we'll have the option to take 25% of that investment. So it will not slow the project down. It's an option that we have to be able to provide to Alaska should the legislature want to who invest, make that policy call. Follow-up? Follow-up?

Thank you. So just to reiterate, if we chose to put our $4 billion either into the permanent fund to help that grow and grow and grow so that we get bigger PFDs or workplace development work that we certainly need to do or other sorts of energy projects or diversifying our economy in other ways, if we chose to do that with that $4 billion that is hanging out there as a possible investment for us, we will not be slowing down or stopping this project. Is that true? Through the chair, Representative Galvin, that is true. Okay, thank you.

Okay, and so as I mentioned earlier, what I wanted to do was take a break after slide 14.

Normally we would be done by 3:30. 3:30. If folks have commitments later afterwards, if you could let me know. What I'd like to do is take a break and maybe meet with my co-chairs and find out how much farther we want to go. We also need to set in stone what our meeting tomorrow is going to be before the 4 o'clock scheduling deadline.

So it might be actually maybe slightly more than 5 minutes. So, uh, House Finance will take a— at ease at 3:34 PM.

There you go. I'll go ahead and call House Finance back to order at 3:50 PM. Again, House Finance back to order at 3:50 PM. And I'm just going to wait for folks to kind of slowly mosey back on in here, and I'll make a couple of announcements. And so just to let folks know, I'll stall for time a little bit by just kind of summarizing what we've done so far.

And what we have done so far is we've gotten through slide 14. And so next we'll be starting on slide 15. And as I mentioned earlier, earlier, we're going to be holding questions questions until— we're breaking this up into sections, and so we're going to hold off on questions. The next break for questions will be after slide 19, and then after that, questions— we'll take questions at slide 23. I think we've gotten most everyone in here, and so the big announcement that I wanted to make is what we'd like to do is go until slide 23, and then we'll call it a night, and then we'll pick, pick this presentation back up first thing tomorrow at our meeting, and we'll finish this presentation.

And then the presentation we have afterwards will be, I believe it was— I think we've got invited testimonies after that, but I just want to let folks know that we'll come back to AGDC at our 1:30 meeting tomorrow, and the intent is to finish slides 24, I think, through the end is, I believe, 36. So with that, Mr. Richards, if you'd like to start us back up on slide 15. And again, just for folks who are just coming in, we're going to go up until 23, and then we'll call it an evening. So with that, Mr. Richards. Thank you, Mr. Chairman.

Again, for the record, Frank Richards, AGDC. So we talked about, you know, a little bit of history going through 2020, but we wanted to talk about our engagement again, looking for those outside investors to be able to come in. So from 2019 through 2024, we were really out and soliciting private sector partners. Partners. That was the intention of the board, that we bring in qualified parties.

So that meant that we had to put ourselves out there with a public offering, meaning putting out there with a prospectus on, on what it would be to come in to partner with AGDC on the Alaska LNG project. To help us in that effort, we reengaged with Goldman Sachs. We had previously worked with Goldman Sachs, and then there was a year or two hiatus. But then when they came back to helped us in terms of not only identifying who private developers might be or investors, but helped us work through a development and a PAC to be able to present to them. And I would really like to identify the strong support that we got from our congressional delegation.

In particular, Senator Sullivan and Senator Murkowski, again, both participated in the work for the federal loan guarantees becoming eligible for the Alaska LNG Project. Previously I mentioned just Senator Murkowski, but it was actually both of the delegation who had the strong support in gaining that for us. Senator Sullivan was active in working with our Asian allies and countries to be able to help and promote this country. So there were several trips that he took on trade missions to Korea, to Japan, to Taiwan that both AGDC as well as Governor Dunleavy participated in to be able to help identify to those markets where we are, where we're with the Alaska LNG project and how we were advancing this now with private developers. And in particular, in the country of Japan, at the time, Senator, or U.S.

Ambassador Rahm Emanuel was the U.S. Ambassador to Japan, and he took up the Alaska LNG cause as a primary mission. And was extremely vocal and active in the country of Japan as well as in in the US in terms of identifying this as a LNG project as a strategic asset that the US should be working towards with our Asian allies, specifically, you know, with the actions of Russia in the Ukraine. So those parties, whether it be our congressional delegations, those members of the administration that were working to help the project, did give us a great bit of opportunity that we then took advantage of to be able to present the Alaska LNG Project. So within the state though, we also again continued our presentations to the legislature and to any of the outside groups that wanted updates on the project, including local governments, our interactions with the Alaska Native Corporations where we have extremely strong support and actually worked with them on, you know, land land leases to be for the pipeline has been extremely valuable in terms of their support for moving the project forward.

And our board meetings are always open to the public. They're public noticed and available for anybody to listen into. Overall, during that time frame, we've had about 130 different outreaches with open houses to be able to help the public identify where we were in moving the project forward. And in particular, to enticing the developer, in particular Glenfarm, in June of '22 is when we actually had our first initial engagement with Glenfarm. And it was that, um, maybe GasTech, GasTech in Korea at the time.

So that was again where Goldman Sachs had identified this was a private developer that was looking towards developing LNG We made the initial conversation and again, we parted ways. ExxonMobil, though, stepped in and also helped to recommend that we meet with Glenfarm and made the introduction directly to Glenfarm CEO Brendan Duvall. So this was again ExxonMobil identifying and helping us to try and find partners to be able to take on the leadership role of the project. So that helped tremendously. And we then had subsequent face-to-face meetings and we identified to them at the time the concept of phasing the project because of the concerns around the Cook Inlet gas supply for Alaska and the need to be able to hopefully use North Slope gas to be able to meet our energy needs.

So during the time frame in 2024, then we had more advanced discussions. We went to New York and met with them. And ultimately, that culminated in a letter of intent that we signed with Glenfarm that allowed for due diligence by essentially both parties to be able to look to see if it was going to be a good fit. But at the same time, we did carve out that we could also be talking to other potential lead parties on Phase 1, really as a contingency, because we saw the need for that Phase 1 project moving forward. But in December of 2024, an amendment to the LOI was executed where we had a draft term sheet setting forth the key terms for the definitive agreements.

And then that kicked off a 60-day period where we actually then negotiated the definitive agreements. So again, key timeframe from December through March to be able to work towards definitive agreements and have Glenfarm become an investor in the project.

So the transition then that occurred after the signing of the development agreements on March 28th, 2025, was that we provided them 75% ownership rights of 8 Star Alaska. And for that, then they would take on that responsibility of advancing it as the majority owner and provide the funding as well as all the resources necessary to move the project forward with engineering in compliance with environmental authorizations and responsibilities. And that— for approximately a 3-month timeframe, we transitioned with Glenfarm because we had the staff available within AGDC to be able to help in— that would have been doing that work previously. And predominantly, most of that staff is now working for Glenfarm in those same roles. So it was great continuity.

For our engagements with Glenfarm, we meet with them weekly on various work streams, as I described earlier, whether it be engineering or whether it be in terms of some of the commercial efforts. And then we have formal board meetings at least quarterly, but we have what is called is our development consultation meetings that we have monthly, and that's where they report to us their advancement commitments on various work streams. And that's where the governance that we have is to make sure that they are advancing it in a timely enough fashion to be able to meet those diligent development efforts.

To you. Mr. Kissinger. Matt Kissinger for the record. So what is 8 Star Alaska? We're going to go into this a lot today and then more in depth tomorrow.

So it is an LLC. Uh, it's structured as what's called a series LLC, where you have your top co— your top corporation, which is 8 Star Alaska, and then you have 3 series or 3 subsidiaries under that: 8 Star Pipeline, 8 Star LNG, and 8 Star GTP. Um, it's not a public corporation. It's not an extension of AGDC. It is a private corporation that AGDC owns 25% of.

It's subject to private sector fiduciary standards, commercial restrictions, and then the confidentiality obligations, which I think that there's been a lot of discussion around that as we manage that carefully.

The managing member has primary authority as it's structured, as all these development projects are structured, so that the developer is able to move the project forward. And we have more like stopping rights, and the stopping rights are around them not meeting the needs of Alaska as you— as we'll go further into these Alaska Advantage principles. And what drives that is, you know, getting gas to Alaskans, getting gas at the lowest possible price to Alaskans, building up an Alaskan-based workforce and having a strong Alaska presence. These are all the standards that are in the Alaska Advantage principles. Principles that we look to as we enforce our rights within the agreements.

We'll talk about the evolution of 8-Star so far, and then it sounds like tomorrow we'll spend the bulk of time talking about the evolution of it into the future. So in 2018, that's when we actually created 8-Star, and we created it really as this vehicle. We needed to bring in private investors. You can't bring them into AGDC since it's a corporation of the state of Alaska, so we created a subsidiary as the vehicle in order to do that. It's also driven somewhat by the way our permits are.

So we have one single FERC authorization, and so we needed one company to hold the FERC authorization even though we want to attract different investors into different parts of that project. For example, you're going to have investors who like to take on pipeline risk. They see that as very low risk for them, more of like an annuity type investment, whereas others are going to want to have more exposure to things like your commodity costs, and so they'll be more interested in the LNG LLC as opposed to the pipeline. LLC. In 2023, as we started the efforts with Goldman Sachs, that's when we expanded this out to have the 3 subsidiaries.

So 8Star Alaska LLC created the 3 8Star ACC Arctic Carbon Capture. Again, that's the gas treatment plant, 8Star Pipeline, 8Star LNG. And then it took us 2 years to find the right partner. A big part of that was phasing the project, as Frank just mentioned. And as Glenfarm came in, then they took their 75% of 8 Star Alaska and we've kept our 25%.

And we've structured it so that that's a non-dilutable 25%. So that is in perpetuity. In fact, the agreements don't say you will get your equity return based on your portion of ownership. It just flat out says you get 25% of the remittances from this company, from 8 Star. 8Star Alaska.

Um, now underneath that, and we'll again, we'll go into this more tomorrow, but you have 8Star Alaska owning 100% of each of those 3 subsidiaries. As we bring in other investors at FID, the assets will be owned by those subsidiaries and those other investors will come into those subsidiaries. And that's where we will have our right to directly invest as well, up to 25% of each capital raise. So that ultimately will have two things: direct investment and indirect investment. We'll have indirect investment in each of those three subsidiaries through our 25% ownership of 8 Star, and we have this opportunity for direct investment or direct ownership through the option.

Okay. We've got a question. Representative Hannan. So on slide 19— thank you, Co-Chair Foster. Mr. Kissinger, when we— who will get to take the 45Q tax benefits, protections, deductions, I'm not sure how we frame that, for the Arctic carbon capture?

Are those percentagely divided? So let's just say that all the major oil companies on the North Slope decide to be investors in that for carbon capture. Do they each get to take the 5%, 10%, or is it 8 Star Alaska that gets the 45Q benefit, or is—. Yeah. Representative Hannan, through the chair.

It's Matt Kissinger for the record. So the way the 45Q law is written— and I do want to— I want to address some misconceptions that are out there while I answer your question. But the way they are written is that the owner of the facility that's removing the carbon, the CO2 from the air, they earn that credit. Now, they can then distribute that credit. So you're going to have 8 Star ACC LLC under this one as the owner of that facility.

So all the investors in that would share in those benefits, but through their ownership, not through directly receiving these tax offsets. Through an agreement to sell send what's called the acid gas. So this is the waste product that comes out of the Arctic Carbon Capture Facility, mostly CO2 with a bit of H2S in it. That has to go somewhere, and the likely place to put it, especially for Phase 1 but probably for the full thing, is back into Prudhoe Bay. Because you're talking about a significant amount of gas that you'd be taking out, and you want to get it back in the ground for pressure support.

And then also because CO2 is miscible with with some oil, and so there may be some benefits. Again, I can't speak to that as not being the operator of Prudhoe Bay, but in other places they do use CO2 for that purpose. So to answer your question, they'll be shared somewhat, but they actually accrue to 8 Star ACC. Now, to misspell some myths, 8 Star ACC costs way more than it will receive in these 45Q credits. So it's not— some sort of— I've read people talk to it as like CO2 mining, or it's a CO2 scheme.

It's not. You have to remove the CO2 for technical reasons. There is a lot of CO2 in this gas, unfortunately, as it gets produced. And the fact that the 45Q credits exist and apply are a great benefit to the project, but they certainly aren't the make or break for this project. Follow-up, Representative Hannon.

Thank you, Co-Chair Foster. So, Mr. Kissinger, uh, will other North Slope producers who could use carbon capture but maybe aren't selling gas to the gas line, can they pay for time at— pay for it to go through the Arctic Carbon Capture Facility so they don't have to build their own? So are there more potential users of the carbon capture facility than gas line producers, or are they completely separate? And I don't understand the engineering. Representative Hannan, through the chair, it's designed to— it's designed to go with the pipeline, and so it's designed to meet the demands of the pipeline.

So it wouldn't really be some sort of a free-use tolling facility just to remove CO2. It's to condition gas that goes down the pipeline. Okay. And then I have one question from an earlier slide. Back on slide 15, under public engagement, legislative representatives who are assigned to the board.

Who are the legislative representatives assigned to your board?

Through the chair, Representative Hannon. The Speaker of the House and the Senate President assign members to the board. So let's see. So currently, I believe it's Senator Giesel is the designee for the Senate. And for the House, it's Representative Elam.

And for the record, that's Representative— Mr. Richards. Representative Hannon. Thank you. Those are my questions. Okay, Representative Gelvin.

Thank you, Co-Chair Foster. Through the chair, I am asking about the indirect investments because you had mentioned that we would do direct and indirect. And one of the indirect investments, well, I'm sure the largest, is related to all of the things that we are doing with permitting and things like that. But I was thinking about some discussion around gravel, and I think that there was kind of a large bit of gravel that was talked about with related to this project. And I think of that as sort of an indirect investment when it comes to maybe the pipeline itself and the building of it.

And I, I quick, you know, back of the napkin math told me that's up to $60 million of gravel. That we will be agreeing to help with building roads or whatever. So how does that fit into this puzzle? Mr. Richards? Through the chair, Representative Galvin, when we talk about the equity investment, let's say in the Pipeline LLC, there— that can come through either cash investment, or what we're hoping to do is to utilize state materials, state assets, to be able to provide to the project in lieu of cash.

So in your example, yes, the gravel that will be used for access road and pipe bedding and pipe backfill and pipe storage yards and camp facilities represents about 20 million cubic yards of material. So that has a value of roughly $60 million. And if we are able to then utilize that value and gain equity, then that would be a non-cash option that we would like to exercise for the state. Okay. Thank you.

Appreciate that. Thank you. Okay. And please proceed. We'll go up to slide 23 and come to questions again.

All right.

I actually covered almost all that in the last one. All right. So again, we've talked about the minority ownership of rights within AGDC and what our obligations are and what our responsibilities are in terms of as the state's representative into the project. So we'll move on to then slide 21 and governance.

Okay, so our role, as I've described earlier, is to make sure that Glenfarm as a developer is pursuing these diligent development efforts. And we've talked about what that really means in terms of advancing FEED, putting forth good faith efforts in developing the project and meeting the timelines to be able to accomplish that, and to make sure that there are sufficient resources to achieve to achieve this final investment decision. So that means personnel, that means contracts, that means working with a variety of folks from gas suppliers to labor to key contractors to make sure that that's, that's going on. And from our vantage point, we are seeing that happen on a daily basis. We're either participating in that or we're seeing the outcomes of that.

Most importantly is also that they maintain the resources that were provided to them in these federal authorizations and state authorizations and approvals that we worked for many years to achieve, namely the rights of way, namely the FERC and Department of Energy authorizations that will allow this project to proceed forward. In addition, we've talked about the Alaskan Advantage principles. That's coming up on slide 22. They are meeting those principles in their daily actions. So our role, again, is to be the state's representative in the development of this project.

And that's what we were created for by the legislature, is to be this professional body that takes on the responsibility to advance a project if it's commercially and economically viable to to achieve. So we take that government responsibility. We shifted then from project, really, ownership and development to now one of project governance in our role. So it's a different role for us, and we are embracing that. We are one of 4 members of the 8STAR Alaska Board of Managers.

There's myself, there's a public member, Janet Weese, who was previously an AGDC board member and previously head of BP Alaska. Alaska. And then there are two Glenfarm board members, namely the CEO Brendan Duvall and the Alaska— or HR Alaska President Adam Prestidge. So we meet quarterly and go through our board as well as our development consultation meetings at the same time. So our concern is, though, with some of the legislation changes that we saw is that by adding legislative oversight and certainly restricting confidentiality, it will make our position to govern more challenging going forward.

So I wanted to raise that as a key point.

Now, to the Alaskan Advantage principles. Go ahead. This is Matt Kissinger for the record. So again, these principles, we measure all of our decisions around approving or disapproving contracts that, um, Glenfarm, the developer, are entering into. So one of them is establish and maintain a substantial operational presence in Alaska, and they have continued to grow that.

They have an office on 4th Avenue that they've already grown into the next part of, and I suspect they'll be growing into an even larger accommodation quite soon. Uh, they have to accept interconnection requests from Alaska customers, so they don't get to decide who gets and who doesn't get gas. And as per design, one of those will serve Fairbanks. And I think, you know, we've heard from the developer more recently on their commitment to serving Fairbanks. In-state customers get priority right for 500 million a day, which is more than double the current demand.

That 500 million was designed— actually, when this project was first designed, the pipeline and the GTP were kind of overdesigned by 500 million standard cubic feet a day so that there would be this sufficient buffer for Alaska. And we just memorialized that in the agreement so that they're not allowed to kind of take that from us. And then further, capacity has to be expanded to accommodate increased demand above that 500 million. And then finally, they may utilize differential rates— and I'll talk about that in a second— only where they both help maximize the flow of natural gas through the project and achieve the lowest possible cost of gas for Alaska utility customers. And this will come through in a couple of different ways, this different— the concept of differential rates.

One is, it would be beneficial— there's shutdown facilities in Nikiski right next door to where we're building an LNG plant, for example. They can't restart at your sort of 12 to 15, 16 cents $18 per MMBtu rate. It's not possible. They won't be able to sell their product into the market. So this is an example where you could do— use differential rates where you sell for a lower price to them that meets their hurdle rate, but in doing so, you get more gas down the pipeline and you help bring down the utility customers' rates in doing so.

And so they only can do that where it achieves the lowest, not a lower price, but it was worded as the lowest possible cost of gas for Alaska utility customers. This also comes into the concept of rolled-in rates. You'll hear this term again and again as people talk about pipelines. Rolled-in rates. This is when you expand a facility and instead of charging your incremental customers just the incremental cost of the expansion, you take the total new cost and you distributed amongst all the users, including the new users.

And so everyone's paying the same price. That's how it has to happen. Everyone, everyone would have rolled-in rates unless you have differential rates. And so again, we get to take advantage of differential rates. We get to take advantage of not having rolled-in rates when it achieves the lowest possible cost of gas for Alaska utility customers.

And then Developer Scorecard. So how have Glenfarn done in the year since we brought them here? You know, we have regrettably heard different feed milestones be put out there. As a developer, just try and light, you know, ignite the energy underneath Department of Energy or others that are, you know, that they are going to for the project. But unfortunately, you know, also it erodes credibility when you don't meet those.

We don't look at a FEED milestone. We look at everything that's going into FEED— sorry, an FID milestone, a final investment decision milestone. When we think of it, we go, what does it take to get to an FID? And it's these things that they are working on upstream gas supply. They now have gas sale precedent agreements with all the producers on the slope for more than enough gas for Phase 1, including, you know, all the foreseeable potential growth opportunities.

And it's a real mix of differently priced gas and different amount of flexibility in getting the gas. These are gas sale precedent agreements. That means that they're not the final agreement. So we have to watch the developer now convert those into the final agreements, and we are watching them them do that right now. Downstream gas sales, they've entered into letters of intent with Enstar and Donlin, and now they are also advancing those final agreements that I talked about.

And the Enstar one specifically would be, you know, sale to a utility. So foreseeable that would be regulated under the RCA. Feed, we mentioned how they've completed feed for the pipeline. They are working on feed for the LNG facility. Facility in the GTP right now in the selection process of the feed contractors.

Construction management, who's actually going to build this? We've heard a lot about, well, Glenfarm, they haven't built a thing in the Arctic. Remember, they're more like the quarterback or the conductor of all this, but in reality, it's all these other companies that they're bringing in, and primarily it's Worley with respect to the pipeline. Worley will be the EPCM, engineering procurement construction management, meaning they are also managing that construction as you go forward. Who are they managing?

They are managing the pipeline construction contractors. They have announced conditional awards to 6 major pipeline companies to move this forward. And then what are they moving forward? Well, they have to build pipe. You need pipe for that.

There is steel supply already under contract. POSCO. POSCO was an interesting contract because it's steel supply and LNG sales. And then they've also gone out to the rolling mills and gotten the actual line pipe where it's rolled into the pipe that you can use. And they have conditional or preliminary agreements for what I understand is two-thirds, and they're closing in on the final third right now.

And then finally, with financing, they've developed the structure They are doing a lot of work in the background. We expect any announcements on that to probably be a little bit later after some of these other ones are firmed up.

So we think, just in summary, we feel that they have done an amazing job over the last year. They have done a lot of work and they have really advanced this project in a meaningful way in a short period of time. Okay. Thank you. Representative Hannan.

Thank you. I'm going to start at the top of this slide, Chair Foster.

What is the difference between a gas sales precedent agreement and a sales agreement? I understand that it's not a final gas sales agreement, so what are the differences between the two? Representative Hannon, through the Chair, think of a precedent agreement as a fully termed-up kind of heads of agreement, if you're aware of what that is. So it's all the important key terms, like the price has been agreed, the term, the duration has been agreed, your take-or-pay provisions have been agreed, all this. To turn that into a final gas sale agreement is more like all the long-form writing.

So that's bringing in the legal teams to long-form write that. But the GSA GSPAs have all the very difficult key terms already addressed in them. Okay. Follow-up on that? So I assume then the parties who are privy to it are both sides of the contract, and included in that would be 8 Star Alaska.

So I presume then you have some of that, what's being deemed confidential information that we can't know until a the sales contract is public, but you as an investor in 8 Star Alaska already know what these are. Is that correct? Representative Hannon, through the chair, yes, that is correct. With the exception of the Pantheon one where actually there was a press release that even released the price on that one. Okay.

Thank you. And then can I— on slide 21, Mr. Richards, through Chair Foster, The final bullet on slide 21 says adding new legislative oversight and restricting confidentiality, blah, blah, blah. And I hate to be dense, but what do you mean by that? What is the legislative oversight? Because sometimes we have to be, you know, we're looking at 4 bills that have very precise language.

Understanding its impacts is something I've strived, but I haven't seen any of them have things that I would view as legislative oversight. So I need you to help point to what you perceive as legislative oversight being purported in this legislation that's untenable to you. Mr. Richards? Through the Chair, Representative Hannan, what I meant by this bullet was that specifically in regards to the confidentiality, and there were some versions of confidentiality requirements that were in in the various bills that required AGDC to essentially limit AGDC's confidentiality protections for— that we'd entered into and provide some of that confidential information to legislature or legislative consultants. So that's what I deemed as problematic, specifically the ability to be able to enter in an agreement to share confidential materials with an entity and then have to identify that, oh, but by the way, we are going to have to share this now with a third party, which is the Alaska Legislature or their consultants.

That would be very challenging for those parties to agree to enter into that confidentiality agreement or be willing to share the confidential terms with us. Dad? No. Representative Hannan. So let's presume that— thank you, Co-Chair Foster.

Let's presume the legislature decided to take an equity interest, and I'm going to go on the really conservative. We took a 1% equity interest out of that 25% option that we'll have after FEED. Would that then, as an equity investor, give us the rights to the confidential agreements and sales contracts? Information that other investors already have? Through the chair, Representative Hannan, the offering for the equity will be at the same terms that the— under the prescriptive RIPE options.

So those equity agreements that will have already been contracted with the likes of BlackRock or GIP or others is what the legislature will have access to that information. So it won't be all the way upstream into the existing agreements, the definitive agreements that AGDC has. It'll be on that equity offering. Correct? Yeah.

Representative Hannan. Thank you, Chair Foster. So am I to understand the way you just described that, that the equity investors will not have The confidential information that's included in sales contract agreements before they make their equity investment? Representative Hannan, through the chair, Matt Kissinger for the record. Assumedly those actually would be included because those are necessary for the financial decision.

So yes, those would be included. I think what Frank was referring to is the agreements at the 8-star Alaska level. Would be less important. You'd be investing into, for example, 8 Star Pipeline LLC. Now the 8 Star Pipeline LLC governance documents would be part of all of that, you know, information that you'd be able to see as an investor, as well as the contracts that are pertinent to the financial flows within 8 Star Pipeline Alaska.

Now as dividends come out of 8 Star Pipeline Alaska and go to one of its owners, which would be 8Star Alaska, these other investors wouldn't have line of sight to then what happens with that. Okay. Thank you. Okay. Representative Gellman.

Thank you, Co-Chair Foster. Through the chair, I'm excited to learn more about slide 23 where it talks about Linepipe and all the work that's been taking place already. I just heard, I think, that there's been some orders already kind of put in place. And I— would you help me better appreciate what the timing looks like? Because what I've heard from some, I'll call them engineering geeks, is that this pipe needs to be ordered well in advance.

42-Inch is a unique size and all of these sorts of things. So can you give us just your short version of what this looks like and how it relates to the timing of getting to the first bit of dirt moving and pipe laid. Through the chair, Representative Galvin, again, the 42-inch pipe has been the design concept since this project originated back in 2014. Yes. So the goal has been then to identify what are the pipe suppliers that could produce the steel and roll the steel into this, this 42-inch product and deliver to Alaska in a timely enough basin.

So what Glenfarm did was go out to the world market, look at the inventory and the opportunities out there, and invited folks to come in and present what they could perform. And so, as Matt described, one of the original ones was POSCO. So POSCO signed up. They wanted LNG offtake, but they also were steel manufacturers, so they were going to be able to provide some steel for the pipe rolling. In addition to that, these two pipe manufacturers, Corinth and Euro Pipe, are again worldwide large companies that produce various sizes and grades of pipe.

The pipe itself based on the conditions that we have in Alaska is going to be X70 and what was known as X80. So these are the grades of the steel necessary to be able to withstand not only the pressures of the pipe but movements of the pipe due to our challenging discontinuous permafrost. So Glenfarm worked with the pipeline companies to assure that they could actually produce that amount of these grades of pipe and be able to deliver it. So they have actually then had conditional awards to both Corinth and Euro Pipe for approximately two-thirds of the actual pipe necessary for Phase 1 of the project, and the remaining one-third is actually now being negotiated for a better price. So thank you.

Co-chair, if I may. Representative Galvin, thank you. Can we keep tracking that along? So we know we have folks who can put together two-thirds of it. You're still working on the last third.

What is the timing if we should, let's say, July 1st FID? How does that work? Are we prepared to start moving things, and do we need to do something different with, I don't know, tankers or with the railroad, things like that, in order to get it moved to the right place, and what are you going— is there any need for us to be concerned about it getting there ASAP? Through the chair, Representative Galvin, the timing of the actual letting of the contract, I don't know. The, the delivery of the pipe and the logistics plan to deliver that pipe from the point of entry to the pipe storage yards is being worked.

There's discussions and negotiations with the Alaska Railroad to be the main transporter of that pipe. So Seward is going to be the— likely the point of origin with backup from the Port of Anchorage. The reason being, again, the amount of truck traffic that would be necessary to move this pipe on Alaska's highways, specifically in our summertime, would be extremely challenging. As you can imagine, during Kenai dipnet fishery, and then you've got pipe trucks moving down the Seward Highway, it would be very difficult. So the goal is to be able to utilize the railroad, which has a very good delivery system from essentially in Mat-Su all the way through to Fairbanks.

And then the pipe for the Dalton Highway portion would then be transshipped by a truck from Fairbanks north. So that logistics planning effort is clearly underway and advancing. Thank you. One last follow-up, please. Representative Gallivan.

Thank you, Co-Chair Foster. So what is the lead time needed to get that pipe up, if you have that established?

So ideally— through the chair, Representative Gallivan— ideally, once we have a final investment decision, the The conditional awards will have been converted to definitive awards, and you would have initial pipe that would be starting to be rolled and then delivered within a couple months— couple months— into Seward. And then there will be pipe ships coming every month for the next 16 months. Thank you. OK. Representative Josephson. Yes, on slide 23, the gas sales precedent agreements, developer has entered into those agreements.

So, um, I, I understood that, in fact, a week or 10 days ago there was one such announcement. I didn't know that they covered the, the issue of price. Um, when we talked to our consultant, Mr. Fulford, yesterday, he didn't suggest that, that, uh, the contract covered price. That was an imperative feature on his slide deck, I think taken from DOR, showing these heat charts where we had to be in the top left corner to reach or come under that $10.41 cost at delivery.

Is it your testimony that, in fact, the producers have gotten into that sort of detail, and someone knows what they're going to charge. Matt Kissinger for the record. Representative Josephson through the Chair, we can assure you that price is included in each one of those agreements. So price has been agreed in each one of those agreements. Representative Josephson.

And I assume that the sort of zone, it was a zone of possibility or something, showed dollar, dollar $1.50. When you got beyond that, you were in a troubled world. Went out to $5. And I guess we're in that zone. That's—.

Without your reporting it, I guess we wouldn't have this hearing if we weren't there. Representative Josephson, through the chair, we have as AGDC, even prior to Glenfarm coming into the project, we've put out there this assumption of $1.50 and I think we are still confidently within that assumption range.

Okay. Thank you. Okay. Any further questions up through slide 23? Seeing none, I think we are going to go ahead and call it an evening here.

Our next meeting is scheduled for tomorrow, May 28th, at 1:30 PM, and at that meeting We'll have invited testimony from Fairbanks North Star Borough, Matnuska Susitna Borough, Kenai Peninsula Borough, as well as Mr. Larry Pursley, who will be talking about the FERC process. And if we have any questions about FERC, we can certainly ask him. Representative Ballard. Can you repeat again, please, Co-Chair, who's invited testimony? Because I have a follow-up question.

On that. Sure. That's the Fairbanks North Star Borough, Matanuska-Susitna Borough, Kenai Peninsula Borough, and Mr. Larry Pursley talking about FERC. Thank you, co-chair. So my question is, the individuals that are testifying, who would those be?

Maybe if I could have Mr. Brody Anderson come up and specifically address who with each of the boroughs are coming to speak to us.

For the record, Brody Anderson, staff to Representative Foster. The presenters for the boroughs will be Mayor Greier Hopkins for the North Star— Fairbanks North Star Borough, Mayor DeVries for the Metanuska-Susitna Borough, and then Mayor Machicki for the Kenai Peninsula Borough. May I do a follow-up? Sure. Ms. Mallard.

So my question is, are we going to have other municipalities and boroughs testify, or is it only these three? We were hoping to get the North Star Borough— I mean, North Slope Borough, but I think there's a timing issue that we're trying to work out with them. Certainly open to other boroughs if you've got suggestions, though. I do. How about the Municipality of Anchorage?

Okay. We will work on that. Mr. Anderson? Any further questions or—. Preferably someone who's in favor of the AKLNG.

Okay. Yeah, just saying. Representative Stout. You answered my question. Thanks, Patrick.

Okay.

Okay, so seeing no further questions or comments, we will go ahead and be adjourned at 4:36 PM. Thank you.