House Finance, 5/28/26, 1:30pm

Ooh. Okay, I'll go ahead and call this meeting of the House Finance Committee to order and let the record reflect that the time is currently 1:36 PM on Thursday, May 28th. 2026. And present— let's see if we've got folks online here. Um, looks like we do have Representative Moore online, and I suspect we'll have some folks coming in here.

But we do have with us Representative Bynum, Representative Co-Chair Sharagi, Representative Co-Chair Josephson, Representative Jimmy, Representative Galvin, Representative Tomaszewski, Representative Hannon, myself, Co-Chair Foster, and in the audience we have a number of, um, Legis— uh, Representative Eichide. Uh, let me back up here. I don't know if the mic was coming through very good on that. We've got Representative Dybert, Senator Giesel, Representative Eichide, Representative Mears, Representative Costello, Representative Sadler. Did I miss Senator Holland, and appreciate you all being here.

Thanks for joining us. And so before we start, just a reminder, folks can mute their cell phones. And we will be returning to House Bill 381, that is the Gas Line Bill. And we do have invited testimony today from borough mayors from Fairbanks, North Star Borough, Matanuska-Susitna Borough, Kenai Peninsula Borough. And then we will be returning to the presentation that we started yesterday from the Alaska Gas Line Development Corporation, AGDC.

And then if we have time permitting, which hopefully we will, we'll then go to Mr. Larry Pursley, who will be speaking to the jurisdiction of the federal regulation of LNG projects and gas line— gas pipeline. With that, first up we have invited testimony from Mayor Greer Hopkins. Mayor Hopkins, I see you here. And if you could put yourself on the record, we appreciate you flying down to be with us. I assume you flew or did you drive?

Definitely flew, sir. Definitely flew. Okay, good deal. It works well. I can sleep on my bed, on my own bed, on either side of the hearing.

So thank you all for having these here in Anchorage. Probably nice for a number of you to sleep in your own bed too, and for those that will get home after this, I look forward— I know you're looking forward to that. I remember those days myself. So for the record, my name is Greer Hopkins, the mayor of the Fairbanks-North Star Borough. Thank you all for having me here today, as well as ensuring that the voice of the municipalities is consistently heard and listened to throughout this.

It's been really important. You know, we started our hearings and our meetings rather with AGDC and representatives from the governor's office back in January. And fairly consistent conversations, especially when it comes to what the interest of the Fairbanks-North Star Borough is. And as you're all well aware at this point, I'm sure, that comes and starts and ends— well, it doesn't quite end, but starts certainly, and for the majority of it is access to gas. You know, 12 years ago when the route was permitted for the mainline, it went basically outside of the Fairbanks-North Starboro boundaries, except for the 2 miles of line that would go through it.

So we are about 30 miles away from actually being able to utilize any of this gas from the mainline. So how we get that spur line to Fairbanks built and funded as part of the project is essential. We are currently paying between $24 and $26 per MCF for natural gas for our 3,500 ratepayers in the Interior Gas Utility System. We could hook up a number more people onto that— businesses, families, and as well as potentially GVEA— if we were able to get access to affordable gas. When I was testifying in House Resources, I said, "We don't need more gas, we need affordable gas." We have a trucking system set up right now that trucks it from the North Slope in cooperation with Harvest and Hilcorp.

It's wonderful having the first, you know, natural gas commercially delivered from the North Slope in Alaska, so that's a big benefit for us. Cost. Um, at the same time, that gas comes in expensively. Uh, it was about just about exactly the same price, just a little bit lower, when we were trucking it up from Cook Inlet for decades there. And since the Interior Gas Utility was created in 2015, we have tripled the number of customers.

But we have a lot of lines laid around the community in North Pole and in the city of Fairbanks and in the borough now as well. The constraint that we have is Is it affordable? Does it make a difference for people to hook up to that natural gas? And right now, I mean, it would right now with the price of oil, but of course that roller coaster sometimes is less per BTU to stay on diesel than it is for to switch over to natural gas. Cleaner, better, you know, maintenance of your own personal heating system, but not economic all the time per BTU basis.

So as we've been talking with Glenfarm and the House Resources Committee and AGDC, how do we get that access to gas for our community and allowing us to spread both economically and for the benefit of the residents to clean our air and to get access to it has been the big question. And I will— so I'll go ahead and take the next step and thank the legislature and especially The House Resources Committee, um, Co-chair Dibert did fantastic work, and the entire Interior delegation banded well together to make sure that that language was in there coming out of House Resources and onto the House floor. Um, and so that was— that language that we have in the bill today in HB 2001 is language that has been agreed to with Glenfarm and the Fairbanks North Star Borough. So this language that we have in there, I ask you, please do not change what is in there without working through both us as a municipality and Glenfarm to make sure it will still not hinder the project and will deliver what we need. It's slightly complicated in there, but I believe you as a committee have heard from Ledge Legal about why it needs to be structured in the way that it is.

And then there was an amendment on the House floor that allowed the economic viability language that was put in to be well-defined, that it will work for Fairbanks because some people might not say that the cost of gas would be economic or the volume of gas, but the way we are working today and with access to this line, it would work well. So, you know, the spur line in this language as it is right now is— it's an eligibility requirement. If the spur line is not being permitted by the developer, by the time that they're getting constructed, they would not get access to the full tax break that is being debated, whatever the result of that that comes out of the legislature. That trigger is important to ensure that a spur line gets built and we're not left out in the proverbial cold. If we are relying on the will of the private sector to get this built without that language that triggers the tax break, I don't— I'm not going to hold my breath that we would get access to the gas.

So that is essential for us to be able to ensure that the Interior can get access to whatever the price of gas that comes off this project is. The second line is that it has to be real— the second aspect of the language in there for the spur line is it has to be real and functional, so it has enough capacity. To reasonably, uh, forward cast what, uh, the community is going to need when we get more affordable gas. If when we see the export facility and people do switch over, how do we make sure that we have enough gas to support Eielson, Wainwright, Fort Wainwright, the Army base, Eielson Air Force Base, the university switching over, and especially the Golden Valley Electric Association. Right now they have no gas-fired plants because, um, the cost of what gas is going to come from and the potential concerns on long-term trucking plans.

So as that utility looks long, long down the line, ensuring that we can get access to them is very important. There's just— I mean, they're increasing their rate by about 30% right now for the coming months because of the price of oil due to the war in Iran. They sent out an email just yesterday saying that they're increasing their power purchase costs, which is buying their fuel stock by 8 cents, which is going to be a huge hit for us. So ensuring that they have capacity as well as what we'll know in the coming weeks from the Department of Defense talking about AI data centers on bases. Senator Sullivan put into that legislation that language that Eielson Air Force Base is going to be a potential landing spot for an AI data center.

If that does happen, they are responsible for generating their own power within that language, and so they'll need access to that gas. So what that looks like, how we forecast that, we'll know in the coming weeks, which will also allow us to, to know what this diameter of the spur line is going to be. The spur line also has a defined timeline in this language, which is very important. So we're not waiting a decade further, but we wanted to make sure that we, uh, or rather, we agreed with Glenn Farn that we don't want to necessarily constrain construction— define that we— the spur line must be built in order to get the tax by the time the main line— the tax break by the time the main line is turned on. So with that, we're working on permitting language.

So this bill requires permitting in a good faith effort to go forward in order for them to get that break, that there could be an obstacle to overcome with permitting. But as long as that is moving forward, I'm confident that that will happen. Additionally, there are requirements that the regulatory commission will have to be checking on that and making sure that it fulfills the language in the bill. Fourth, gas has to be affordable. And that means it's being delivered at the lowest cost consistent with safe and reliable service.

And that's something the regulatory commission would look at. And one of the biggest aspects of the language is how the tariff is calculated for us. Ensuring that for— despite me sitting in Anchorage in front of a number of Anchorage and Southcentral representatives, if Fairbanks had to pay for the spur line, then, you know, we should make sure that Anchorage pays for the Anchorage spur line, which would be everything south of Fairbanks. The joke might fall on deaf ears here, but the reality is if we have to pay for a $200 million line across 3,500 ratepayers in the Fairbanks-North Starborough area that gas would not come in economic for people to use. So that tariff being rolled in statewide, system-wide, in the language that is in there currently, is essential to make sure that it works out for every Alaskan along the line to get access to it.

So I think that is one of the most important things that we've been pounding our table— the table on for over a decade now. And so seeing that language in there today is heartwarming and gives me optimism that if this project moves forward, there will be fairness across Alaska to get access to gas. You know, I don't have the language of HB 2001 in front of me, but the bullet point number 2 for the whereases of why we need this project was economic impact for Alaskans. And that tariff language in there allows that language to be fulfilled. The bill also defines economically viable gas sales contract that I was talking about.

When the bill moved on to the House floor, it had language in there saying it has to be economically viable for the spur line to happen. This— the language that was passed on the House floor is satisfactory to us to make sure that that is fulfilled. You know, one other thing I'd like to bring attention to that's not in HB 2001 is the local taxation rates. Currently, you know, one of the debates that is moving forward in this bill is What title of Alaska statute do we put the spur line under? Moving it out of Title 43 can allow different payments in lieu of taxes, different taxation rates, not using the full 20 mils.

Currently, the way this is structured, the spur line is under the Title 43 language. So that is really important. Well, there was an amendment passed by and introduced by Senator Myers in Senate resources that was really good and gives flexibility to us as a local municipality. Because if we— how we tax the spur line, if we're forced to be taxed under the current language of the full 20 mills, it would add in the neighborhood of $500 per year to each local IGU ratepayer. That language is really important to give us the flexibility in that from that amendment to figure out a payment in lieu of taxes, uh, with a developer, whoever builds the spur line, whether it's Glenfarm, whether it's an Enstar or IGU or a joint venture or anybody that wants to show up.

Allowing us to have that flexibility with a good sunset on that of 10 years is really important for us to ensure that our impacts get covered as well as the ratepayers see a strong benefit. From the gas and it remains economic. So that I would urge introspection on by this committee to ensure that you are looking at what that cost would be. Moving it into Title 29 could work. Moving it— giving it specific language that was addressed in that amendment could work.

It is flexible, but that is really important as well. So I ask that you look into addressing that language here as you move forward in this committee.

With that, you know, there's been some other levers in the legislation that's moved forward. As you're— I'm sure you're going to be taking it up and asking questions. How the impacts to the local municipalities was one of the big conversations we had and struggled to find a one-size-fits-all measure in our conversations with AGDC and the governor's office before the language was introduced to the legislature. You know, the North Slope has its system for covering its costs. All 5 municipalities have different systems.

In the Fairbanks North Star Borough, some of the biggest impacts we believe we would see are solid waste, but we have an enterprise fund. So if they're— that means if the developer is taking waste to our Fairbanks North Star Borough, well, we'll have a tipping fee. So we'll get reimbursed there. And they can't take it to our transfer stations, which we have 13 of, because commercial You can't take commercial trash to those. So they'll go through our tipping fees.

But we have fire service areas, you know, so as there are accidents or impacts along the roads, the main highways as they drive north up the— to the Dalton Highway to construct the line or south down the Parks, they'll be passing through anywhere between 3 and 5 different fire service areas with different tax rates. But they won't be paying the taxes to those. They might be paying the property— that local property tax to us to collect for where they would be located. But the real impacts to those fire service areas for EMT services, for accidents that will happen as we increase— I won't even calculate how many times the traffic of large trucks on these roads— will be a cost impact to us that we'd have to consider. Impact on our roads, depending on where those pipe laydown yards are, is going to be really important.

We've been in conversations with Glenfarm as well as local developers on where those pipe laydown yards will be, but it's going to be the hub for us. They're going to have, you know, thousands of trucks moving through over the next several years during the construction of this project. So where that happens is going to be very important as we take the pipes off of the rail, weld them together, and then drive 100-foot sections of pipe through our community is going to be a big question that we'll address locally, but it'll be an impact. So while the language of how we ask for reimbursements of those funds is going to have some sticking points, and I don't have any specific recommendations on what that language should look like today for that $40 million fund that is in there, the one-time fund for extra funds. I would be happy to answer any questions as best I can today or in this process, and many of you have my personal cell phone, or feel free to email me, and I would be happy to engaged in those conversations about what ideas could look like for that.

Um, going forward, you know, there's not going to be a ton of operations in Fairbanks compared to what we've seen on TAPS, but it'll still be a hub for going north and south and, um, a lot of construction and maintenance impacts, I believe. So, you know, that impact to our community going forward, uh, is going to be real as well. So, um, the funds going forward that are in the bill are a good start. And something to consider within this committee as you move forward. So I'm going to open myself up to questions.

Happy to answer any about how Fairbanks operates, conversations that we've had, the spur line itself, future casting, anything like that. But I want to go ahead and thank again the Interior delegation. You know, this has been a major concern for us for 12 years. How are we going to get access to the gas once it was routed away from us? And this language that we see in there today is the best thing that we have seen for our community going forward.

So the 100,000 residents of Fairbanks North Star Borough are seeing hope that we'll get affordable access— affordable access to affordable gas instead of having to pound the table and build it ourselves. So I appreciate that language from the Interior delegation and the legislature understanding that and happy to answer any questions. Thank you very much, Mayor Hopkins. And just would like to recognize that we also have with us at the table Representative Allard, and in the audience we have with us Representative Colombe And so thanks for being here. We have questions.

Representative Hannon. Thank you, Co-Chair Foster. Good to see you, Mayor Hopkins.

Focusing on the spurline language that is in House Bill 2001 as opposed to the resources version of 381, there are some differences. You've highlighted those, the economically viable gas sales contract, but some of that language speaks to beyond residential users, industrial users. I'm not— I can't remember if it says military very directly, but state agencies, government, federal consumers. Um, you've used the term repeatedly, affordable gas. So for residential customers in Fairbanks, what's that?

Because all of this economic language talks about precedent sales agreements, which are driven by costs that they're going to sell it to you. But I assume that commercial users will probably be buying at a different rate than residential. So But for the residential users of the greater Fairbanks area, what's that price point? Cheaper than it is today is a heck of a start. You know, right now the residential— the difference between industrial and residential users on the Interior Gas Utilities contract are actually not based on how much gas you use or anything like that.

It's based on if you are an interruptible client. And so because we're trucking gas in, that is a bottleneck for how much gas we can bring in. You pay less if you're willing to be an interruptible. All—. Almost all of our public schools are on natural gas, but they have their old diesel boilers as well.

So they're an interruptible client. The hospital, the borough facilities, those are interruptible. So we pay a lower rate, but it's only a dollar or two less. Our—. One of the first questions I get asked often about this is how and if we can, as Interior Gas Utility, can get out of the contract for trucking if this moves forward?

And the answer is yes, we can. There's a clause in there that allows a conversation to be had, and for Hillcorp— the not Harvest, but Hillcorp— to decide if they get us out of that, uh, that contract. And that conversation has to start at $19 per MCF. So underneath that would be the, you know, a start, and that's delivered to what we're calling the city gate. The Interior Gas Utility does have a $5 to $7 tariff on top of where it is today to pay for that North Slope Trucking project to be able to pay for its own tariff and the ADA debt that we are carrying.

But that would have to be then on top of that $19, I believe. So getting it under $19 is essential for us, but that's still not all that affordable gas. So as cheap as we can get it coming out of the legislature is going to be the important aspect for us. So, you know, if it's one price today under— or tomorrow, I guess— underneath the language for the in-state line that gets us below that $19 threshold would be essential. And then as we move forward, seeing hopefully an export facility in the future that would drop that and get to affordable.

So if I can give a threshold, Certainly under $19 and in your $12 to $15 would be my hope. Can I follow up? Representative Hannon.

How long does the contract that I assume it's GVA has with Hilcorp to provide gas currently that's trucked in? Representative Hannon, through the chair, it's actually the Interior Gas Utility that has that contract. GVA doesn't use any natural gas in the Fairbanks area at this point. So it's through Interior Gas Utility and it's It's over 20 years for that contract. So we have— if this pipe doesn't move forward and we see for the next 20 years what we've seen for the past 60 years, we're going to be able to continue to have gas access in our community through that trucking contract.

So follow-up. Oh, what? You're— there's 20 years remaining on your current contract. Correct. And one more follow-up, Chair Foster.

You phrased it in a way that If Hilcorp does— so Hilcorp is the provider, the producer that Interior Gas is buying from. It's completely up to them whether they sever the contract or the contract reads that if you can get it cheaper than $19, you can sever the contract? The former of that. There's no objective coverage, so we'd have to have that conversation with Hilcorp to ensure that we're able to get out of that contract. It's actually with Hilcorp and not with Harvest.

So Harvest deals with the LNG facility that puts the LNG into the trucks that IGU owns, and they get that gas from Hilcorp. So it's actually the Hilcorp end. But, you know, with, um, if we've got a large diameter line that's able to sell gas into it, I'm optimistic that we'd be able to find that agreement with that company. Okay, thank you. Representative Tomaszewski.

Uh, thank you, Co-Chair Foster. Through the chair, uh, Mayor Hopkins Mr. Brooks, thanks for coming down and being here representing the borough. I'm one of those customers who got the GVA letter of the increase coming. It's really quite concerning for the residents of Fairbanks, and I'm glad you're down here to advocate for Fairbanks. And one of—.

You've mentioned several impacts that are going to happen to the community. I'm wondering if you went back and looked at the history of what TAPS brought to the Fairbanks community and the impact overall that happened. You know, right now we have a small homeless population, we have crime, we have other things. Have you looked at what that's going to bring? Because when you announce a major project, people are just going to maybe hop on a plane, hop on a bus, they're going to head to Fairbanks, because that's kind of the choke point of getting to the North Slope.

And they're going to be looking for jobs, they're going to be looking for opportunities, and, you know, rightfully so. There's a lot of opportunities for that. But it also, you know, some of those folks aren't going to find those opportunities and they may end up, you know, part of our population there that may increase the use of services. Police, fire, like you mentioned. Have you looked back and seen what are the consequences originally from TAPS and what it may look like today with the gas line?

Thank you, Representative Thomas Heffke. Through the Chair, before I move forward, I just want to make sure I thank you as well for the amendment you offered on the House floor that would have been similar to Senator Myers' amendment in House Resources that was important to have that dialogue, and hopefully we can move that in this committee. You know, I haven't done a specific evaluation of what the impacts in the '70s were of the Trans-Alaska Pipeline workforce. It certainly is legendary. You know, our Two Street and the bars and the houses of ill repute that popped up there are famous.

We also have thousands of residents that moved to Fairbanks and have stuck it out and lived there for the last 50 years. So The impact is profound. We as a Fairbanks North Star Borough don't have public safety powers, so we rely on the state troopers to provide our public safety. But our EMT service is all borough-provided outside of the city of Fairbanks. And so, you know, if there are concerns, if there are drug or alcohol impacts, overdoses, injuries, oftentimes those are the EMTs that come from those fire service areas.

That would be a substantial impact on us. The city of Fairbanks has its own police force and fire service there. So if they're going downtown, one population or one law enforcement agency would be handling it. If they're outside, another law enforcement agency would be handling it. But those impacts would be real.

And as they look for places in community to live, you know, we don't want to see an increase of the homeless population. As Representative Tomaszewski noted, it's not as large and profound as in other places around the country or the state, but it is there and it's real. And as we're working— a little offside— as we're working to clean up a number of junkyards around our community, we're seeing a lot of those people who have not been able to find homes and live place to place, they are living in those junkyards, and those can certainly be a welcoming place for drug and alcohol abuse, mental health issues, unhoused populations. So How we fund housing in our community, how we ensure that those people can find a place to live when they come at an affordable rate will be a huge impact to us as a borough in the community because the city is constrained by land area and the borough is not. It's not the problem that we have for sure.

So we would be looking to try to ensure that we can help build housing adequately. When I had conversations with Glen Farn during the AGDC discussions, And in my office personally with them, they're not looking at building permanent housing for their workers. So we're not going to be seeing that from them. And we asked, like, is that a way that we could look at a payment in lieu of taxes, would be through building of decent permanent housing that those workers could live there, or people that come up looking for housing after the fact, once the pipeline's done being constructed, could live on, those sort of things. So those impacts will be real for us.

And as we try to create incentives to fund those, that would be something that we would be looking at as the impact. So that might be the biggest place that we as a borough would see. But the North Pole City has law enforcement powers, and so does the city of Fairbanks. So that might be where we see the law enforcement. But the EMT would be a big impact for us as well as the homeless population.

Representative, thank you. To follow up, follow up. Yeah. And so my, my thoughts on that is You know, the people that come to Fairbanks, I was one of them. You know, my father worked on the TAPS, and that's what brought us to Fairbanks, and that's why we stuck our roots down there.

And I think I turned out okay. But, you know, there's going to be a lot of folks that come up, and it's going to be a great opportunity for our borough. There's going to be more construction, more housing. We have room to grow. And I look forward to all those positive aspects that this pipeline is going to bring, not only in the construction industry, not in the, in the construction jobs of the project itself, but in the long-term project jobs that are going to help maintain and run this infrastructure for the state.

I think it's going to be a great thing for Fairbanks, and I'm really looking forward to getting this done. And we really do need to lay that pipe. So, Representative Thomas, if you see the chair, it's not a question, but I'll take the opportunity anyway. You know, that is a wonderful problem that we would have is the increase in population for our community there. I don't know when the last time you were at the bar in your district, the Howling Dog.

There's an old bumper sticker up on the ceiling. It says it's a beautiful view watching a Texan leaving the state, heading south with an okie under both arms. Let's turn that around and bring them here and find a way to make construction for the housing go hand in hand with the construction of the gas line. All right, thank you. Okay, further questions?

Representative Bynum. Thank you, Co-Chair Foster. Through the chair, thank you very much for being here. We hear a lot about community impacts, but when I looked at— when I look at the bill and amendments that we've had in the bill, and we talked about basically equalizing the cost for a spur line to Fairbanks and absorbing that as a system cost, Can you really quantify, um, the benefit that we're going to see for $8 to $12 gas or cheaper coming to Fairbanks compared to what I continue to hear about community impacts? So for example, if there was $0 for community impact for you and you were still getting, uh, $8 gas, what is the benefit or the positive impact to Fairbanks comparatively?

Like, if you had to weigh those two things, what would you say that the comparative impact would be? Uh, Representative Bynum, through the chair, if you're asking me to pick, uh, one or the other, um, you know, we've been waiting 60 years for a gas line. Um, we haven't been waiting for 60 years for gas lines' ancillary impacts, uh, to the communities. Um, so I think that choice would be easy. But, you know, as we look at what those decisions are, you can look back at the Municipal Gas Line Board, the MAG board rather, 12 years ago and the agreements that they came up with, an understanding of the full scope of what the impacts might cost to Alaskans along the rail belt was far more than what we're seeing in this legislation today.

So how those impacts are looked at going forward is still very important to us. You know, the Theoretical impact of lower gas is going to help increase our economic output, which would allow more people to be interested in building things. We have a very stringent tax cap for our local municipality. That tax cap is not driven by assessed value. It is driven by new construction and the price of— the rate of inflation is the biggest driver for specific revenue to the community.

So this gas line, whether we keep the current language in there, in state statute, of the 20 mils for taxation is not going to bring new revenue or much in the way of new construction to our community. It will— it's just 2 miles of line, whether that's, you know, whatever the price it is to build a line, only those 2 miles are going to increase our revenue for it. So ensuring that we have the ability as a local municipality to address whatever the impacts are, how Representative Tomaszewski was talking about them, is going to be very, very important. And our infrastructure is going to be constrained because we are a fairly steady population of a community. We're seeing more military come in in the next year.

We're expecting over 1,000 soldiers and airmen combined to come in, let alone how many family might come with them. So that, plus whoever might come in with a Texan and an Okie under both arms, is going to create some some constraints on our community. And so ensuring we have the flexibility through those additional funds for the impact funds is going to be essential for us in the long term. Thank you. Further questions?

Mayor Hopkins, thank you very much for being here today, and we appreciate it. Um, so with that, we'll move to the next borough here. Thank you very much, Coach Eric. Great to see you all again, and thank you for your work on this. Welcome back.

And so next up we do have Mayor Edna DeVries with the Matanuska-Susitna Borough. If you could please come up and put yourself on the record, we appreciate you being here today, and we'll listen to your presentation and probably have some questions. Well, thank you very much. When I sit here on a sunny day when all of you would like to be campaigning or out fishing or something. My memory goes back to when I formally sat in your seat and had to sit in that seat for 3 weeks while we had a special session in August.

So I have sympathy for you because I can easily identify with you. Anyway, my name is Edna DeVries. I am the mayor of the Mat-Su Borough. And we are here in broad, heavy support of this project. When we started the mayor's meetings that the governor had set up several months ago, we took the first step, I believe, in that mayor's meeting to say that we were proudly supporting this project.

And the Bollam Tax is the idea that our assembly has supported and is continuing to support, even though the pipeline is 22% in our borough because of its location and across the river from, say, Wasilla. So for those of you that have driven in Wasilla in the rush hour, don't be concerned about the impact from the people working on the pipeline because they're going to be across the river in their own little places to live. So that is mainly what I'm here for, is just to reiterate to you that we want to see this project go forward, and whatever we can do to help do that. Our assembly and our administration, as well as my office, stands behind that. And I don't have a spur line that I want.

I, you know, we have no special requests except just looking over the state and how I believe this state needs this project. Not just in the core area down where the pipeline runs, but all over the state. Because I think the state of Alaska, without being too philosophical, we need something to sort of get us off center. And, uh, and so that's my testimony. I welcome questions, but So here I am.

Yeah. Okay. Thank you. Representative Hannon. Thank you, Chair Foster.

Thank you for being here, Mayor DeVries. And since you don't have special call-out language, the questions I have for you as a mayor are what are the impacts you anticipate seeing in your borough? And although you referenced it won't impact Wasilla rush hour traffic because they'll be stuck in it, because they'll be all the way across the river.

Do you anticipate water and sewer expansion demands, etc.? Because, you know, the devil's in the details. I don't think anybody's debating a volumetric tax. Looks like where we're going, but making sure that our community impacts— because you're giving up property tax, don't necessarily want it to be on the state's dime. But what are the impacts?

So we make sure that we've thought about them ahead of time that you foresee? You're shaking your head no. You don't see any impact? No. Well, the borough doesn't have water and sewer, but the cities do.

So any impact would be for people that would want to start living in the Mat-Su Borough because the man camps are not going to be connected to any water and sewer projects that we have. And So does that answer your question, ma'am? Thank you, Chair Foster. Well, Mr.— Mayor DeVries, I hope that we don't look on back and say, of course there were impacts, because the mayor said there are no impacts and we'll anticipate there will be no impacts in the Matsuburo. Those man camps will be completely contained and everything will be rosy and the traffic will improve in Wasilla.

I'll throw that in on my own. Okay, thank you. Well, as all of you know, Matsuburo is the fastest growing area that has been for several years in the state, and so we are used to dealing with housing shortages and things like that. But as I said, we don't— this borough doesn't handle water and sewer. Most of our people are individual wells and septics, systems except for City of Palmer and the city of— so yeah.

Okay, further questions? Seeing none, Mayor DeVries, appreciate you being here. Oh, I do. Oh, we've got a question. Yes, Representative Moore.

Sorry about that, I tried to get in the queue but I'm having a hard time doing that. But I just— not a question, but just wanted to Thank Mayor DeVries for being here today, for her engagement and her wisdom and knowledge. She's been doing this for a very, very long time, longer than anybody—. Not longer than any of us sitting there on the finance team. So very happy with her local knowledge, her local governance, and thank you for being there to give your testimony today.

I appreciate you. Thank you. Great. Thanks, Representative Moore. Okay, thank you, Mayor DeVries.

Okay. Looks like we had a crisscross in our lines of communication regarding scheduling with Mayor Peter Machicki from the Kenai Peninsula Borough, and so we're going to have him in tomorrow. So what we'll do is we'll jump right into where we left off yesterday with AGDC. And so if we could have Mr. Frank Richards as well as, I believe, Matt Kissinger, if you could come up to the table and put yourself on the record. And it looks like we left off— we completed slide 24, and so we'll pick up where we left off there.

Thank you, Chair Foster. For the record, Frank Richards, president of the Alaska Gas Line Development Corporation, and happy to be back in front of you today. It was really nice to hear from the mayors from Fairbanks and from Mat-Su, Mayor Hopkins and Mayor DeFreeze. As they described, we did have many conversations with them looking at the community impacts as well as the alternatives to the property tax. And so they were both actively engaged and it was a very good and robust conversation.

So appreciate them coming today. To the committee. Where we left off yesterday was really around, um, how AGDC has been working with Glenfarm. We went through the developer scorecard, and then I wanted to move on to how AGDC is actively engaged in supporting Glenfarm in the development of the Alaska LNG Project. And that is through our active participation, as I said, in the development consultation process, where we are engage with them on a weekly, if not monthly basis, where we are providing some of our own expertise from having long sit in the developer's position in terms of project management, as well as the design, as well as the permitting efforts for this project, including, you know, all of the efforts that we took within the state for the right-of-way, but also in terms of all of the environmental reviews that we undertook through the FERC process.

So we have, uh, good experience. We also, at the direction of the legislature, pushed forward what was then called the Alaska Standalone Pipeline Project, where we actually completed a feed. So we've been through this process before. We've brought that knowledge and that information to the Alaska LNG Project and are continuing to help then with Glenfarm as they go through and have gone through the feed for the pipeline. And now we're initiating the feed for the liquefaction and gas treatment plant.

In addition, we also provide commercial expertise, and I'll ask Matt to chime in. This is Matt Kissinger, commercial director for AGDC, for the record. We also provide commercial expertise in ways— so we, we carried this project for a long time, built a lot of relationships up, especially within the Asian LNG buyers, so we've been able to bridge that and actually work closely with 8 Star or with Glenfarm within the 8 Star structure to continue advancing those. Same with Alaskan stakeholders. For example, we had a roundtable up in Fairbanks where we had the utility as well as some of the large-scale mines to talk about the future of energy in the interior.

And a lot of that was coordinated by us, but of course Glenfarm bringing the expertise necessary for the project. Again, interfacing with Alaska Native corporations and ensuring that they are, you know, that the opportunities within this project are clear for them. And then aligning key state departments and corporations. A good example of that is royalty in value versus royalty in kind discussions with the Department of Natural Resources and bringing them along the line, as well as much of the work of the Department of Revenue where we work quite closely with the economics team there. There's a bullet point here saying adding new legislative overstrike restricting confidentiality will make AGDC's ability to support Alaska LNG development more difficult.

And really what that's about is, is there's some information flow that's legislated by these agreements that we have with Glenfarm, but then there's a greater amount of information flow that is built just on the trust that we have as the two owners of 8-star. Uh, there is fear that if our confidentiality ability is restricted, that flow of information that is not legislated by the agreements but is just built on trust would be eroded, and it would, uh, provide us with less of a window into the inner workings, and I think really limit our ability to help, uh, Glenfarm in advancing the project.

Just so folks— just to remind folks, we're going to take up questions at the next break, which was slide—. After slide 30, I believe, is where we had mentioned yesterday. A little bit of static. I'm not sure where that might be coming from. Okay.

Oh.

It's like the old days when we used to have the antenna on the TV trying to get the best reception. I'm not sure if it's working or if it's just coincidental. There you go.

Some foil. Take briefkies.

OK, House Finance back on record at 2:21 PM. Mr. Kissinger. OK. Thank you. We've talked about this optional equity participation, and in the next several slides, hopefully Hopefully this will all become clearer.

But in addition to our developer, you know, ownership of 25% of 8Star Alaska, underneath that, as new investors come into the subsidiaries and equity is issued from those subsidiaries in exchange for capital, we will have the right to participate in that issuance of equity from a minimum of 5% up to 25%. And the minimum 5% was really just put in there to avoid having a de minimis stake in there, because, of course, it does open the door for a lot of information. And I suspect that that same limit would be on other investors. This opportunity is going to come in a lot of different tranches. So we've heard a lot of people say, oh, there's a $4 billion decision ahead of us.

That's not really true. There's probably $4 billion or so worth of decisions ahead of us, but in fact, it will come in the form of, you know, the Phase 1 gas pipeline first, Phase 1 gas treatment at the same time as that, but those would be two separate equity issuances. And then as you build out Phase 2, the further compression within the pipeline, so you would have another one on the pipeline, building out the GTP, so another one on the GTP, and obviously one on the the LNG facility. So each of these will be a discrete opportunity, independent of each other. And there's no obligation if you participate in one to participate in all.

And, and just because you don't participate in the first one, it doesn't mean you lose your ability to participate in later ones further down the road. Again, we can't stress this enough, this is a contractual option, but it's not an obligation. This is very different than the model under the producers back when the state was a 25% payer. The state would have been subject to cash calls going forward, would have been subject to default provisions should they not pay into those cash calls. We don't have any of that structured into this.

Each time instead of that, it is an option provided to the state. Move on to the next slide. If I may, Mr. Chair.

Frank Richards for the record again.

The option that we're talking about here is— will be provided to the state of Alaska in whole. And what I mean by that is not only to the state legislature, but also to Alaskan corporations and hopefully Alaskans themselves. So this was an option that we negotiated with Glenfarm to allow then the opportunity for the state and its citizens and its corporations, should they want to invest in the project, But the project will proceed without Alaskans' investment if they don't want to. So that's, that's a key consideration. It's not a requirement.

It's not an obligation. It's an option.

Matt Kissinger, for the record. The way these rights will be exercised is through a preemption. And this is common in international upstream oil and gas structures where a state led oil company is able to avoid the upfront developer risk period like we are right now where we're being carried through the rest of this development period. And at a decision of commerciality, they're able to back into an equity position. And we structured it somewhat based on that and provided ourselves with this 6-month preemption.

The way that would work is all the other investors would be lined up. The project would achieve an FID. And be ready to move forward, and in fact, would be getting spending money and moving forward. From that point of that final investment decision, the 180-day trigger would start, or the 6-month trigger would start, and we would have the, you know, the opportunity to back into on similar terms or same terms as the other investors into that investment. Now, I will say up front that we are also exploring opportunities for this to be done on different terms where you could have a preferential capital issued for this state option.

This is nothing that we've agreed to yet, but I think it's worth highlighting that, you know, this is something that we're continuing to explore, and that would be structured in a way to avoid any cost overrun risk. That would be the reason for doing it that way.

So I'd like to go through the next 3 slides. And then we'll go back and go back through these 3 slides with questions. And then if we need to go through them again, more than happy to, as many times as we want to. You'll remember from yesterday we talked about this structure as it sat in 2025 when Glenfarm came in. They took 75% of 8 Star Alaska.

We retained 25%, and 8 Star Alaska itself owns these 3 subsidiaries: 8 Star Arctic Carbon Capture or Gas Treatment Plant, 8 Star Pipeline, and 8 Star LNG. Now, as we go forward, let's just focus on the pipeline, because that's going to be the first decision that we make, is Phase 1 pipeline. We are going to first get project debt lined up, project finance. So before you go out even to the equity market, you find out how much of this you can fund by debt. We've always assumed somewhere between 70 and 80%.

I think mostly in our modeling we show 70%. But there's always a potential to go a bit higher than that with pipelines.

As we raise— first, we will get that, call it 70% in place. Now we have 30% that we still need to raise for equity. And this will be where we issue shares of 8 Star Pipeline to others. They'll come into 8 Star Pipeline and 8 Star Alaska. Will be diluted in that process.

And we've been listening to Senate Finance and they are beginning to talk about this and I look forward to addressing it with them. To be clear, in a worst-case scenario, you could be fully diluted. 8 Star Alaska could be fully diluted. Go back to my Shark Tank example yesterday. You know, you go in and they say, "I want 50% of your company for $2 million." Well, this can happen and maybe you have a bit remaining, but then you have some cost runs, so you need to issue more.

And the worst-case scenario could happen. The important thing to know about that is we are 100% aligned with Glenfarm. So Glenfarm, as the developer really moving this forward, as the manager moving this forward, they also get all of their true economics out of that. Now, they could also participate the same as we could as direct equity investors, but, you know, your real reward for all of the development exposure that you're taking right now, all that risk that we're taken right now is keeping some of those developer economics. So yes, in the worst-case scenario, that could be fully diluted, and that's why we've never shown any numbers around this.

This is not included in the DOR modeling. This is all pure upside, that 8-star Alaska developer economics that would flow through. But in extreme case, you know, this could be generating over $100 million a year or more for additional economics.

On the next slide. So I've just sort of shown this play out in this slide where, you know, you put your debt in place, but now you also need to issue the equity. And let's say, for example, to get the additional equity funding that you need so that you have all the capital required, you have to divest of 65%. That would mean that 8 Star Alaska keeps 35%. But the interesting thing about it is, of course, AGDC will have the right to back, back into that other investor bucket.

And that's what I show on this slide is if we were to exercise our full 25% ownership, it would back those other investors down to 48.75%. We would be at 16.25%. That's 25% of 65%. To follow along.

In addition, we'd have our 25% of 35%, which is 8.75. 8.75 Plus 16.25 equals 25%. So we always have, even as we get diluted, as 8 Star Alaska, I should say, even as 8 Star Alaska gets further and further diluted, we can always maintain our 25% by paying and purchasing it, which is where we would have already been if we were under the earlier models of this project.

So with that, I will offer to go back to— go back a couple of slides and we can start the questions there if you would like. Okay. Representative Galvin. Thank you. And we— I am trying to play this out from slide 29.

The way I'm reading it is that if the Phase 1 project costs $15.5 billion, and that is different than what I heard last week from DOR, which had it at $16.6, so I just want to make sure we're aware of that too. If you want to explain that first, then I'll continue with the rest of my questioning. Through the Chair, Representative Galvin, again, the cost estimate we put in here was really A rounded number. It's not indicative of the actual cost of the project. It is for illustration.

Okay, that's fine. No worries at all. So, okay, so let's say we're at that 15/5. Equity owners as a whole will have to contribute, as a whole, $4.75 billion per this example. And if Alaska chooses to buy 25% of the 65%, right?

Then we're at 16.25% direct ownership. Is that tracking? Am I still on track there? That's correct. 16.25 Direct ownership.

Okay. That's direct ownership. And does that mean that due to the carried interest in Instar Alaska that the state will only have to come up with $771 million or is it— and that's 16.25% of the $4.75 billion to stay at the 25% equity, or is it— is the 8-star Alaska indirect ownership not carried? And I think that's what you were saying, meaning that the total state contribution then would be— would need to be $1.18 billion if my math is correct. Yep.

Yes, Chair Kissinger. Representative Gowan, through the chair, that you got that correct. So it wouldn't be 16.25% or else the math wouldn't add up for the full amount of capital that's being required. It's 25% of the capital that's being required would get you 16.25% of the direct ownership of Astar Pipeline Alaska. So the Astar indirect— sorry, the Alaska state indirect ownership does not get carried— the 8 Star indirect doesn't get carried through, right?

You are in fact being carried because you're not contributing any capital through 8 Star Alaska. The capital is all being contributed through the direct investors, the other investors as well as us as one of the other investors, so to speak. But to be clear, to stay at the 25% level, then that would need to be the $1.18 billion. Yeah? That's correct.

Okay. Thank you. Representative Hannon. Thank you, Chair Foster.

In the example that Representative Galvin just walked through with you, who gets to make the decision as to whether you're expanding equity investment interest? Is that a board of directors decision level?

Representative Hannan, through the chair, let me go back and look at the agreements and consult to ensure that we can provide that under the terms of the confidentiality. But it would ultimately be an 8 Star Alaska decision. I'd need to look into how that decision gets made again. And then follow up. Follow up.

And then for taking an equity— expanding the equity investment there, Who has— would 8 Star of Alaska have access to its own capital to invest, or does it come back to the legislature for a legislative appropriation to invest? Representative Hannan, through the chair. So 8 Star Alaska, again, won't be required capital. 8 Star Alaska already owns 100% of it and will be diluting its ownership in in exchange for the capital being raised. And that's the dilution.

I don't want to hide from that word. It is dilution. Let me— Chair Foster, so let me go to the other side of it where if we decided to exercise more of our equity position where direct ownership and you were saying that individual Alaskan businesses could invest up to the 25% share. So if we are expanding our investment interest, we are not going to at any point have to give additional capital? Representative Hannan, through the Chair, so for direct ownership, you do have to pay.

You have to pay the same amount as the other investors do. So that's the decision I want to know. Who makes it and who has the authorization to the funds to buy that expanded equity position? The—. Representative Hannan, through the chair, the way that decision would work is, is at FID, 8 Star Alaska would notify AGDC of its right, its preferential right.

From that point forward, it just becomes an AGDC decision. Now obviously, AGDC funding would require us to come to the legislature for that to be provided. Alternatively, there is bonding authority, so So you could structure revenue bonds to fund some of that. Um, questionable how well that would work because there is still completion risk involved, but that is one avenue. And then further, under our, um, the enabling legislation for AGDC under the uncodified law, as well as under the original Alaska Natural Gas Pipeline Act of 2004 at the federal level, uh, there is a requirement for us to offer to Alaskans kind of in general a right to invest in this project.

And so we are looking at a way to provide that. We've looked at something similar to Pick, Click and Give, only more like Pick, Click and Invest. But however we structure it, it would be a way for individual Alaskans to invest in part of that 25% pool. Okay. Chair Foster.

Through the Chair, Mr. Richards again. Mr. Richards. Representative Hanna, to your question, today and yesterday, when that preemptive rights are offered to AGDC, we will then notify the legislature of this opportunity. And then it will be up to the legislature to make that decision if it chooses to invest.

Follow-up? Representative Hennepin. So you're using some language that doesn't have enough specificity in legislative direction. So I apologize for focusing on that. But so if AGDC's board— and I, I guess I want to know, is it just by a majority, or does it need to be unanimous, or can, you know, says we want to invest, then you come and make a request to the legislature for a billion few hundred million, whatever the equity expansion that you want.

But let's, you know, a simple majority of the legislature through our regular appropriation process. And then you've mentioned the bonding, which when I've tried to figure it out, it doesn't seem as clear to me what bonding authority AGDC has or whether that has to be affirmed by the legislature.

The Alaska Railroad has had some similar things where their board has to ask for a bond but then come to us for basically sanctioning that revenue bond. And I'm trying to understand that dance because we haven't had the dance this far in prior renditions of the project. Mr. Richards. Through the Chair, Representative Hannon. I have two points to make.

Number one, when the board authorized AGDC to enter into these agreements with Glenfarm, it was around this— the ability for AGDC to receive these preemptive rights for investments into the various subprojects. And that was the board direction, that we wanted the opportunity for Alaskans to be afforded this.

Now, when Glenfarm takes FID and then provides the preemptive rights to AGDC, that's the trigger point for us to notify the legislature and other opportunities for Alaskans to be able to offer this up. That is, again, the start of the 6 months that we currently have under agreements to be able to make that decision. For up to 25%. The existing— the legislative bonding approvals that were granted to AGDC in— under Alaska Statute 3125 is, as Matt described, as revenue bonds. So AGDC does not have the ability to put forward bonds that obligates the State of Alaska for bond payments.

They withheld that at the time with the express interest that if the state wanted to provide bonding authority, it would at a future date. So it's— the opportunity would only be for revenue bonds that AGDC could float currently, but without any of the full faith and credit of the state of Alaska backing them, only the revenues coming in off of the project.

I'll look for some additional. Through the chair, Representative Haynes, I'll be happy to provide you the citation. I'm not sure what are you going to have. Representative Moore, you might want to put yourself on mute. Thank you.

Next up we've got Representative Schrag, then Bynum. Representative Schrag? Pass for now. Okay, Representative Bynum. Thank you.

Thank you.

Representative Moore, are you there? I'll take a brief, please. Yeah, we'll take a brief, please.

Okay, House Finance back on record at 2:41 PM. Representative Bynum. Thank you, Kucher. I'm so sorry, we just want to recognize Representative Stepp is here. I think your flight was delayed.

Is that okay? Representative Bynum. Thank you, Co-Chair Foster. Through the Chair, we've talked a little bit about this equity portion and being able to be an equity holder in the project. The example you gave is for the pipeline, but this would apply to the other— the other three— other two components of this.

You briefly mentioned in your slide deck the difference between debt and equity. But we haven't really talked about who will be carrying the debt portion of that. Now, I'm assuming that if somebody is coming in and they're going to collect debt for themselves and they're going to be offering this debt for an equity stake, that's going to be on them to carry that debt. And however they get that, that's going to be whatever their mechanisms are. My assumption is, is it's not associated with 8 Star.

Or the debt carried against the project per se is debt. So can you talk a little bit about how debt will be brought into the project and who will actually carry that? And if it's outside of ASTAR, who that might be? Representative Bynum, through the chair, that gets back to some of what I was talking about yesterday with respect to project finance. So what you just described would be very standard what we call like sponsor balance sheet finance.

This is how the producers were going to move the project forward. The problem with that kind of finance is it's much more expensive. Generally, you're getting a sort of blended average of what a company's returns need to be along with that company's debts, but ultimately you get to a higher sort of average cost of the capital. And that was what Wood Mackenzie had pointed out in the 2015 study when they said that the economics were poor and you should really pursue project-level finance and a tolling structure. Under project finance, the project itself gets credit, you know, credit support, I should say, through the contracts for LNG sales on the downstream side or within the state of Alaska through its gas sales to Alaskan customers.

And then on the upstream side, ensuring that you have the upstream gas supply already under secure terms. So long-term, 20-year to 30-year agreements, both upstream and downstream. This is really what makes it so much different than oil and why when we start getting into these ideas of like, well, what if the gas price goes up, the spot price for gas goes doubles or triples and we're gonna lose out on the money. Well, the reality is you've already lost out on that because when you put the project together, you're selling that gas for 20 years. And some of it's indexed to different things, like indexed to crude oil is a common one.

They call that the Brent index. It's usually like a— what's called a slope of Brent or a percent of Brent, 12% or something. But it doesn't fluctuate as much as spot markets do. On the oil side, You have this more integrated structure where the owners are selling their oil downstream and kind of netting it back. This is not a netback structure.

This is a, a sale of the gas into the project, a sale of gas and LNG outside of the project. And all that provides a credit rating agency, for example, the ability to say, okay, this is a creditworthy entity that you've created. Created. That entity, so 8 Star Pipeline LLC in the case of the pipeline funding, that entity does go out and places that debt.

That will cover, in this case, we had $15.5 billion, which I did actually get from DOR numbers. So it was for the full pipeline that I grabbed, inflated through to current numbers. So I will And we can dig into why there's a difference there. But in this case, you would first go out and get 70% of the debt for that. So your $15.5 would immediately be funded— $10.85 billion by the debt held by the project.

8 Star Alaska still owning 100% of 8 Star Pipeline, but not having enough money to build it yet, because you only have $10 billion or almost $11 billion of the $15.5. You need to raise the rest of it, and the rest of it is where you go out to the equity markets, and that's where you start your Shark Tank conversation. And just for the record, that was Matt Kissinger. Follow-up, Representative Bynum. Thank you, Co-Chair Foster.

Thank you for that. I appreciate it. Kind of clarifies, like, how we're dealing with debt. And then obviously debt is just one component where we have carrying cost to hold that debt and pay it back over time. The other component is that we've been talking about is the property tax, hence why we're talking about this bill to begin with.

Can you just briefly link where we are at in the presentation with the importance of having certainty in the carrying cost of not just debt but also the liability of property tax? And the impact of the project.

Representative Bynum, through the chair, if I understand your question correctly, and please rephrase if I get this wrong, but going back to that whole project finance, this whole structure, everything relying on these 20-year agreements, 20 to 30-year agreements, 20-year look-aheads, this is really where it comes down to Everything that we can needs to be tight, needs to be fiscally certain to the extent that we can make it so, and also needs to be helping us become more and more competitive so that we can get those other investors in and ultimately not be fully diluted in doing so, to be honest. But it is the only way to bring these other investors in is to first demonstrate that you can make an economic project. And making an economic project is really about moving us further down that chart of competitiveness that we showed yesterday where we are in the middle of the pack and we need to move more towards the front of the pack. If that answered your question. Yes.

Thank you. Okay. Representative Bynum. Thank you, Co-Chair Foster. That was it for me.

Sorry. Representative Stepp and then Representative Gellman. Representative Stepp. I think Co-Chair Foster said the Chair too. Wonderful AGDC folks.

Can you elaborate a little bit more on the dilution aspect? The co-chair of Senate Finance kind of brought this up yesterday, I want to say, and had concerns about the equity stakeholders effectively diluting the value of the state option in the event we were to purchase in. Through the chair. Mr. Kissinger. Representative Staff, through the chair.

So our direct investment option would be part of the diluters, actually. And so we always have the ability to maintain 25% even as we— as 8Star Alaska's ownership gets diluted out. The dilution, the only dilution that we're talking about here is 8Star Alaska owns all of 8Star Pipeline. But in order to raise the funds to build 8Star Pipeline, they're going to have to issue out the equity to other investors in order to bring in the cash necessary to build the thing. That is called dilution, and that is exactly how it was designed.

And so this is not— this should not be an aha moment. This is truly how it works. It's just like in Shark Tank when they go in and they make their trade, they're getting diluted. They walk in owning 100% of their company, they walk out owning 70%, 60%. It's the same exact model here, but we're always able to also be be part of the ones diluting, the diluters, because we always— every time equity is raised, we have the option to participate in up to 25% of— or every time equity is issued for capital to be raised, we have the opportunity to invest in up to 25% of that.

All right. Follow-up? I'd also like to recognize that we have with us Representative Johnson, I think I saw walk in. Thanks for being here. Representative Stamp.

Yeah, thank you, Chair Foster, through the Chair. Obviously, okay, In the example of 8 Star Pipeline, you guys have no money other than what we give you. So in order for you to raise the money to build 8 Star Pipeline, you have to sell to an investor. So my question to you is, if I have no money and I say I want to own 25% of something, who is going to give me 100% of the capital on a project for 70% or 75% of the ownership? Through the chair.

Mr. Kissinger. Representative Stapp, through the chair. The model would be that the other investors, such as your institutional investors, would come in because there's less risk that they're coming in under. So during the development stage, you're doing a massive amount of de-risking of the project to the point when you reach an FID, it's a very different risk profile that they're buying into had you not gone through all that development work, gotten the permits in place, lined up the buyers, lined up the sellers of the gas. And so assumedly, you would be able to bring them in funding 100% of it, but not issuing out the full 100% of the equity.

There is the risk, especially through cost overruns, that that could happen, and we want to be upfront about that. And that's why we don't, again, show any of those developer economics in any of the numbers that we show. We consider it pure upside. My fault. Representative Stout.

Yeah, thank you, Chair Foster. I have too watched a few episodes of Shark Tank, and I'm pretty sure if you told Mark Cuban you'd pay 100% of a project and only get 75% of the value, he might have a different answer. But I guess I don't see how you would retain any level of your equity interest in these sub-LLCs without ponying up capital for investment because it's 100% at-risk capital, isn't it? Like, what is— how do you de-risk an ownership equity stake of something that you put no equity in? Through the chair.

Representative Stapp, through the chair. So at the point of FID is where you would shift from binary risk to non-binary risk. So ahead of an FID, you have binary risk, meaning the thing could go wrong and you lose everything that you've put in. After an FID, things can go wrong. You can have cost overrun risks.

Et cetera, but you don't lose everything. You generally can— your position is slightly worse. You have lower returns, things like this. But it's very different than the binary risk ahead of an FID. And that's the reason why in bringing others in at FID, you're offering this different risk profile, and so they are willing to fund, you know, significant amounts in exchange for smaller amounts of equity.

Follow-up? Representative Stapp. Yeah, thank you, Chair Foster, through the Chair. How does that work in the event that the project suffers cost overruns on the capital portion after the FID phase? Do you absorb more equity or do you just go back to the investors and raise more capital through the Chair?

Representative Stapp, through the Chair. It's a combination of those two. Obviously those initial investors are first going to be looking to you to be further diluted, but there comes a certain point where everyone is willing to either be to be further diluted by issuing more shares to other investors or willing to add additional funds to the project to keep the project going. But it becomes decisions like this, and it's quite normal as they develop projects. Last one.

Sam Stout. Yeah, thank you, Chair Foster. So wouldn't the expectation then that you guys be the ones to dilute your own ownership because you're not putting up the money and everyone else is putting up the money, right? So I'm just thinking from my perspective. Perspective, if I put a billion dollars into this gas line, I own 30%, and I didn't raise more capital because I have cost overruns, I would look at you guys and say, hey, you need to get more of your shares out, uh, to cover this cost overrun before I would attempt to dilute my own, I would imagine, because I, I put good money in for mine.

Um, so in the event that you have a cost overrun, like, what level of ownership in the, um, sub-LLC pipeline would you guys expect to have through the chair? Representative Stapp, through the chair. Now remember, 8 Star Alaska will have contributed all the agreements necessary to pull this thing together ahead of that FID. And those aren't— that's not worth nothing. That's worth quite a bit to these investors.

I do agree with you that their starting point is going to be exactly as you've described, but that will be a negotiation. Okay. Thanks. Okay. I've got Representative Galvin.

Galvin. Evan Bynum, Representative Galvin.

Thank you. And here's where I'm going to ask if you can pull back the curtain a little bit, if you could, what you are able to share. Do we have some lead equity investors already engaged? And if so, how much more funds are needed, roughly, if you could share some pieces of that? I think you alluded to at one point Mr. Kissinger, you said something about pipe— one of the pipeline companies typically does.

That's part of the way they work as they are— they become an investor. But I just wanted to give you an opportunity to share what you can, please. Representative Galvin, through the chair, Matt Kissinger for the record. So we can't open the curtain too far on that. There are a lot of conversations going on focused first on debt.

Because, as I said, the first thing you do is you line up your project debt. So it's a little bit counterintuitive to some. You don't line up the equity first, you line up the debt. But the conversations are also being had with the potential investors, and it's being led and advised through a very well-known infrastructure funding group. Follow-up?

Follow-up? Okay. Well, didn't get in there at all, but Thanks for that. I assume that you are working primarily on Phase 1, that you are calling it $15.5 million. On May 20th was the date I was given $16.6 million by Matt— by Mr. Stickle.

So we can maybe check that later and figure that number out. But these matter because it is a billion-dollar difference.

So, but that is what we are talking about, is the first phase only, or are you looking beyond? Because I am sure you want to make— you understand, or there is some sort of an understanding that without phase 2, phase 1 becomes very expensive for ratepayers. Representative Galvin, through the chair. So the—. Right now we have the cost, the Class 2 cost estimate on the pipeline.

And sorry, I probably shouldn't have put the $15.5 billion in because it probably confuses things. I pulled that out of Revenue's numbers, but it was really the full pipeline cost part of their $46 billion that they've been quoting. That's where I pulled that from. So it was really, that was just for an example, and I apologize for that. With respect to Phase 2, Phase 2 The, um, the ability to quickly move into Phase 2 obviously is part of attracting the investors for Phase 1.

Very similar to LNG Canada, as I mentioned, they did a Phase 1, Phase 2, and our— my understanding from conversations with Shell on it were that they did Phase 1 intentionally as skinny as they could economically, um, knowing that that would help Phase 2 become a very easy decision down the road. With respect to Phase 2, we still need to get to the class 2 cost estimates. So we still need to get through FEED. That's the— that's a lot of work is going into entering FEED on the LNG and GTP right now. And we need to get the contracts in place to sell the gas.

Now, you don't need to be fully informed of your costs in order to sell gas because you're actually selling LNG at a global market price. They don't really care what your costs are other than they'd like to know them because they'd like to use them against you to bring down the price a bit. And we need certain things like what's called a floor or some kind of a debt underpinning pure cash flow. And that's probably getting too far into the weeds on this, but suffice to say, we need to get all those agreements further along before you fully engage the debt and then equity market. Thank you.

Okay, I've got Representative Mr. Bynum, and then staff. Thank you, Co-Chair Foster, through the Chair. I think, you know, one of the things that I've heard, and it's not really a question, I guess a comment, is that it's not— when we talk about equity being given, that we dilute, that's 8Star Alaska that's being diluted, and that's both owners or shareholders of this. That's Glenfarn and AGE. DC being diluted.

So they're taking dilution just as much as we are, or even more so because they have 75% ownership stake on this. But I guess one of the, one of the things I'm just not 100% sure on is about timing of our equity buy-in for each one of these phases. Right now we've talked a lot about Phase 1, we're talking about the pipeline portion, uh, but we will have a Phase 2, in this project. I would assume that that would be the case because it makes the whole thing actually work long-term. Will that 6-month window be for each element of this, or will we have to make a decision right up front when that trigger is being pulled for the first initial 6-month evaluation period?

You get my question. It's basically like, do we have an opportunity for each one of these LLCs to make a decision on whether or not we are going to be putting in 5%, 0, 5%, or 25, up to 25%. Ultimately, this investment of between $1 and $4 billion across the spectrum based on the information you are providing here. Yes. Representative Bynum, through the Chair, it is for every time there is equity raised.

It is the same process. So you will have an investment decision from the other investors. That will start a 180-day clock. It will be the same on Phase 2. Phase 2 will be both the GTP— sorry, all 3, the GTP, the remaining pipeline components, because remember that Phase 1 only builds the pipeline to South Central but not across Cook Inlet, and also doesn't include all the compression.

So there's 8 compressor stations that get built with Phase 2 on the pipeline, and then the LNG facility. Yep. Thank you. Okay, Rep. Sam Stout. Yeah, thank you, Chair Foster.

Through the Chair, so does that mean that we could have an equity option buy-in for the different pieces of the project if we just wanted to have an ownership interest in the gas treatment facility or the marine terminal? Through the Chair. Representative Stepp, through the Chair, that's exactly right. So each one of these is its discrete decision. They're not hinged on each other.

Electing not to participate in one doesn't preclude you from participating in the future ones. Follow-up. Follow-up. Yeah, thank you, Chair Foster, through the Chair. So if I were to— if the state were to take— so a lot of times, like, end users have equity stake.

That's what LNG Canada did because you get access to all the books and stuff. So if we were to opt into the gas treatment facility, wouldn't we have access to all the details of the producer gas sales agreements for the project, through the Chair? Representative Stapp, through the Chair, I would anticipate that to be the case if if one was to invest into even the GTP. Now, that is one of the reasons why there's the 5% lower end limit, to be honest, is for that exact purpose, to ensure that whatever stake any investors come in with, it's a meaningful enough stake to warrant that. Paul.

Paul, you want? I—. I'm—. Do the producers know that if we were to have an ownership interest, they'd have to give us everything through the chair? Mr. Kissinger, I'm sure they probably do.

I mean, tongue in cheek. So yeah, Representative Stapp, through the chair, I don't know if that really needs to be addressed. I would anticipate so, but I wouldn't— you know, we've never talked about that. So thanks. Representative Bynum.

Thank you, Co-Chair Foster. Through the chair, Representative Stapp kind of was hitting on what I was going to Was going to be one of my follow-ons, but I was waiting on it. And then that is, we've been hearing a lot about wanting to see the information. And the conversation that was being had is, well, when we are an investor and we're actually putting up our own money to be into the project, then that's the time to be able to see that. My assumption is, is that we will— when I say we, I mean the state and our interest— will be able to see the information that any investor is going to be able to see to make that decision.

Can you clarify a little bit more clearly when I say we as the state, who actually will have access to that? I mean, we will have to be making a decision to appropriate billions of dollars potentially to be an owner into this for the benefit of Alaskans. So who ultimately will have access to that information? Representative Bynum, through the chair, I mean, that That is a really good question, to be honest, because AGDC would have the rights to that information. But if we're going to be coming to the legislature for an appropriation, quite obviously that information would need to be shared with the legislature.

And so that will be on us to ensure that we maintain the rights to do that. I would say that, um, your risk around sharing this information changes quite a bit once you have all your contracts in place. Right now, this information is quite sensitive because other projects would love to know what your cost basis is and, and figure out what your limitations are when you're going out to the market so that they can undercut those limitations. And this is a competitive environment. It's a competitive environment even within Alaska, where we have multiple sellers of gas, even multiple sellers of gas out of single reservoirs, each with its own pricing, etc.

And we definitely need to keep those terms highly confidential at this point in time. In a small place like Alaska, it's quite easy for those to get out. Thank you. Representative Hannan. Thank you, Chair Foster.

I'm going to continue down this thread or go back to where I tried to ask it earlier. So if that equity interest ownership was bought by the Alaska Corporation's business and individual Alaskans who people have been given the opportunity to invest, that minimum 5% investment is held collectively for that group. And I guess my question is, what if we only get to 4.9% or 4.8%? Or is— who manages that collective investment opportunity that's to be shared with Alaskan businesses and individuals? Yup.

Representative Hannon, through the chair, what we will do is we will create a single investment vehicle that will be a subsidiary of AGDC. Okay. And all these collective investors would be owners of shares of that subsidiary. That subsidiary then would be an owner of 8 Star Pipeline Alaska or a beneficial owner of 8 Star Alaska. By beneficial owner, I mean AGDC holds the equity, but the revenues are routed to the beneficial owner and then distributed from there.

Okay, and just one follow-up, because you described, you know, a click, pick, invest option. So we could have very small-time investors, but we could also say the legislature decided not to take its own 5%, but let's opt in on that and take our equity position shared with Alaskans individually and get to our 5% or maybe we'll get to 25% that way as a shared collective. Is that a possibility also? Representative Hannon, through the Chair, I think that's a possibility in some ways up to the legislature. The legislature could say we want to take 25% but are willing to be backed out by individual Alaskans.

And so you're more like backstopping it that way for the individual Alaskans. So there's different ways to do this that I think the flexibility is still there. I didn't— I failed to answer your earlier question. If we don't get to the 5%, then that's the limit. We have to reach a 5%.

And so if we don't— if we didn't get to that 5%, it would be sorry to all those investors, but here's your money back. Okay. Thank you. Okay. I think we've got a few more slides.

Just one more. Frank, you can close it out.

Sorry, we got a question. Representative Bynum. Thank you. Through the chair, really quick, we've been talking about this 5 to 25% option. This is the option that happens after investors are already in.

So we're basically— we're taking their space. I'm not saying this is going to happen, but just out of clarity or for clarity purposes, if we decided to say we were going to be one of the investors We're not restricted to this 25— 5 to 25%, are we? That's only the option to say that we're coming in after we have certainty that it's being funded to be able to take that. Representative Bynum, through the chair, you're absolutely right. There's nothing to stop us from approaching, you know, and offering to be an investor in the initial round outside of our 25%.

Right. Okay. Thank you. Mr. Richards? Through the chair, Representative Watson.

Frank Richards for the record. I would mention though, Representative Bynum, that again, when that equity offering is out by the developer, the timeframe to be able to make that decision would be rather condensed. So that would be a lot of information to be assembled and shared with the legislature and a decision made in a very short period of time. It's not that it couldn't be done. You guys can work as fast as you want.

Quick follow-up. Representative Bynum. Yes, thank you. I'm not saying that that's a real— that that's a reality that that will happen. I'm only pointing out the fact that this 5 to 25% set-aside is there because we get to come in after the fact.

Correct. That we could be treated just like any other investor and have a right to 100% of all of this if we really wanted to. Now, can the legislature move that quickly and would we make that kind of investment I'm not saying that we would, nor was I suggesting that we would, but I just wanted to clarify that reason for the 5 to 25. Thank you. Okay.

Representative Josephson. And in a similar vein, as to the 5 to 25%, if the state were, as sovereign, were to look at this through a self-interested lens and wish to occupy the entire, say, 25% of an equity share of one of the components, then Native corporations and boroughs would be— they simply would not be in the position to take that first 25%. Would they be eligible for a 26th percent or sort of make their own way as to an equity owner? Representative Josephson, through the Chair, there is nothing stopping them from entering into equity discussions with the lead party, which would be GlenFarn in this case, on their own volition. There's nothing to stop that at all.

Okay. Thank you. Representative Tomaszewski. Thank you, Co-Chair Foster. So we got these 3 projects.

I imagine one may be more lucrative than the other. And we may want to put our money in one of these projects over the the other initially. And so I imagine we're going to have that information and see at the time of that investment decision, you know, the potential return on investment of these three individual products and which may be better. And I imagine you're going to give us your opinion on where we should put our money, I would imagine, in the future when this all does come to fruition. Representative Tomaszewski, through the chair.

In fact, I wouldn't say one will be more lucrative than another. There's no such thing. They'll have different risk and return profiles. And so you'll have a pipeline is generally underpinned by, you know, either tolling agreements or just kind of secure revenue generation through the years that you know up upfront pretty much. And so that's very low risk.

And that's why if you look at pipeline investments across the country, you'll see a lot of like teacher funds and some of these, you know, more risk-averse funds invested into those. Whereas on the LNG side, you may have some exposure to commodity risk. Commodity risk is where you end up with quite, you know, quite a bit more risk, but some potentially higher returns. And so, they'll just be different risk and return profiles. And yeah, and each one, we will not have these all next to each other at the same time.

Some of them we will, but of course, Phase 1 FID will be far ahead of Phase 2. So, you know, a year or more ahead, I would anticipate. But each time, definitely, we'll be able to come in and talk about what the risk and return profiles are of each each one for the state to make that decision. Thank you. Okay, last slide.

Thank you, Mr. Chair. Again, we've talked about many of these different options, but we wanted to at least put them on the slide for the public to understand that we have reserved the option for the state to invest or not. So the state ultimately could make a decision not to invest in any or or any portion of any of these subprojects. And that would be fine.

The projects would proceed to go forward. We just wanted the opportunity for Alaska to invest. How do you do that? We're looking at ways now to potentially— because we know that cash is very tight within the state based on our budgets, that we're looking for ways to use in-kind contributions. And so you saw that there were new regulations coming out from the Department of Natural Resources for materials, in this case gravel, that could be provided to state corporation, meaning AGDC, that could provide to the project and get an equity position from that contribution.

So non-cash investment. Third alternative is coming to the legislature for an appropriation. And it would really be up to the decision makers, the policy makers, to look at the books to see, as Matt described, the risk-reward profile and determine whether or not that was a good investment for Alaska. Additionally, again, the opportunities are around bonding. And again, we talked about general obligation bonds, but that would require legislation to be able to provide for the vote of the people to back those bonds.

Or as we described earlier, again, revenue bonds, which are really about utilizing the contracts and the revenue coming from those contracts to underpin those, those bonds and those bond payments. As we've discussed, there will be multiple decision, multiple investment options presented to the state. This first one is Phase 1 of the pipeline, and that's where we hope to be able to find ourselves very shortly with, again, successful legislation and a new alternative volumetric tax that will allow this project with its very thin margins to proceed forward. And our goal is to be able to communicate with the legislature, share the information when the investment opportunity comes forward, to be able to allow you to make that decision. So thank you.

Okay. And just for the record, that was Mr. Richards. And we've got Representative Stepp with a question. Yeah, thank you, Chair Foster, Mr. Richards. Obviously, this is a future decision that's kind of separate from the issue that's before us, which is the property tax abatement.

But I am curious, since you guys are here, I see you have a general fund appropriation, bonding, and in-kind contributions, but didn't the Canada project— didn't their pension fund invest in their LNG project? Through the chair, Mr. Kissinger. Representative Stapp, through the chair, I believe that's correct, that they would have invested in that, in the pipeline portion. Follow-up, Mr. Cook.

I'm curious, obviously state has investment fund and permanent fund, pension fund. I'm curious why that's not a potential option on the slide deck. For the record, I'm not saying that's a wise option. I'm just saying it's not on the slide deck, through the Chair. Mr. Kissinger.

Representative Stapp, through the Chair. We should be clear that actually we have the right to extend that option to any of our sister agencies. Agencies. So that would include the Permanent Fund Corporation, ADA, the railroad.

Okay. Any further questions? Representative Hannan. Thank you, Chair Foster. I want to get a little more information on the in-kind contribution and the issue of gravel.

Because it's not— the gravel piece isn't directly addressed in, I think, our current version of the bill, but it's certainly been talked about as being a vital piece going forward and an expectation, and I think there's already a DNR reg that does it. So, do we presume we get to take that at its cash value for in-kind contribution for an equity position, or is that the DNR proceeding with regs to give it to you to pass on to the project still in negotiation? Through the Chair, Representative Hannan, Frank Richards. Again, this is a negotiation that we are underway with right now with the developer in terms of the opportunity to utilize this in-kind contribution. The first necessary step was to have the ability for DNR to provide it to other state corporations at zero cost, and then it allowed us then to enter into this negotiation on utilization of that for equity.

Now, as we've talked about here, again, our range of— ownership, we've reserved between 5% and 25%. And we talked yesterday about 20 million yards with a rough value of $60 million. Well, that doesn't quite break the 5% threshold. So that's part of our discussions and negotiations with Glenfarm about the ability to utilize some of that within that, that threshold or even having that threshold altered. Follow-up.

Follow-up. But I guess I've, I've heard in two days two different versions of this. So I want to know if they're not going to be willing to give us $60 million of in-kind value for it, can we charge them for the gravel? Or is it your expectation at AGDC is the gravel authorization is already something that you've taken account care of and intend to do, or is the potential is there's a charge for it? Through the Chair, Representative Hannan, if the negotiations don't come to successful conclusion, it would be a charge to the project.

Okay. Thank you. Okay. Seeing no further questions, I believe you are through the slide deck. I notice there are a few in the back there, but I think those are just—.

Thanks. Okay, reference. Okay, um, real good. Certainly appreciate it. We'll just take a 5-minute, uh, at ease just to stretch our legs, and then our last presenter will be Mr. Larry Pursley.

And so House Finance will be at ease at 3:18 PM.

Okay, I'll go ahead and call this meeting of the House Finance Committee back to order. The time is currently 3:35 PM. I want to thank Mr. Larry Pursley for being here today, and if you could put yourself on the record and walk us through your comments. Sure. Through the chair, for people who are not familiar, I thought I'd give the 30-second resume.

The short summary is I've worked on this for 30 years, so the fact that there is no gas line, you can blame me.

And we're done with the presentation. No, I'm joking. Yeah, pretty much, yes. Okay. Someone's got to take the fall, and I'll volunteer.

All right. So I first started working on the project in earnest. I was with the Department of Revenue Commissioner's Office from '97 to '99— I'm sorry, '97 to 2003, the last 4 years as Deputy Commissioner. I was also involved in the Stranded Gas Development Act negotiations. In '03.

Neither of those efforts resulted in a pipeline. I worked as Associate Director of the State of Alaska Office of the Governor in Washington, D.C., 2007-'08, again working on oil and gas, and this project specifically were in the portfolio. 2010-2015, I ran the— what was called the Office of the Federal Coordinator for Alaska Natural Gas Transportation Transportation Projects created by 2004 congressional action. Our job was to, I guess, be the concierge— the office that would coordinate all the federal regulatory and permitting agencies to ensure they moved quickly, reasonably on the gas project. We closed that office in 2015 after Congress ended the funding.

Because the office— and just the last point on this— the office was created in 2004 when it was going to be a domestic gas line project. And there was a public policy issue that, well, we need the gas in North America, we're going to create this office, loan guarantees, other, I guess, benefits for the project. When it's switched to an LNG export project, the law did not cover that. We were not allowed to operate on that, so we closed. And then I spent a few years after that at the Kenai Peninsula Borough as their oil and gas advisor and chief of staff to the mayor, again working on this project.

Because back then, the Alaska LNG project was led by the producers and they were acquiring property Nikiski and going through the federal environmental impact statement. So, but I'm to go into my— and I don't have slides. I don't know if that gives people a reason to breathe a sigh of relief or say, "Gee, I wish I had slides so I didn't have to listen to the guy." But I'm not going to talk about specific provisions of the bill or taxes or ownerships or 7.5 25.5% on alternating Wednesdays. I just would— was asked and would like to talk to you more about the history of federal regulation, why liquefied natural gas projects are so different than oil developments. But I think most importantly, Alaskans need to understand that the Federal Energy Regulatory Commission, or FERC, and the Department of Energy are both involved in this project, and they both have different roles.

FERC regulates construction and operation— the hardware, the siting, the environmental review— but FERC regulates construction and operation of interstate natural gas pipelines and any LNG project, export or import, in this country.

For the interstate pipelines, interstate gas pipelines, FERC does regulate the rates and the tariffs, the rate of return on those. FERC has no authority, no interest, none whatsoever in regulating tariffs on pipelines that are not part of the interstate grid. And that's what we have here. The Alaska LNG project pipeline is wholly within Alaska. Yes, some of the gas is going to leave Alaska, but it goes to overseas buyers.

And it's— there's not an interstate commerce issue and there's no federal law, or really you could say, um, policy that says the federal government should regulate what the price is of a commodity that's sold overseas. So it was when the Alaska Gas Pipeline started back in, well, 2012 or so, you had a couple different proposals out there. There was the NALI pipeline, which was a BP ConocoPhillips venture, and then the TransCanada Exxon venture. And both of those were looking at a project that would go from Alaska, south, take the turn before you get to Fairbanks, go through Canada, and connect with the North American grid. And that was regulated— or that would have been regulated by FERC as interstate pipeline.

They would have set the rates. They would have gone through what are called open seasons, where the pipeline developers say, hey, we're gonna build this. This is what we think— how much it's What's it gonna cost? Who's interested in using it? An open season gauges interest among shippers.

None of that on this.

They shifted to an export project because around 2008, 2009, 2010 hydraulic fracturing, shale gas changed the market. Prior to that, the expectation was North America could run short of gas. So maybe Alaska's North Slope gas had finally, finally met the day where it would be needed. But with shale gas fracking, US natural gas production today is more than double what it was 20 years ago before the shale gas revolution. It's—.

Lower 48 may like our fish. They don't need our gas. They don't wanna pay for it, they have no interest in it. There's so much natural gas being produced in lower 48, we're exporting a lot of it. Or in some cases, in West Texas and New Mexico, which is the Permian Basin, there's more gas than there's pipeline capacity to move it, and so on.

Many days this year, the gas has a negative value. You're producing as a byproduct of oil, There's no way, or limited ways to move that gas out, so you gotta pay someone to take it.

It's unfortunate we can't get them to somehow get it to South Central.

So, back to FERC, since there's no FERC oversight on the regulations on this project. Now, FERC did conduct or put together the environmental impact statement and issue authorization for this project. And that authorization, that EIS, covers the pipeline from Point Thompson to the gas treatment plant at Prudhoe Bay, the gas treatment plant, the 807 miles south through Alaska underneath Cook Inlet The liquefaction plant at Nakiski and the marine terminal in Nakiski, all that is authorized under the FERC order in 2020, which says you can go ahead and build it. You can go ahead and operate it if you meet these conditions, meet these terms. But the FERC jurisdiction, again, only applies to the construction and operation, not, not anything else.

That's just not what FERC looks at.

Even to the point, if you look through the 6,000 pages of the EIS and the supplemental EIS put out by the Department of Energy and look through the FERC authorization, the words cost, tariff, rates, cost overruns, they're not there. It's just not— the fact that the project may be uneconomic is not their concern. FERC has, over the years, approved multiple gas projects that never get built. I don't care. If the project applicant reimburses FERC for the cost of the EIS, that's the end of their financial relationship with the federal agency.

Mr. Chairman, should I just keep going or wait for questions? I'm—. Does anyone have questions? I could talk for days. We've got a question, Representative Hannon.

Thank you, Co-Chair Foster. Mr. Pursley, that EIS that was completed and you said authorized in 2020, how long is that EIS good for?

Through the chair, Representative, the authorization that FERC approved in 2020 has a 2030 deadline. The project has to be in operation by 2030, though it's not uncommon for project developers to seek extensions. It happens frequently, either because they really ran into delays or their original timeline was overly optimistic and they knew they were always going to have to get an extension. Thank you. Representative Hammond.

Thank you, Co-chair Foster. And so in your familiarity, Mr. Pursley, with FERC permitting and I assume some EIS extensions, and it's 2026, I think even in the most optimistic scenes we're not going to be fully operational by 2030, but I don't know, the engineers are pretty wildly— maybe they can all work 36 hours a day. When should a FERC extension for that permit be applied for? Because it is also only 4 years out, and sometimes things don't happen as rapidly as we'd like. Right.

So through the chair, Representative, the FERC authorization was for the entire project. Right. I guess the question might be, and I don't think FERC's ever faced it, what if the pipeline were in operation by 2030 but the liquefaction plant wasn't? I— my belief is FERC would— you'd need an extension because FERC doesn't look at it as Phase 1 or 2. It's just the whole thing has to be in operation by 2030.

In terms of when you apply for an extension, I've seen some projects that do it 2 years in advance. I've seen some just do it a few months in advance. I guess if I were the political advisor to this developer, I say, do it while you still have Trump appointees on FERC so you get your extension sooner than you might otherwise. Okay. And I'm sure the developer's smart enough to look at a calendar and count votes.

Okay. Thank you. Representative Stepp? I'll defer a little bit until he goes on a little further. Thanks, Co-Chair.

Okay. Mr. Pursley? So I think I mentioned earlier that there's two authorizations, FERC which says you can build it and you can operate it. You need Department of Energy approval to export or import the commodity into this country. Department of Energy doesn't look at the liquefaction unit, the compressors, the pipe, the steel.

They look at the public interest of the import or exports. The Department of Energy export authorization for this project also has a deadline. It's 2032. And there again— and that's when exports would have to begin. A developer can apply for an extension.

Now, one small point to keep in mind, the export authorization is in the name of the original applicants, which was Alaska LNG LLC, which is Exxon ConocoPhillips, now Hilcorp. Taking over BP's share at some point in this development, then Glenfarn, Astar, Alaska, and the authorization holders would have to go to the Department of Energy to request a transfer from holding that authorization. And that assumes that the authoriz— the export authorization needs to be held by the entity that's exporting the gas. So if the producers were to sell the gas up on the North Slope to A* or some other LLC, which would then be the exporter, the authorization for exports would need to be transferred to that entity. But that also is pretty routine.

The Department of Energy would publish a notice, public comment period, and they could issue the transfer.

The export authorization and FERC jurisdiction is covered by something called the Natural Gas Act of 1938. Has two important sections that sometimes people get confused. Section 3 prohibits the export of or import of natural gas in and out of the U.S. without authorization. So Section 3 applies to this project. Section 7 is the one that deals with interstate gas pipelines, and sometimes in my conversations with people, they're more familiar with Section 7 because it's the one more people are used to, but— and that's— Section 7 is the one that says FERC has to decide whether the pipeline tariffs are, quote, just and reasonable.

But that only applies to interstate pipes. That section does not apply to this, this project.

One thing, I guess, keep in mind, under the federal rules, an LNG export project does have to report to the Department of Energy, literally report their exports, where it's going and how much. That's publicly available. You can see where where the cargoes are going. Not the price or the terms, but you can see oil and gas both where shipments are going. It's a, a different regulatory world for the Regulatory Commission of Alaska, and I think it's important to keep in mind that any utility—NStar, Chugach Electric, Matanuska Electric, Golden Valley if they ever got into buying gas, needs RCA approval of their contract before they can put it into their rate base and recover their costs.

So if you want to look at the RCA as the protector, I guess no utility is going to sign a contract that they can't get reimbursed from their customers, can't pass through the gas cost. So that's where the RCA comes into this. You know, again, without that RCA approval, Enstar or Chugach could not recover the cost of the gas supply from their customers. The— and that's separate from authorization. There's been some confusion that this project has been authorized by FERC and they don't need RCA.

Well, FERC said you could build it, but if you're moving the gas from point A to point B in Alaska and selling through a regulated utility, which is what the customers generally are gonna be, then the RCA does get involved. So think of it as kind of a pipe within a pipe. There is one steel pipe, but there's some gas moving through it that the RCA is gonna get involved in, whereas most of the gas, FERC doesn't care what it's sold for and the RCA doesn't care what it's sold for, or the tariffs. Um, and I guess It has happened. Back in 2006, the RCA rejected a gas supply contract that, um, I think it was Enstar had with Marathon.

In hindsight, we would have been better off if they had approved it because it would have tied Cook Inlet gas prices to a blended average of lower 48 prices, which have alternated between being in the toilet and on the edge of the toilet. Over the past 20 years. But at the time, the feeling was it was not a good contract. The RCA rejected it. Marathon and the utilities negotiated a different deal, and Marathon said, that's it, we're out of here.

We're just not going to take the risk anymore.

I'm just looking for—.

Rep. Sinisterra. I guess I will oblige, Commissioner. Thank you, Commissioner Foster, to the Chair, to Mr. Pursley. Thanks for being here. So I feel like most of this issue with FERC and RC is kind of known to the developer.

I think I read the comments from Mr. Duvall the other day at the Sustainable Energy Conference where he talked about two big issues with this project that he needs. One is this tax abatement that we are talking about here at the Committee, and the other is he seemed fully well aware that he would have to go through RCR approval. Is that your understanding? Through the chair? Through the chair, Representative, I didn't go to the conference.

I don't go somewhere I gotta pay admission. So I read in the paper. Okay. Yeah, it's my understanding that they know that if a utility is buying gas, the RCA gets involved. Yeah.

In fault, Mr. Co-chair. Representative Stout. Yeah. Outside the one example you have from 2006, I mean, If the, you know, the costs are known and obviously, you know, that the gas cost has to be recouped by the rate base, unless the number is outrageous at some level, do you foresee the RCA not approving this type of agreement through the chair? Through the chair representative?

No, I think if it's not unreal— because it also statute, which was amended in 2010, instructs the RCA to consider not just price but also diversity of supply. Utilities have to have that gas. They've gotta know it's coming down the pipe to run the power plants. So there is certainly a value to having a guaranteed supply rather than, "No, I'll take my chance, maybe I can buy it on the cheap next month." Okay, thanks. I will say it— one complication, and I am not an RCA expert, But, um, if an entity owns the pipe and moves its own gas, so it's, it's essentially a proprietary pipe, and then they sell it at the end of the pipe, that's a different issue for RCA than if the pipeline is available for third parties.

So for example, if Enstar bought the gas on the North Slope and Enstar moved its gas through the pipeline, then the question is, does RCA get involved with pipeline tariffs? If H-Star buys the gas on the slope, moves it through an H-Star pipeline, and then sells it at the end of the line to N-Star, then I would think RCA regulation comes in at that sales point. But the ownership of the pipe, who's owning the gas moving down the pipe, could pose a— it's not a problem, but an issue that the RCA would have to resolve.

I would also like to add to that, we do have NSTAR. Mr. John Sims, I believe, will be in on Monday. And I know that he's been before RCA quite a bit. And so we'll have him in. Representative Galvin.

Thank you. Thanks for being here, Mr. Pursley. I'm hoping that you'll give us a little sense of— I think you were starting to go there. Let's say some of the producers have bought into 8 Star, or if, if N Star has bought in as part owner, does that also create some of these complications where we need to work out or understand better how RCA might approach it in terms of the pricing to Alaska ratepayers, for example.

Through the chair, Representative, I'm trying to think through the scenario. So are you saying what if Producer A, instead of selling its gas on the North Slope—. They do sell it, but they— pardon me, through the chair. They— to give you the scenario a little bit more clearly, there's 3 different entities that investors can put into: the pipeline itself, the treatment center, and then the port. So if they choose to invest in any one of these, and in this case the pipe, for example, and so they are now a part owner of the gas that's coming through, so to speak, or at least of the pipe, and then they're also setting the price of the gas that goes into the pipe.

Through the chair, Representative, I don't think ownership of the pipe would make a difference. Either it's a proprietary pipe— I own it, I'm moving my gas— or It's a pipe that I and others own, and we're moving gas for different owners under contract with them. So I think the shareholders in the pipeline wouldn't matter as much as either it's a pipeline that is moving third-party gas or it's my pipe and I'm moving my gas totally, if that makes sense. It does, but I'm thinking through to the after it gets to the market. And if they, they've told NSTAR, let's say, they're selling it to NSTAR and they'll give it to them at whatever price and they have ownership of this whole operation.

I'm just trying to understand if we, if we're getting ahead, kind of out ahead of our skis and we then don't have control over, or if the, if RCA can, then at that point I think some of the words that we heard from representative staff where they're looking at price and the diversity of supply. So they would be able to, at that point, I assume, step in a bit if the— if it's getting priced in ways that are more advantageous, let's say, to one of the 8-star owners who happens to also be a producer. Through the Chair, Representative, you know, I'm trying to think this through. So It's, um, are you suggesting that different shareholders of the pipe pipeline company, some of them might be moving gas that they own through a pipeline that they own a partial share? They may own 17%, and other owners own 83, whatever it is.

It's different shareholders so that Um, but I would think that pipeline would have one rate for everybody, not different rates for different entities that may or may not own a percentage of the shares in the company that owns the pipeline. That, that makes sense to me, that there would be sort of an even rate. What I, I guess I don't understand is if industry owns a larger portion of it, if they're I don't know if they could then price it, all of them, at a certain rate that might be disadvantageous. And I just— what I guess what I'm looking for, the answer I'm looking for is that RCA will take care of the ratepayers and that has been shared with us by other presenters. And I want to believe that's absolutely true.

I just wanted to see if you had any thoughts on that. Through the chair, I will say there's something called the TAPS settlement methodology that went back decades because when TAPS first went into service, the producers were going to— well, not were going— they are allowed to deduct the cost of transportation from calculating royalty and production taxes. So what TAPS— what it was going to cost to move oil down taps became a big issue. And the state had one number in mind and the producers had a bigger number in mind and they went to litigation, settled before court where— and the problem for the state cash flows— flow was that the producers were— they were deducting the higher rate and holding it I don't know if it was escrow, but the state wasn't getting the money and the state needed the cash. So the state settled, negotiated a lower rate for TAPS, and because the producers own TAPS moving their oil, it's been controversial over the decades since.

If there's no producer involvement in this project, you're not gonna have a problem on that scale.

But, and that the— just to finish, the pipeline, oil pipeline tariffs go before the RCA and FERC because it's interstate. So the oil that moves within Alaska is RCA jurisdiction. The oil that goes into a tanker at Valdez and goes to California or Washington State, those tariffs go before FERC. Okay. We've got Representative Stepp and then Bynum.

Representative Stepp. Yeah, thank you, Co-Chair Foster, the Chair, and Mr. Pursley. Again, thanks for being here. So, you know, we talked a little bit about the 2030 expiration for FERC and the 2032 authorization expiration for the DOE in terms of export. It seems to me, based on all I've heard thus far, is that the developer is basically asking us for this level of an abatement.

It seems like there is some level of urgency. They may or may not have to extend those timelines, probably would based on what I'm hearing from you. But I've listened to a whole lot, and I don't see a lot of fiduciary risk to the state by simply looking to try to deliver on the developer's request so that they can have the best level of economics to move toward a final investment decision. So my question to you is, am I missing something in that statement? Through the chair.

Mr. Pursley. Through the chair, Representative Soos, the question— to rephrase it— what's the risk of the state writing off some property taxes if it helps the project get built? Yes, through the chair, correct.

Through the chair, I'm trying to be careful on this, I guess.

Denying money to the general fund is a cost. So, and thankfully it's not my decision, it's yours. How much are you willing to short the general fund or municipal budgets because you're trying to— I hate the word incentivize, but you're trying to incentivize something getting done that wouldn't get done otherwise. And where is that point? You know, how many cents on the dollar is it?

At fault, Mr. Co-Chair. Representative Steff. Yeah, thank you, Co-Chair, through the Chair to Mr. Pursue. Yeah, no, I mean, so unlike our current oil production on the North Slope, I mean, we currently don't have a project, right?

So when we talk about future revenues, they're nonexistent because there is no project, right? So to me, like, when we talk about this in depth, we looked at our heat tables with our economics. The economics on the project, even with our 10-year-old cost estimate, are marginal at best, I would say. The request from the developer makes that more likely but still not that less than marginal. And I guess from my perspective, I want to make sure the state's insulated from any fiduciary risk.

I just, I don't really see what that would be. I mean, worst-case scenario, we give them this bill and they don't go to final investment decision, right? Through the chair?

Through the chair, Representative? In some people's Minds, right, not getting the project, if that's the outcome, you're right, you didn't risk any money, but if the project got built, you have diminished general fund revenues if you thought it would go ahead without the property tax relief. Okay, follow-up, Mr. Co-Chair. Representative Staff.

Thank you, Co-Chair, through Chair Musser-Pursley. Do you think the project can get built without property tax relief?

Through the chair, Representative, I will say if you change nothing and the project went ahead, yes, you're looking at $800 million, $900 million, $1 billion in property taxes under the current 20 mil levy. Though I will point out that under current statute, the liquefaction plant in Nikiski would not be subject to state property tax. Because the state 20 mil oil and gas property tax only applies to exploration, production, or transportation, and a liquefaction plant isn't any of those. So depending on the final cost, yes, it's— the economics, and I'll actually talk about this in a couple pages, but the economics on an LNG project are much more challenging, much tighter than an oil project. So do I think an LNG project could afford $1 billion in property tax?

Say, just do math. $20 Million at $50 billion? No, I don't think so. The question is where between $1 billion and $76 million is the magic number. Thanks.

Okay. Representative Bynum. Thank you, Co-Chair Foster. You know, I've been hearing a lot about contracts, contract types. Utility RCA overview.

I think probably it would be helpful for the committee at some point that you could get a quick refresher on contract types, fixed price contracts, formula-based contracts, roll-in rate treatments, reopeners, those kinds of things. Because part of this project really is revolving around the idea that we are getting contracts put in place so that we can go forward. I think that it's an important part of the conversation when we talk about putting in fixed contracts or putting in some kind of a contracting mechanism that's at a benefit to the utilities. That happens likely before construction begins. And then when we talk about cost overruns, those cost overruns are going to impact the investors, including a lot— including Alaska as an investor, if we are one.

And so, and the profitability. So I think those are something that we probably should be talking about. I think there's a lot of concerns about cost overruns and how it might impact the ratepayers. These contracts being in place will protect ratepayers. Who's overseeing those, I guess, is a bigger question here.

But what I wanted to specifically ask was, we talked about FERC being an entity here with oversight on the they'll have some, some level of oversight on tariffs potentially for the line itself, but not about how we're dealing with, with rate or commodity pricing.

You'd mentioned that when we talked about export, that export was for foreign markets and therefore wouldn't be applied. Is there any consideration of what would happen if the export was for US use, meaning Hawaii or the lower 48? I know that there's a lot of restrictions on that being the case now, but those could change. And if they did, how would it impact FERC's responsibility? Sure.

Through the chair, Representative Bynum, just to clarify one point you made, if I heard correctly, I think you said FERC would get involved in the tariffs on the pipeline, but they wouldn't. It's just not an issue for them on the pipeline as it is now. But you do make a good point. If this project were to start exporting gas to California, Hawaii, then it becomes interstate. Then FERC would, under Section 7, get involved.

Follow-up? Follow-up? Thank you. Follow-up. How would you see— I mean, my vision of that happening would be something further down the line.

And so we go to Phase 1, we go to Phase 2, we have these contracts in place, we're exporting to Asian markets as an example, and then all of a sudden something changes in federal law or the climate changes where we are now exporting to our own states, Hawaii, California being a —good example—how would—how do you think that that regulatory involvement would happen, like, from a functional perspective? Through the chair, Representative Bynum, it—I would think, and I haven't thought about—but if the gas is moving across state lines, then I assume there's a mechanism where the exporter, you know, is the owners of the project, the export, would have to fill out forms and apply to FERC and get approval on tariffs. Though, as you point out, a U.S., because of the Jones Act requirements, if you're gonna move the commodity, in this case gas, from Alaska to the West Coast, has to move on a Jones Act tanker built, flagged, U.S. cruise. There hasn't, last Jones Act tanker was built in the U.S. in the 1970s. '70S.

Yeah, so, but it's right, things could change. It's certainly possible, and I would say the people at FERC who have been working on this project for 40 years would probably be retired by then, and someone else would take the call and say, "I don't know, no one's ever done this before." One follow-up. Representative Bynum. Thank you. So in that scenario, we'd say I would assume that that would then fall upon the exporter, the— whoever's responsible for actual export onto the ships and whoever's owning that.

That would then fall under the FERC, not necessarily the whole system as a whole. Right. Through the chair, Representative Bynum. Right. The exporter, the entity that is selling and delivering the gas to California.

You know, in that context, just a little bit, uh, sort of on where LNG exports are for the US, uh, there are currently 9 export terminals in operation in the United States. Uh, we went from 0 to 9 in 10 years. All that shale gas needs a market, and that's kind of how markets work. So we now have 9. There are 7 on the Gulf Coast, 1 in Georgia, One on Chesapeake Bay in Maryland.

Several of those 9 are in expansion mode. There are several more that— there are 10 LNG projects that have been approved by FERC that have not proceeded to construction yet. So there's a backlog there. They're looking for financing, they're looking for customers, they're looking to put together their economics. Of those 10 FERC-approved LNG projects, Glennfarn has 3: the Alaska LNG project, a project called Texas LNG in Texas, and one in Louisiana.

But— and again, these are projects that— and not to just pick on Glennfarn, the other 10 are probably all in the same boat. They're going to run up against their FERC deadline, and if they want to proceed, will need to get an extension of their authorization. In addition to the U.S., There is now an export terminal in British Columbia, went into operation last summer. It's called LNG Canada. There are two more LNG export terminals under construction in Canada, one in British Columbia, one just north of Vancouver.

Uh, and then there's one more just across the border from Alaska that talks about making a final investment decision sometime this year. Also, I find this interesting. There is an LNG export plant which is close to starting up on Mexico's Baja Peninsula that will actually be exporting U.S. gas. There's so much gas in New Mexico, West Texas. They're going to pipe it down to Mexico and then ship it out from there.

So we're not the only one on the West Coast. I had a question, Representative Pannen. Thank you, Chair Foster. Mr. Pursley, I want to go back to Glenfarm's two other projects that are FERC-approved, the Texas LNG and their Louisiana project. In your opinion, what's holding those projects up?

Um, through the chair, Representative Hanna, I assume economics. Um, the Texas LNG project, earlier this year Glenfarm announced they had contracted with a financial advising firm to put together the several billion dollars in financing they need for that. So, and they keep— so they're working on that. The other one is not nearly as close. But I assume you look at the 9 that are in operation, several are in expansion mode, 10 more have approvals.

The ones that went ahead, had, well, gas supply is not an issue in the Lower 48, but they had enough bind customers signed up for long-term contracts to provide collateral to get financing and investors. So the ones that haven't are still putting together the numbers, the partners, the investors, and selling off enough of the LNG on 20-year deals, they can get a loan. Follow-up? Follow-up? And what— I mean, the project economics that prevent it, right?

We have an excess supply of gas, just like West Texas.

Why would I, as Glenfarm— I mean, I got to find buyers for all of my gas if I'm going to make it equitable. And it would seem that our economics are the most challenging when we've looked at all these projects laid out. That's how it gets described. Alaska's, you know, we're at a big distance, expensive distance disadvantage. So what keeps Glenfarm from pursuing contracts for Argus versus their Georgia plant?

Or do you think that as a developer they've got different clients potentially for each of the 3 projects that they're trying to get to FID? Through the chair, Representative Hannon, generally Gulf Coast projects like the Tulugun Farnese trying to develop in Texas and Louisiana are looking toward customers in Europe or Latin America, South America, rather than ship the long way to Asia. But it's, it's done a lot of the Gulf Coast gas, particularly now with the Mideast supply turmoil. A lot of gas is leaving the Gulf Coast and going to Asia, but generally, Gulf Coast is going to look to the Atlantic Basin and whether it's Baja California, Alaska, Canada, generally going to look for customers in the Pacific Basin. Okay.

And I see no further questions. Mr. Pursley? A couple of things to, to point out, I think. As you sort of wrestle with this. The difference between oil and gas pipelines, oil and gas markets, oil pipelines are generally common carriers.

They're open to everybody. There's no long-term contracts. There's capacity, you got oil, there's room, you move it today. Gas pipelines, particularly the FERC-regulated interstate world, those are contract carriers where the shippers and the pipeline owners, sign years-long contracts for that pipeline capacity. You know, it makes sense when you think of it at the— who the customer is at the end of the line.

For crude oil, generally the customers are going to be refineries. They have massive storage tanks. They have weeks, maybe, or more of storage capacity, so whether the oil comes that day or not isn't that crucial to them. You think about, um, and oil's generally sold on what's called the spot market or short-term contracts. The customers at the end of a gas pipe are power generators and gas utilities.

Gas does not store nearly as easily as crude oil. So if you're Detroit Edison, you've gotta know that, that gas is gonna be there, particularly wintertime, summer air conditioning. So utilities want, they need those long-term contracts, not just for the gas to be delivered to their burner tips. It's just, it's a different business, different business model, different market. One goes short-term, what's available today, I'm moving oil.

My customers literally can wait a day. The gas utilities need that certainty of supply on a schedule that matches what their customers expect.

I think another thing to keep in mind is the vastly different economics between natural gas and oil. So an example, and I thought about this this week, so the PICA oil development that Santos and Repsol just put into production The company's reported that it took about $3 billion in capital investment at PICA, and that will peak at 80,000 barrels a day. So let's assume $75 oil, which is, I think, what the FY27 budget's built on. If you had 80,000 barrels a day at $75 oil, that works out to $6 million a day in gross revenue. That's before operating costs, before pipeline tariffs, tanker charges, but just before royalty.

$6 Million gross. The Alaska LNG project, if it operated at full capacity of 20 million tons a year of LNG, its gross revenues, I'm gonna say $32 million a day. Just making some assumptions on the price in Asia. So, and that would take a $50 billion investment, depending how you want to round off the construction cost estimates. So you look at it, yes, Alaska LNG could produce 5 times as much gross revenue as PECA, but it would take 17 times the capital investment to produce that.

LNG projects are just very capital intensive, which is why Project developers want their lenders, their investors insist on long-term contracts knowing they're going to have the cash flow to underpin the debt, the mortgage.

And another point is that it's got to be with creditworthy customers. And that has been an issue with some projects. Some buyers like in Japan are more creditworthy than Bangladesh, which at one point this winter I think was half a billion dollars in arrears on paying for the LNG. So creditworthy customers long-term to cover the mortgage is essential for something like an LNG project where it may pay consistent returns over decades, but it takes a lot of spending up front. Another way to think of it is if you have a supertanker with 2 million barrels of oil.

And if you just think of oil, gas, coal as BTU, it's just energy. That supertanker is gonna have 4 times as much energy as an LNG tanker. Just not as energy dense. Costs more money. A lot of that cost, again, looking at Asia, if the price is $10, $12, $9, whatever it is per BTU, A small portion of that's for the gas itself.

In Alaska's case, most of it will go to the gas treatment plant to remove the CO2, the carbon dioxide. And for people who don't know, you have to remove the carbon dioxide. If you leave it in the gas stream, it's gonna mix with water. It's gonna become carbonic acid, which is corrosive to the pipe. So unless you wanna do 800 miles of stainless steel pipe, You gotta get the CO2 out, and that's expensive.

You've also gotta get the CO2 out because if you leave the CO2 in the gas stream and run CO2 through a liquefaction plant, it turns to dry ice, which does not do much for the machinery. So you look at that price in Asia, most of it is gonna go for the gas treatment to remove the CO2, for the pipeline, for the liquefaction, and Prudhoe Bay, by the way, is about 12% CO2. It's a very carbon dioxide rich stream. And you're also consuming a lot of the gas. 15% Of what goes into a liquefaction plant gets consumed running the plant.

You can't sell it. It's just the cost of business. All that means when a buyer in Asia is paying 9, 12, 10, whatever it is for gas, most of it is going Essentially for the manufacturing process, not for the gas.

LNG tankers are more expensive than oil tankers. An LNG tanker is an expensive thermos bottle on a ship to keep it cold. So they cost twice as much as an oil tanker. Oh. Anyway, so if you think about, getting back to oil, It's about $10 to move a barrel of oil through TAPS and a tanker to the Gulf Coast.

So if you had $75 oil, $10 to move it, that gives me $65 to pay taxes, royalties, capital return, operating costs. Take gas. If you sell in Asia from Alaska at $10, you're burning up probably 80% of it, 75-80% in the manufacturing process. It's just different economics. This is not to endorse property tax relief or anything else.

This is just to understand the economics of LNG versus gas.

I guess, so for the last points, and certainly happy to take questions, I find this interesting. Other people may yawn. Oil is much— the oil trade in the US is much older. Oil production started in 1859. It wasn't until 100 years later that the first load of LNG left the country.

It's a newer industry. And even that's, I think, kind of interesting. The, um, England was short of gas. This is pre-North Sea oil and gas discoveries. So some Americans down at Lake Charles, Louisiana had this idea.

And they got an old World War II freighter. They remodeled it with balsa wood and plywood and urethane and aluminum and built storage tanks into the hold of the ship. And then they pumped LNG into it, standing behind a barrier because they weren't sure it was gonna explode. Pumped the LNG into it and shh, sent the first load of LNG to England in 1959. And then since then, it's certainly grown, but it's still a fraction of the oil.

And this is the last point I was gonna make. At today's prices, $100 a barrel, global trade in crude oil is close to $3 trillion a year. Even with all the growth in LNG, not just US, but Qatar and elsewhere, At today's high prices, global LNG trade is worth about $300 billion, so 1/10 the size of the oil market.

It's still a lot of money, but it's a much smaller industry, but growing. And to paraphrase the representative from Fairbanks, certainly be nice if Alaska grew with it.

Not to put words in his mouth through the chair. Oh, that's good. I agree.

Okay. Is that the conclusion of your comments, Mr. Pursley? Yeah, I will say when I was with the Federal Gas Line Office, we put together a 40-page book on the history of failed Alaska gas line projects. And I have the final 21 residual copies that still exist.

It's available online, but if anybody wanted a printed copy, I'd certainly pass it out. So I'll hang around. Thank you. Appreciate your comments. Good to get the perspective on all sides here.

And does anyone have any further questions? Okay. Seeing none, appreciate your being here. Oh, we do. Representative Valer, do you have a question?

Pointing to Rep. Tomaszewski. Oh, okay. Sorry, it's a different picture. Okay, and so I think we're going to go and close out. So just to announce, tomorrow we'll be meeting at 1:30, and at that meeting we're going to hear from 6 invited testifiers.

4 Of them are the producers— that's ConocoPhillips, ExxonMobil, Hilcorp, and Pantheon Resources. Then we're also going to hear from the mayor of the North Slope Borough as well as the mayor from the Kenai Peninsula Borough. And then I think, I think that's what we're looking at. Representative Ballard. Thank you.

Did we get any representation from this great municipality of Anchorage that was going to be speaking or anything? We reached out to the municipality of Anchorage today and are awaiting word back and I'm getting a head nod, so we're going to continue to work on that. Okay, so just to be clear, the mayor hasn't responded? The mayor's office hasn't responded yet? That's correct.

Okay, thank you.

Um, I think sometimes maybe it's just a matter of pushing the microphone all the way in, I think is what that is. Any further questions? Okay, so, uh, with that, we will go ahead and adjourn out at 4:28 PM. Thank you.