House Finance, 5/21/26, 1:30pm

Okay, I will call this meeting of the House Finance Committee to order. Let the record reflect that the time is currently 1:38 PM on Thursday, May 21st, 2026. And present today, we do have online Representative Moore, and we've got Representative— let's see here— we've got Representative Kocher-Schraggi, Representative Kocher-Josephson, Representative Galvin, Representative Hannan, myself, Kocher-Foster, Representative Bynum. Just a reminder, folks can mute their cell phones. And we are going to— we've also got representative staff.

And let's see, in the audience we also have Representative Holland as well as Senator Myers. Thanks for joining us today. And we've also got Representative Tomaszewski. And so Representative Jimmy, we also have. And so we are in special session and we are Taking up the item that was put on the call for the proclamation for the special session.

Representative Elam, thanks for joining us. Um, and that item was House Bill 381, the Gas Line Bill. We last heard from Department of Revenue, and that is Mr. Dan Stickel, Chief Economist. Last Thursday is where we left off, so we're going to continue with our presentation from Department of Revenue, Mr. Dan Stickel. And also online, just so folks know, we do have Mr. David Herbert.

Or let's see, actually I don't see him online right now, but we do have Owen Stevens, commercial analyst. And so with that, Mr. Stickel, welcome back. If you can put yourself on the record and continue walking through Thank you. We also have with us Representative Allard. Prepare your presentation, walk through the presentation.

Alright, again, for the record, Dan Stickel, Chief Economist with the Department of Revenue. Thank you for the opportunity to come back before the committee and continue our presentation from last week. So when we were before the committee during the regular session, We had walked through some background on the property tax, which is being adjusted by House Bill 381. We had walked through what the proposed legislation in the version T House Resources Committee substitute that's before this committee, what it would do, and the revenue impacts for each of the various provisions of the bill. We had walked through our implementation costs in our fiscal note, and we were— we left off right before we got into the detailed project modeling from the bill.

A couple things I wanted to note before I jumped into that. So we did have a correction to one of the slides. I think it was slide 16. I had called out— called that out when I was presenting that there was some incorrect numbers around the alternative volumetric tax. We have updated those numbers for the committee, and this is not the updated slide.

The committee should be getting the updated slides soon. I believe we have that on the way. You have the updated slide. It's not on the projector here. A couple other things I wanted to mention.

I wanted to make a couple of clarifications to statements I made last week. For the 25% equity interest under this bill, the municipalities could participate within the state's existing 25% equity interest alongside AGDC. They could also potentially negotiate something further with Glenfarm if they wanted to. Under this version of the bill, the municipal options— so the, the bill establishes an alternative volumetric tax for the pipeline and then basically defers decisions on alternative taxation for the gas treatment plant and the LNG facility facility to the relevant municipalities. The options there for the municipalities are to keep the existing property tax, they could reduce the existing property tax or eliminate that, or they could negotiate for an equity stake in lieu of property tax.

There is not an option for municipalities to establish an alternative volumetric tax for the treatment plant or LNG facility, and there's not an option for them to actually increase the taxes above and beyond the current property tax. For the Fairbanks spur line in this version of the bill, costs for that line are shared system-wide within the state. So among all in-state ratepayers, those costs are not shared with export ratepayers. And then finally, there was some discussion around carbon capture in the gas treatment facility. I had some discussions with AGDC following up on that.

So carbon capture and gas treatment, they are the same facility, and the size of that facility is designed for the expected throughput of the AKLNG project. It is potential— there is the potential that some gas, some other gas used on the North Slope could go through the facility, or there's the potential that other CO2 captured on the North Slope could use the same the same wells, but the facility itself is designed around the throughput of the AKLNG project. And so that would be an additional potential or negotiation and would defer any further questions on that to AGDC. We may have a question. Representative Josephson.

Yes, thank you. Good afternoon, Mr. Stickel. So you said the spur line would be paid for essentially by Alaskans up and down the length of the line. And then you said something about it would not be paid for by export funds or something. I didn't hear what you said and I'm not sure I understood it.

Right. Koshar Josephson. So when I presented previously, I stated that the costs for the spur line would be shared system-wide. And what I wanted to clarify is that it would be— under this version of the bill, it would be system-wide among in-state ratepayers. So Southcentral, Fairbanks, and any other in-state offtake from the LNG project would collectively share that cost of the Fairbanks Spur Line.

But the export— the buyers from overseas would not be paying for the Fairbanks Spur Line. Okay. All right. Thank you. I'd also like to recognize that we have in the audience with us Senator Kawasaki.

Thanks for joining us. Mr. Stickle?

All right. So if there's no other questions on that, we can jump into the detailed project modeling.

So slide 24 lays out our baseline assumptions for our AKLNG modeling. So we have a model that we've developed over multiple decades. It's been extensively peer-reviewed. Lots of confidence in the model itself. This slide walks through the assumptions that we are putting into that model.

So we're modeling a 32-year time horizon, which is 30 years of full export and then 2 years of in-state only during a ramp-up period. And that's the timeframe that we're analyzing for purposes of, of calculating various economics. We assume that there will be a 20-year debt service as part of that, and we're assuming that the developer is targeting a 10% pretax rate of return over those initial 20 years of full export operations. And that's kind of a typical time period for a payback for a project of this, of this sort. We are modeling based on a $46.2 billion construction cost that is based on Some, some pre-Glenfarn information that we've got from AGDC.

They have not given us detailed information about the construction costs of the project, so we've used that previous information from AGDC and we've simply scaled it up to current dollars based on inflation. We're assuming a $1.50 per 1,000 cubic feet purchase price for the gas from the North Slope producers. That's in 2026 dollars, and we do assume that that value will increase with inflation in the future years. In terms of the production into the project, we are assuming— we have not identified a specific field for Phase 1 production. Originally, there was some talk around Great Bear Pantheon potentially being a source of gas for the initial phase of the project.

That That availability has been drawn into question based on some recent well results, and so now we're assuming a general, a more generic Phase 1 field. One of the benefits of the Great Bear Pantheon find is that that gas is a very high-quality gas that would be immediately utility pipeline quality, and so it would not require treatment. We are now— this is a change that we made earlier this session— we're now assuming that our The gas from Phase 1 will come from a different field on the North Slope that will require a gas treatment cost. That would probably be a small— potentially a smaller facility than the full gas treatment facility, potentially some sort of modular treatment. But then once we get to full exports and the full project throughput, we're assuming that Prudhoe Bay and Point Thompson will be the two fields that will anchor that production.

And an important point regarding that is we are assuming that the Prudhoe Bay oil impact— oil production will not have any impact from the gas sales. We did run some scenarios in the other body looking at what would happen if there were losses to oil production from Prudhoe Bay. We are assuming a significant increase in liquids production from Point Thompson, totaling 270 million barrels over the life of the project. That was based on some information that was developed in collaboration with DNR and AGDC a few years back. We did hear some testimony in the other body that that may be an optimistic projection, and again, we have run some different scenarios in the other body looking at what some different amounts of increased oil production would look like in terms of economics.

But these are the key assumptions that underline our baseline model that we will be walking through. Okay, and I've got questions. Representative Stapp and then Hannon. Representative Stapp. Thank you, Co-chair Foster.

Good to see you again, Mr. Stickel. Thanks for being here, being a trooper through the chair to Mr. Stickel. Just a quick question. These cost projections. Um, how, how, when was, when did we get, receive that number from, uh, DOR, get it from AGDC?

I mean, how old are these basically? Through the chair. Representative Stapp to the chair. So this was based on an estimate we received from AGDC, and I believe it was 2022 or 2023. We've inflated that up, and I believe those costs in turn were based on some earlier work that had been done.

So they are somewhat dated. And a follow-up, Mr. Co-Chair? Follow-up? Yeah, thank you. Through the Chair to Mr. Stickell.

So just out of curiosity, I know that we're coming up on this kind of revenue projection table. Have you modeled that kind of construction cost into the kind of number in terms of the upcoming slides on the state, local, and federal take, if that changes? Through the Chair. Representative Stout, through the Chair. So we have— this is the cost that we've used in our baseline analysis.

And then we show the breakout. We have a slide on state revenues in particular, state, local, and revenue— state, local, and federal take based on that. We have some sensitivity analysis looking at state revenue at a range of potential different construction costs. Okay. Yeah, I'll wait for it.

Thank you, Commissioner. Okay, Representative Pandem. Thank you, Mr. Foster. Mr. Stickel, before we jump into the model, um, did you use any assumptions that ring-fenced the cost of the gas line against especially the legacy producers and legacy fields, or will they be able to use— if they have capital expenditure costs for the gas line that exceed their tax there, can they use them against their oil taxes from other projects? Sure.

Representative Hannans, through the chair. So kind of two, two ways of answering that question. First of all, the baseline model here has a separate analysis for upstream and midstream. So we assume that the cost of the AK LNG project will be— and the entire AK LNG project will be entirely developed by an independent third-party midstream. And so that's been really the main focus of the analysis.

We assume that the upstream producers will sell their gas prior to the gas treatment plant, and those are two completely different analyses. In terms of the upstream component of the analysis, we are modeling out the current law for oil and gas production tax, that oil and gas Production tax does allow for producers to apply all lease expenditures against the oil tax side of their calculation, and that's what we've modeled here. And we are assuming some additional lease expenditures incurred by the producers to bring on gas production. In particular, we have some significant level of lease expenditures at Point Thompson, um, assumed to be an expansion of that field with new wells drilled to bring on the gas as well as incremental oil. Oil.

We— the other body at one point had a provision to have us try to allocate out those lease expenditures between oil and gas and potentially disallow some of the lease expenditures related to gas from the tax calculation. That is possible. We testified in the other body that that would be extremely complicated and cost costly and potentially litigious to the state, that is certainly a policy option. It would be very challenging for us in the industry to implement, though. Follow-up?

Thank you, Co-chair Foster. And Mr. Sickel, if— and you've modeled it using the developer having all the midstream expenses, but let's say after it was built that they sold to one of the existing operators on the North Slope.

Does that midstream expense then can be used to capital expenditure lease expenditures to the upstream because they can apply it that way? Yeah, Representative Hannan, through the chair, for the most part, no. So there is some question around how lease expenditures for the gas treatment potentially would be incurred since that could be on the lease. Those would be things that we would work through. But generally, the concept would be that for the upstream production tax, that would still be based on the upstream lease expenditures.

And then if a producer were to take an ownership interest in the midstream, that would be something that we would have to work through. Through regulations, we would have a different point of disposition for the gas and cost deductions for those transportation costs. Thank you. I also see we have with us Representative Mears in the audience. Thank you for joining us.

I've got a question. Representative Josephson. Yes. On this topic, Mr. Stickle, it just strikes me that the state should be as vigilant and guarded as humanly possible about maintaining its production tax receipts and is entitled to do that without reduction. Because why do— if I'm— if my state's going to get $600 million in royalty and tax from the gas line but give up and have that discounted because we haven't sufficiently ringed off deductions that we could fight against, then where am I?

And I guess my question is, is it— could some referee in the abstract say, well, that clearly is an activity related to gas and should not be— is not borne, for example, or is borne by Conoco, but Conoco is receiving its profit from that activity and should not be deductible against oil. Is it possible— I'm not a petroleum engineer— but is it possible to reach some consensus about what is on the list as deductible and what is absolutely not? Representative Kocher-Dossov said so possible, yes. It would be challenging. So obviously there's some activities and expenses that would clearly be oil or gas, there's some that would be unclear.

So if, like, let's say Point Thompson is expanded and an additional well is drilled, that additional well is going to supply gas into the AK LNG project. It's also going to supply oil down taps. We would have to determine whether— how to count that as either an oil or a gas lease expenditure when the well is being drilled prior to it coming into production. That would cause a challenge that we would have to work through in the regulatory environment. If an exploration well is being drilled outside the unit, we would have to come up with regulations to determine is that an ex— are they exploring for oil, are they exploring for gas, or are they exploring for something in between.

So it's a challenge. And it would probably result in increased assessments, audits, litigation. It's a challenge that could be worked through, but it would be challenging. Follow-up? And I assume that there are two countervailing arguments.

One is the challenge should be met now, and another is this isn't relevant directly for some number of years, although I don't know how many that is, and so it can be postponed and this bill can— we can move forward on this bill and leave that for another time.

Is that basically an argument you've heard, those two points of view? Kuchur Josephson, yes, that's true. Another Another point is that if, you know, looking at what is the policy goal, and if the policy goal is to protect state revenue or to generate a certain level of state revenue, there's probably more efficient ways of accomplishing that policy goal. And I think we had talked with the other body about different levers, not making any particular recommendation, but laying out potential options in lieu of oil and gas allocations. Okay, thank you.

Okay, Representative Galvin. Thank you, Co-Chair Foster, through the Chair. One question I have is related to the Phase 1, just better understanding what the gas flow What would— is the expected gas flow? And I say that because I think that what I'm seeing here is 2031, but in another chart, I think it might have been from DNR, the— I think it expressed that the need will come into play especially in 2032. So what is the expected gas flow as— and I'm sure it's a ramp-up, but if you have that already in mind, I'd like to hear that.

Sure. Representative Galvin, through the chair, so we have an assumption of gas flowing starting in 2029 with Phase 1. We have that coming in at 65 billion cubic feet per year. The assumption there is that that is 15 billion cubic feet contributing to in-state demand and 50 billion cubic feet per year from an in-state anchor customer. And that anchor customer could be a reopening of the fertilizer plant, data center, mining operation, something like that.

So that's basically the initial phase 1 demand, and then we have the full export operations. Well, we have export operations beginning in 2031 and ramping up with full operations in 2033. Thank you. And I have one follow-up. And I think this may be for the next phase, and if so, then I don't want to ask it yet, but it's related to the spur line.

You had said something about the cost that all of us who use gas from the rail belt will be paying for it, I think is what I heard. Representative Galvin, through the chair, that is what is in the current version of the bill before the committee, correct? Thank you. And through the chair, I think the last time I heard about an— again, an assumption of what the cost would be for that, I heard from the governor's office it was around $250 million. Is that still what you're working with?

Representative Galvin, through the chair. So we've heard a lot of different numbers. We, for our, for purposes of our modeling, we used $190 million as our modeling assumption, and that was based on the midpoint of a range of $180 to $200 million, which was stated by AGDC, and that was the latest information that we had from them when we built this into the modeling. I know they've In the earlier committee, they submitted a fiscal note that had a little bit higher number, and there's been some other numbers thrown around, but 190 is what we baked into our modeling. Okay.

And so in trying to understand how that would look, one, we're— I assume we would spread that cost out over a long period of time so that there's not a lot of hardship on the consumers. Do you have that modeled out as well as to what that would look like? Representative Galvin, through the chair, so we can provide that. I don't have the detailed number off the top of my head. I think that would be helpful, co-chair, because that's a kind of a significant decision point of this project and because it may have impact —on users, it would just be good for us to know what that would look like.

Thank you. Sure. And just to clarify, Representative Galvin, through the chair, so we had heard from the legislature's consultant, Gaffney Klein, that the spur line spread across the entire project, including exports, would impact the cost of delivered gas by about 2 cents. So pretty minimal for the for the entire project, obviously that's going to be a larger number spread just across the end state, and we will provide that. Thank you.

Co-chair Foster, if I may, so just for clarity, it was 2 cents if it were spread across all users including exports, and now you're remodeling it for just Alaskans, right? Yes, Representative Galvin, co-chair. Great, thanks. Okay, that's all the questions I've got here. Mr. Stickel, please proceed with the presentation.

All right, moving on to slide 25. So we have modeled 3 scenarios for the gas line in the following slides. We've modeled the current law if we retain the existing property tax and left it as is. We've modeled House Bill 381 as introduced by the governor. This was the, the 6-cent-per-1,000-cubic-feet alternative volumetric tax on the entire project with a with an initial ramp-up period.

And then we have modeled the bill before the Committee, the version T Resources Committee substitute. For each of these, we show the impact under our baseline assumptions if the full AKLNG project proceeded under each scenario, which is uncertain.

So Slide 26, this is the first of 3. 3 Similar slides has a little bit of information going on. So the cash flow summary at the top here shows the cumulative revenues to the various stakeholders over 10, 20, and 30 years of full export operations. So we can see that under current law, if the project were to proceed, there would be almost $30 billion of cumulative revenue over the life of project to the state. About $22.6 billion to the federal government and over $17 billion to the municipal governments.

Um, and we show revenues to the upstream and midstream as well. It's important to point out that these are cash flow revenues and not profits. So costs of operation would have to be paid out of these revenues as well.

And then down here on the bottom, we have two, two sets of cost of supply numbers. On the bottom left, we have an in-state breakeven cost of supply, and this represents what would the gas price have to be delivered to utilities in Alaska if the full project went forward and assuming a 10% rate of return to the developer. And so under the current law, in 2033, that would be $4.86 for an in-state breakeven price. To put that in, into additional perspective, there's about $4 and change of distribution costs from the utility to get it to the end user. So this would be looking at an end user price of a little over $9 per 1,000 cubic feet.

On the bottom right, we have a breakeven price for delivered LNG into the market. And again, this would be what price would the LNG have to be in the global market, given our baseline assumptions, for the developer to earn that 10% rate of return. And in 2033, that value is $9.07. To put that into perspective, current futures market prices for delivered LNG in Asia are in the $8 to $9 range. And so that would be on the high end of potentially competitive under current law, which kind of— and under our baseline assumptions for the $46 billion capital cost.

And it's really that number, that $9.07 with some potential upside to it, that represents why a project like this may need some sort of— may need or want some sort of tax relief.

And so slide 27 is the similar slide, which is the bill that the Governor introduced. And if you compare this to slide 26, you'll see that there is a reduction in state revenues of about $7 billion, a very significant reduction in municipal revenues of over $13 billion. And what does that do? Is it reduces the in-state cost of supply, breakeven from $4.86 to utilities down to $4.43. But more importantly, it reduces that breakeven cost into the global market from $9.07 under current law down to $8.48 under the bill as introduced by the governor.

Representative Hannon. Thank you, Coach Foster. So, Mr. Stickell, I guess I'm surprised that the LNG breakeven price under the governor's version of SB 81 only brings it down to $8.48 and What you said is the current Asian sale price is a range of 8 to 9. So it doesn't seem that even under that scenario that the governor introduced, if I'm a buyer in Asia, this, this price doesn't look that attractive. So is it that the supply in Asia isn't going to be there?

And so this provides more security because of the supply? Supply versus the price? Sure. Representative Hanna, through the chair. So I'm not an expert in global LNG markets, but, you know, what we can say is one of the advantages Alaska has is we don't— our gas doesn't have to go through certain choke points.

So there is a supply security advantage to Alaska Gas.

The information around gas futures prices is publicly available. It's the— we look at the Japan-Korea marker. It's a publicly— it's a traded— you can look at it just the way that you could for an oil futures price. And you can see that, yes, even under our baseline assumptions with the bill as introduced by the governor, it's still a challenging price into the global market based on what we're seeing in revenue. Thank you.

Representative Josephson. Thank you, Mr. Stickle. I have a lot of work ahead of me over the next week or 10 days. In particular, I'm curious about slide 27. The, the real difference, of course, with slide 26 is municipal revenues column, and I understand House Bill 2001, formerly called SB 180 would have the state pay municipalities $90 million of a— there are two forms of it, but one form is $90 million of direct impact aid.

Is that right?

So I don't have the new bill in front of me and primarily prepared to speak on 381 today. But yes, one of the elements of the bill introduced by the governor for the special session is some may appropriate language that the legislature may appropriate between $0 and $90 million to community impact that would go through. There's a waterfall of which communities that would go through would be administered by Department of Commerce into grants. Follow-up? Representative Josephson.

In our minds, the putative $600 million in royalty and tax would become 5— if we did what we'd be allowed to do, that would become $510 million, because it would come from general fund revenue. Is that right? Co-chair Josephson, yes, it would be a potential appropriation from the state. I think we're still working through exactly how we plan to present that in this chart, whether it's a state revenue and then a separate appropriation to the municipalities, or whether we show it as municipal revenue directly. But we will be coming— I anticipate we will be coming before the committee in the near future with a presentation on that bill.

Representative Josephson. I assume the existing property and equipment tax written decades ago, was written in some rational way, maybe. I mean, I just see this reduction in cumulative revenue to municipalities of $14 billion, if I'm reading this right.

How does the administration recommend municipalities deal with an influx of vehicles, kids, medical needs. What is the administration's position on dealing with changed communities? That's a great question that you raise. I can't speak on behalf of the administration. Happy to include a follow-up in our long list of follow-ups for the committee that we'll be providing.

Thank you. Representative Stout. Yeah, thank you. Kuchor Justin through the chair. Mr. Stickell, Mr. Stickell, probably a good answer to this.

Why is the municipal take in the resources version above current law? What mechanic in the resources version would trigger that taxation? Cash flow being above the Current law version through the chair. Sure. Representative Stapp through the chair.

So under— this has to do primarily with how the alternative volumetric tax is set up and modeled. So under the bill before the committee, we assume that the property tax would remain in place. For the gas treatment plant and for the LNG facility. Municipalities have the authority under the legislation before the committee to negotiate down that property tax or potentially replace it with a negotiated equity share. For modeling purposes, we've assumed that the property tax will remain or that some arrangement with a similar municipal revenue will be put into place.

When we're modeling out property tax for the pipeline itself, we assume that property tax will be stable over time in nominal terms. That's a modeling assumption. We assume that inflation and depreciation will roughly cancel out over time. When that's replaced with an alternative volumetric tax, we actually see, um, that there's an inflation adjustment built into that alternative volumetric tax. So the alternative volumetric tax actually increases over time.

And then with some of the revenue sharing provisions in the bill, there's actually a little bit of a shift away from the state component as well. Okay, that makes sense.

Thanks, Kutr. Okay, please continue.

All right, in slide 28, I think we started talking about this slide a little bit. This is the similar summary of cash flows and cost of supply under the version of the bill before the committee, which is the resources version. And as, as was noted, it's a reduction over life of project, a reduction to state revenues, a significant reduction to state revenues, actually an increase to municipal revenues. That has to do with, as I was mentioning, some of the mechanics of the, of the alternative volumetric tax and inflation over time. There's additionally some additional community payments, I believe, that are in this version of the bill.

But as far as the project economics go, again, zeroing in on those cost of supply numbers, so for— compared to current law, for the in-state breakeven price, it's a reduction of $4— from $4.86 down to $4.76 per 1,000 cubic feet. And then for the delivered break-even price into the global market. It's a reduction from $9.07 under current law down to $8.96 per 1,000 cubic feet under the bill before the committee. So a modest tax reduction from current law, but not nearly as significant of a tax cut as under the governor's proposal.

If I might— Representative Josephson. Mr. Stuckley, you said version T, slide 28, was a reduction of state revenue? Compared to current law, Mr. Co-chair, yes. But more than the Governor's proposal?

Co-chair Josephson, so to just clarify that statement, version T before the committee is a reduction to state revenue compared to current law under our modeling. It is a much smaller reduction than under the Governor's Governor's proposal.

Okay. So again, comparing slides 26, 27, and 28, cumulative through 2062 under our baseline assumptions, under current law we show $29.7 billion of cumulative state revenue. Under the bill introduced by the Governor, we show $22.5 billion, and under the version before the committee, we show $25. $1.1 Billion of cumulative state revenue. Please.

Oh, we've got a question. Representative Tomaszewski. Thank you, Co-Chair Foster. So cumulative to 2042, where are you starting? What's your start date?

Assumption? Yeah. Representative Tomaszewski through the Chair. So this— we're assuming starting this year. And so what these numbers through 2042, '52, and '62 represent is they represent 10, 20, and 30 years of full export operations.

So we're including the investment cost, the period of Phase 1, the ramp-up, and then 10 years of full export operations through '42. Follow-up? Follow-up? But export not starting until '32, hence the 62, 30-year calculation. So, Representative Tomaszewski, through the chair, so we assume In-state gas starts flowing in 2029.

We assume exports begin in 2031, and we're modeling out a 3-train— basically a 3-train scenario where exports begin in 2031, ramp up in 2032, and then the full 3.5 billion cubic feet per day end of the project in 2033. And so that 2042 represents the 10 years of the full export operations from 2033 through 2042. Okay, just one follow-up. Follow-up. And so if we don't build a gas line, what's the revenue in 2062?

Representative Tomaszewski through the chair. So I don't— we don't have an official revenue forecast. What we do for modeling purposes is we have an extrapolation that we do based on our official revenue forecast. No, I'm sorry, follow-up. Mine was if we didn't build a gas line, the revenue would be zero.

Representative Tomaszewski, through the chair, the revenue from the gas line project would be zero without a gas line project. Thank you. That's correct. Thank you. Okay, please continue.

Alright, and so the next set of slides depict annual revenues to the state, and this is just the state portion, not, not including the municipal portion related to AKLNG as well as related upstream development. So this includes both the direct revenues from the midstream as well as any incremental revenues from the upstream, from producing gas and related oil. And so we show this over the time horizon from current through 2062 under the three different tax systems, with slide 29 being our current law scenario if the project were to proceed under, under current law. As we've discussed, there would be 2 years of net negative revenues to the state in 2029 and 2030. And what that represents is when we assume upstream producers would be making significant capital investments in new production and facilities to contribute gas into the project.

And that would have a negative impact on our production tax and to a lesser extent, our corporate income tax. But as soon as exports begin in 2031, we would show this as a net positive to the state. And once full exports begin, we're looking at about $1 billion per year of revenue to the state across production tax, royalties, corporate tax, and state property tax. Again, this doesn't include the municipal portion. One question that, that you might ask looking at this chart is what's going on in 2038.

And what's going on there is we are assuming in our modeling that development at Point Thompson in particular would come in two phases, that there would be a significant additional investment in the near term as well as a second round of investment. And we've put that in 2038 for modeling purposes, about a decade out, that they'd come back and do some additional facilities and wells. Got two questions. Representative Bynum, then Galvin. Representative Bynum.

Thank you, Co-Chair Foster. Through the Chair, Mr. Stickell, thank you for being here again. Pretty exciting that we're back to work on this. So I'm looking forward to getting a bill done and out the door, seeing a gas line bill. And when we look at all these numbers, we're making the assumption that we put corporate income tax here.

We're making the assumption that this is being paid at the current corporate income tax rate of 9.4.

Representative Bynum, through the chair, our modeling assumes under current law a maximum marginal corporate income tax rate of the 9.4%. We assume that about two-thirds of the upstream producers will be subject to that corporate income tax, and we assume for modeling purposes that the midstream developer will not be paying corporate income tax. Thank you. Representative Stapp. Yeah, thank you, Commissioner Foster, to the chair, to Mr. Stickrell.

Just a question on the midstream developer. Does that change if there are other ownership interests in the midstream project itself and if they're C corps? Representative Stapp, through the chair, yes. So if, if there are C corp owners on the midstream, they would be subject to our corporate income tax. Thanks.

Please continue.

All right, slide 30 is the similar chart under House Bill 381 as introduced by the governor. And so the overall shape of this chart looks very similar, with a couple years of net negative revenues to the state during the upstream development period, followed by significant positive revenues to to the state, and we see those leveling off at around $800 million per year with the version of the bill as introduced, compared to about $1 billion per year under the current law scenario. And again, this is reflective of just the state revenue portion, where the most significant reduction in revenues under the bill as introduced to the municipalities.

And then slide 31 is the similar chart under the Version T House Resources Committee substitute.

Again, it is a fairly similar shape of the chart. You can see that property tax and alternative volumetric tax number in the bottom blue purplish bar is a little bit higher than under the as introduced. There's also a significantly higher portion to the municipalities, but we end up with kind of similar to this $800 million-ish per year revenue to the state once exports begin. One thing that was included in the House Resources version that wasn't included in the the governor's original proposal is this sunset. So you can see in 2056, we actually show the sunset to the alternative volumetric tax and a reversion to the property tax that we have under current law.

Question, Representative Galvin. Thank you, Co-Chair Foster, through the chair. So in looking at 30 and 31 here on the left side, it looks like we will be incurring costs, I guess, or lower UGF. And I can't tell exactly what number, but it looks like maybe around $100 million-ish. Is that what I'm seeing each year?

Yes. Representative Galvin, through the chair. Okay. And then there— I would assume we would still be in the build phase potentially in some of that. So there would be still the Transportation and DC and DNR somehow doing work to help make this happen.

So there would be additional costs during this phase. Yes. And I guess I'm trying to— if that was— that also considered, or was it just revenue and no other you know, I guess what we would call multiplier effect of loss. Right. Representative Galvin, through the chair.

Yes, you're correct. I mean, there's, there's obviously going to be costs to the state to support the gas pipeline and the buildout, as well as cost to the municipalities. I think there's been testimony in the Resources Committee from, from the mayors in particular around potential municipal costs. That is not something that we've built into our modeling. Follow up.

Follow up. Have you done any building of that, though, knowing that you've heard from municipalities and I'm sure the state is wrestling with or should be thinking about the same sort of considerations? Has there been any modeling of that just so that we could have a sense of what that nominal cost might be and be prepared for that? Representative Galvin, through the chair, that's not something that we've looked at in detail from Department of Revenue's standpoint. That might be something worth having AGDC weigh in on.

Okay, thank you. Please continue.

So moving on to slide 32. So we have a couple of breakeven matrices here. There's a lot of stuff on this slide, so I'll try to walk through it. Slide 32 and 33 are very similar in nature. Slide 32 presents a sensitivity analysis for breakeven prices for the in-state gas delivered to utilities.

And then slide 33 presents a similar sensitivity analysis for the delivered LNG prices into the global market. And what we've done here is for each of these charts, we've taken our— two of what we view as the most uncertain assumptions around the project, and we could certainly prepare similar matrices for additional assumptions. But two of the more uncertain assumptions are what will the price of gas negotiated between the developer and the upstream producers be? And we've assumed a $1.50 per 1,000 cubic feet price? And we show a range here as low as $1 and as high as $5.

And then what is the capital cost of the project? As we all know, that, that cost has not been released publicly. There's been speculation that the capital cost is higher than the $46.2 billion that we've modeled. And so what we've done here is we've started with our base CAPEX, which is the $46.2 $6.2 billion assumption, and we've modeled out up to a 100% higher cost. We've heard from AGDC and Glenfarm that that 100% is probably too high, but so this gives a range that we're pretty confident that the capital cost is within this range.

And so you can see, looking at our $1.50 purchase price and the base capital cost, that under current law, we show the $4.86 per thousand cubic feet breakeven price for delivered in-state, and that that reduced to the $4.43 under the version introduced by the Governor, and $4.76 under the version before the committee. But this allows users to see if capital costs were higher than we're modeling, and if if the gas purchase price were a little bit lower or higher than what we're modeling, what would that delivered price of gas have to be for the developer to earn their assumed 10% rate of return? Representative Stapp. Yeah, thank you, good day, Mr. Chair, to Mr. Sickel.

So I guess, you know, fundamental question here is going to be how does this compare to the cost of LNG imports if the state were to move down that Around.

Sure. Representative Stapp, through the chair, and to, to reiterate, this is the in-state breakeven assuming the full project goes forward. We did do some analysis. So what we did to look at LNG imports is we looked at a report that was done by a consultant see, called BRG for NSTAR a couple of years ago, and they did an analysis of various import options, and we inflated their cost up to $20, $33 for comparison purposes, and that came to about a $17 per 1,000 cubic feet price for imports. And so you can see under all of these scenarios, assuming the full project goes forward, the price would be well below the price of imported gas.

Yeah. Follow-up, Mr. Co-chair? Follow-up? Yeah. I just kind of want to have the committee really consider that model number on LNG imports.

It's obviously— that'd be a catastrophic, I think, price for the state to pay. So my hope is we'll try to go through this bill and deliver it as close as we can to the requests of the developer, because I would hate to see Alaskans pay triple the price of gas that's currently available in this bill. Through the chair. Thanks. Representative Galbraith, you referred to—.

I think it was something from Enstar. I— if the— if that's available, I think that would be a great thing for us to have to be able to show public kind of why and how the rest of these numbers compare. Sure. Representative Galdman, through the chair. So it was, it was an analysis that was done by BRG for, for NCSTAR.

It's available on the NCSTAR website. It was published in June 2023, and we'd be happy to provide the direct reference to the committee for that. Obviously, it's, you know, that would— June 2023 was almost 3 years ago, probably be 3 years ago by time we're done with this. But it kind of gives a— it gives kind of an order of magnitude of what imports might look like. Thank you.

Representative Josephson.

Mr. Stickel, apologies for something so elementary, but When we talk about the price of import, there's still gas production in Cook Inlet. Why can't it be 75% of our requirements and we're importing 25%? Does this relate to the Hilcorp commitments moving forward or what's the issue there? Sure. Co-chair Josephson.

So what we look at purposes of modeling for this bill is we used a gas supply study that was put together by DNR.

I understand they've come out with a newer version of that since we built out the modeling, but we looked at their gas supply study to understand, given the current outlook for Cook Inlet production, what is the market shortfall? And we assumed that in-state gas supply from the AK LNG line would, would not displace Cook Inlet production, but would rather fill in for that expected shortfall. And so that's why we had 15 billion cubic feet per year as the initial in-state volume, which compares to about 70 billion cubic feet per year of total Cook Inlet use.

Follow-up. Representative Justus. I was talking about imports. I understand that $17 is a high price. I don't think it's triple.

It's often double of what you're showing here. But it wouldn't be the entire subscription of what's needed. It would be a part of it vis-à-vis what we're producing now, right? Yeah, sure. Coach Josephson, certainly.

And there's obviously a calculus of how do you spread the cost of an import terminal That's not something I'm intimately familiar with, but in concept, yes, if you had higher-cost import gas, it would certainly make sense for that to also fill in with the shortfall of Cook Inlet gas instead of displacing Cook Inlet production. Okay, thank you. Please continue.

All right, so moving on to slide 33, and I think this is really the the key slide as far as these matrices go. And this is the sensitivity analysis for the LNG breakeven price into the global market. We talked earlier that futures market prices indicate something in that $8 to $9 range. And so you can see that the project is challenged for these prices. Is, generally speaking.

But we can look at what, given our baseline assumptions of the $46.2 billion capital cost and the $1.50 per 1,000 cubic feet purchase price, we have that $9.07 break-even price under current law, the $8.48 under the governor's version of the bill, and the $8.96 per 1,000 cubic feet under the version before the committee. And we could look at what would those breakeven prices be with the different gas purchase prices at the upstream and then with different capital costs.

Representative Skapp. Thank you. Through the— or Co-Chair Foster, through the Chair to Mr. Stickel. So what we are looking at is a project that is very challenging economically. It's a very complicated project, very expensive project.

And even under— I mean, under— even as the bill introduced, we're still on the margin of being able to be competitive by your modeling in a very tight window. And, you know, I just think that there's a lot of reasons here why we would want to ensure that we would forego as much desire of folks on the committee of state and local taxes on the project, because the alternative would be clearly by your tables that the project economics would almost certainly not work if you increase the state take. Is that fair through the chair? Representative Staab, through the chair, so obviously we don't know the true values of this purchase price or capital cost, but Directionally speaking, yes, I would agree that the project is challenged. Follow-up, Mr.

Co-Chair? I guess I would say, obviously, you can't have a future ball and determine the price of Asian LNG market 10 years from now. I know the futures market does the best they can. But again, even under the governor's proposal, this is a very narrow window looking at the potential probable scenarios. And I just would hate to see a desire for big increases in taxes on a project that is already challenged.

That would wind us paying $17 for LNG imports and having the folks in Alaska have to pay for capital costs of an import terminal. Thanks. Representative Josephson. Yes, Mr. Stickle, have you done similar price heat maps for a scenario where we're just talking about Phase 1 pipeline for in-state demand?

Rep. Kocher-Josephson, yes, we have. We haven't produced those for this particular version of the bill. We did provide some in the Resources Committee in the other body. On April 27th to 29th, and we would be happy to provide similar, similar charts for this version of the bill. And yes, they do show that under a phase 1 only scenario, the in-state breakeven prices would be higher.

I would be happy to come back with Yes, I would like that. But you're referring me to April 27th through the 29th documents and basis essentially? Representative Josephson, through the Chair, correct. So it was a presentation that we delivered in the Senate Resources Committee. It was a response to hearings from April 13th and 14th.

I believe it was dated either April 27th or 29th. And basically what we showed there is we looked at current law and as introduced by the Governor, and those showed a weighted average price under current law of $14.55 in our Phase 1 only scenario, which would reduce down to $12.45 under the version introduced by the Governor. And then we were asked by that committee to do a further analysis that broke out just the price to utilities. Um, when we do our Phase 1 only analysis, that is predicated on the assumption of a baseload customer. We assume that that baseload customer would pay a price of $6 per thousand cubic feet, and that lower price is basically required to make the baseload industrial demand economic.

Um, and when you weight that out against a utility price, we came up with a baseline cost of supply to utilities of $22.70 under our current law scenario and $18.60 under our as introduced by the Governor scenario. Those would be higher than the price of imported gas. And what that really highlights is that the true benefit of this project comes from the the full project that includes the export sales.

Okay. That's an important point. Thank you. Representative Tomaszewski. Thank you, Co-Chair Foster.

Through the chair, Mr. Stickle, thank you for being here again. So have you calculated out the impact on the economy of the state of Alaska of sending our dollars out of the state to purchase gas versus what we would be getting in the opposite direction of us taking our gas and getting dollars from out of the state into the state. Have you calculated anything like that? What is the cost of that for the state of Alaska, for the economy, for the citizens? Sure.

Representative Tomaszewski, through the chair. So we haven't attempted to quantify that. Qualitatively, yes, you're correct. Absolutely. Having the dollars circulate within the Alaska economy would be more beneficial than sending those outside.

Thank you. Please continue. Oh, I'm sorry. Representative Galvin. Thank you.

So there's a— some sort of a gap between phase 1 and phase 2, and I think you have this in here, but I'm just— it would be helpful if you would show me the difference in price when we haven't gotten to that Phase 2 volume yet. There— because it sounds like all of our opportunity is really once we get to Phase 2 with regard to low-cost energy to Alaska. And, and so I guess 34 sort of does it, but it looks like it doesn't cover what Phase 1 is. And that I think this is modeling after Phase 2. So I'm trying to understand that piece of the puzzle.

Sure. Representative Galvin, through the chair. So if we have the full project, and we have a situation where Phase 1 comes online for, as we've modeled, for 2 years, and then Phase 2 starts and ramps up over time, there's 2 ways that that could be handled. One would be to average the operational cost and charge within a given year and charge a higher rate initially to in-state consumers, and then have that rate come down as the full project comes online. That is one option, that we could start paying the higher rates and then those would come down once exports begin.

Another option is that the developer would negotiate with utilities and charge a rate that's averaged over life of project. And so that's what we assume for purposes of our modeling, is that once— the gas flows in Phase 1 in 2029, that there's already been an FID for Phase 2, and that the in-state residents will benefit from lower rates as soon as gas flows. And we've been told by AGDC and Glenfarm that that is an assumption and not an unreasonable one. If instead we started with higher rates, we'd actually end up with even lower rates once exports begin.

Thank you. Co-chair Foster, if I may, so what I'm hearing is the assumption that's being made is that there will be Phase 2, and so you've modeled that out, and if— and also the assumption is there's two options. One is the high— just a high rate in the beginning to help start paying it off. And then the other one was that there's some sort of an agreement that there will be buyers internationally who will help over the long run bring down or allow for a spread of incrementally raising the price as opposed to all— a giant one at first. And again, I'm just talking about this middle part where we're not at Phase 2 yet, but you're saying that there's likelihood of there being buyers for the other international buy, but we don't have certainty of that yet, but your hope— our hope would be that it would come into play before the prices go up.

Is that right? Representative Galvin, through the chair, certainly the hope is that there would be buyers and phase 2 would receive an FID. We, for our modeling purposes, we have assumed that there will be a levelized cost to Alaskans, so they'll pay in real terms, that will be a set cost of gas over the 20-year period of the initial recoup of investment. Okay, and I have one last one. Representative Gelman.

Have you modeled at all if, let's say, a region— in this case it's Fairbanks that wants a spur line, but there's been talk of other spur lines. Have you modeled having that those buyers purchase that spur line? Has that come up at all? Representative Galvin, through the chair, we haven't directly modeled that. My understanding is that if the cost of the spur line were borne entirely by Fairbanks consumers, that that would be a prohibit— prohibitive cost.

Okay. There are options. There are alternative options for energy and gas into Fairbanks. And so that's part of the reason why the House Resources version of the bill put in a series of requirements around the spur line. And also one of those was the sharing of that cost across all in-state consumers.

Okay. Thank you. Okay. Please continue. Did you have— Representative Tomaszewski.

Yeah, thank you, Co-chair Foster. So on this slide here, I'm just looking at the $1.50 upstream gas price. Current law at 100% is $7.74. HB 381, the gas— the governor's bill is $6.86, and I know that reduced it to a 6-cent volumetric tax. And now in the current version, we're at $7.37, so we're getting close back to current law, if the governor reduced it to 6 cents, I know the— it's at 15 cents in the current version.

What other provisions are factors in raising that price back up to the— close to the current law tax matrix? So we're looking at slide 32 in the 100% capital cost increase scenario. Is that— Yes. That's correct. Yeah, so one of the— I mean, one of the key differences here is the property tax, just the difference between the property tax and then the alternative volumetric tax.

So when we are modeling out property tax and property tax impacts, we assume that that is a function of the capital cost. And so if we have a 100% higher assumed project cost, then we will assume that there would be a 100% higher property tax in the current law scenario. The resources version of the bill retains property tax. For the treatment plant and LNG facility subject to municipal election, whereas the bill as introduced by the governor replaces that with an alternative volumetric tax. And that alternative volumetric tax under the version introduced by the governor, that would be $0.06 with a $46 billion capital cost.

That would be $0.06 with a $100 billion capital cost. And so kind of locking in that tax reduction has a more significant impact with a higher capital cost. Can I follow up? Follow up? And basically gives more stability and more finance— financial ability to finance the project, basically.

Gives stability to those who want to— contribute to this project. Yes, Representative Tomaszewski, through the Chair. So regardless of the exact rate on the alternative volumetric tax, going to that mechanism has a— it significantly de-risks the project. And I think the next couple of slides actually provide a little bit more light on that. That.

Thank you. Representative Gelvin.

I'm just trying to make sure that it's not getting covered in the next couple of slides and I don't think it's here. So I'm going to ask— this is a general question that's come up to me quite a few times. It's related to whether or not we can soften the blow, if you will, of the cost because the RCA has control of that. Do they have the authority to be able to do that? If they look at agreements, I suppose, and know that there's going to be the proper amount of flow and we have the customers worldwide down the road, can they make the decision to— or do they have the authority to average rates, you know, over an assumed project life?

With theoretical customers, if you will. Sure. So, Rep. Galvin, through the chair, so my understanding is this would not be an RCA rate set or regulated pipeline project. This would be a FERC-regulated project. FERC, okay.

And so the rates that would be negotiated between the developer and the utilities.

Thank you. Okay. And please continue.

All right, we've got— so slide 34, we have two sets of tornado charts. These are very similar charts, and they look at the, uh, the impact of some key variables on cost of supply. Given that the charts are so similar, what I think I'll do is focus on slide 35, which is the delivered cost of LNG into the global market. And so what we have done here is we have taken our baseline cost of supply under the current law of property tax, which was— that was the $9.07 per 1,000 cubic feet, and we looked at how some key mechanics would impact that delivered cost into the global market. And so first we look at property tax under two different scenarios.

So the first being the reduction in property tax as introduced by the governor, and you can see that would reduce the, the breakeven cost of supply significantly to under $8.50. And then we look at the version of the bill before the committee that would have a more modest reduction in cost of supply Next, we look at the impact of a capital— of a change in capital expenditure. And so the capital expenditure, what does this project cost? That is a really key question, and it is extremely material for the economics of the project. We have assumed the $46.2 billion.

If that were to be a lower cost of —of capital, that would have a 10% reduction in that capital cost, would have an impact on the project similar to the governor's version of the legislation. But then we also look at the potential for a higher capital cost. For purposes of this chart, we showed the 50% higher capital cost, and you can see that a higher-than-modeled capital cost quickly has a very large impact on the economics here. We look at rate of return. So we've modeled a 10% pretax rate of return.

We look at if a lower rate of return would be acceptable to the developer or if they were targeting a higher rate of return. We've heard some testimony that maybe something closer to the 12% rate of return would be something that might be targeted for a project like this. We look at if a higher or lower gas cost, being the gas purchase price from the upstream producers, were negotiated. And again, you see a low— if gas were negotiated for $1 instead of $1.50, that would have an impact on our modeling actually a little bit more than a 10% reduction in capital cost or the property tax relief. And then finally, cost of debt.

We've modeled out a 5% assumed cost of debt, and a higher or lower cost of debt would also be a material impact on the project. And we can produce charts like this for any of the various variables in our modeling, but just wanted to kind of highlight these as some of the key uncertainties.

Representative Stapp. Thank you, Chair Foster. To the chair, um, to Mr. Stickel. All right, so if I just evaporated all state take on this thing and local take, at what point would the CAPEX overruns basically make that sell price undesirable for a consumer base? Through the chair.

Sure, Representative Representative Stapp, through the Chair, want to clarify the question in terms of consumer base? Yeah, yeah, it's my fault, Mr. Co-chair. Representative Stapp. Yeah, so let's say I just put zero total tax abatement on every aspect of this project. At what point do the CAPEX cost overruns alone kind of dwarf the ability to be able to be economic at the sale price?

Sure, and Representative Stapp, through the Chair, we would be happy to run an analysis looking at zero state take. To clarify, if we would run that with zero state take just from the midstream or also from the upstream? Follow-up, Mr. Co-Chair. Representative Stepp. I don't really think I need you to run a model like that.

I'm just curious, because at some point, you know, that CapEx costs at all aspects kind of Hear us a lot, but appreciate the offer though. Yeah, and sure, and so Representative Sapp, through the chair, so again, if you refer back to slide 28 under our baseline modeling, we assume $25 billion of state revenue over life of project. Clearly transferring $25 billion, that's under the The House Resources version of the bill clearly transferring an additional $25 billion across the table to the operator would significantly improve their economics. Okay, please continue. All right, slide 36 is a conclusion slide for, for this part of the presentation.

So Alaska LNG has the potential to provide tens of billions of dollars for the state of Alaska, the federal government and local governments, public and private sector. And beyond just those direct financial benefits that we've, that we've modeled would be an enhancement to energy security for both Alaska and the nation, significant job creation and economic development. The bill, as introduced by the governor, would be a material increase to the cost of gas. And would definitely make the project more attractive to investors. The version of the bill before the committee is a tax decrease overall, but to a much smaller extent than the bill as introduced by the governor, both by having a higher alternative volumetric tax rate for the pipeline and then by essentially carving out the, the treatment plant in the LNG facility and subjecting those to municipal election.

And so that is the final slide that I had for this part of the presentation. We also have an appendix presentation that was based on some additional requests of the committee, if we would like to go through that or leave that with the committee for further review. The appendix. Thanks. I see you do have another, but I don't think this is what you are referring to, the version, resource version, the Appendix 1.

Can you point that out? Sure. Co-chair Foster, so we have an appendix. It should be dated May 12th, and it has 9 slides, and this was a response to a supplemental request that we had from committee in addition to the main slide deck. Coach Froster, I believe you did have that in your hand just a second ago.

It looks identical to the presentation we just went over. It's just a thinner packet. I think that if you turn that first page, I think it'll say appendix. That should be it there. Perfect.

Okay, thank you. Does everybody have that? I'll find it. It's outside of step. Did you have a question?

Yeah, I think, Coach Froster, I just wanted to maybe have Mr. Stickler go go back really briefly to his last slide and his conclusion sections. And again, kind of what is before us, just so the public is aware, is basically your conclusion to the Chair, Mr. Stickel, in the current version of the bill in front of us, that does not materially decrease the cost of gas or make the project more attractive to the investors. Right? That is what I see up on the slide. That is this resources version.

And obviously the whole point of this process is to make the project more attractive to investors so we could have a project. So I just want to put that on the record, and then you can agree if you're not, but I'm sure you do because it's your conclusion through the chair. Yeah, Representative Stapp, through the chair. So the version T is a much smaller tax cut, and then that final bullet point is kind of the One of the cruxes of that is that we have carved out two of the major components and left significant benefits with the North Slope Borough and the Kenai Peninsula Borough and basically allowed them under this version of the bill the authority to negotiate what to do with those components.

Okay. And yes, Mr. Stickle, so I do see you have got the House presentation slide deck, House Bill 381, House Resources, CSB. Version T, and then the second page shows Appendix. If you would like to walk us through that. I would be happy to, Mr.

Chair. May need to have assistance with getting that set up on the screen here. Okay. Let's see. I think that might just— we will take briefings.

Okay, House of Finance back on record. The time is currently 3:08 PM on Thursday, May 21st, 2026, and we are now on an appendix presentation. Uh, Mr. Stickle. All right. Again, for the record, Dan Stickle, Chief Economist with Department of Revenue.

And so this was provided as a separate committee document. It is basically 6 slides of content. Slide 3 is the additional requests that we had from the committee to address as part of this presentation.

And so this just lays out the requests and I will walk through each of these in turn. So slide 4 provides a visual breakout of state and local revenue. And what we looked at is the revenue in 2033 once full export operations begin. So total state revenue would be $781 million, and total local revenue would be $583 million. These are under the version 3 version of the bill in front of the committee.

And the chart here shows how that breaks out for the different components. So for the state, the production tax and royalty being the primary components. And then for the municipalities, the alternative volumetric tax on the pipeline as well as the remaining property tax on the treatment plant. As well as the LNG facility being the primary components. This is version T. Representative Galvin, just to double-check, this is version T, correct, Mr.

Stickel? Mr. Chair, correct. All of these slides assume the version T Resources Committee substitute except where the request includes changing a provision of the bill. Thank you.

Representative Galvin? Thank you. Assumption I'm, I'm questioning is that what, what, what volume are you assuming at 2033? Representative Galvin, through the chair. So in 2033, we chose because it's the first year of full project exports and capacity.

So we're assuming 3.5 billion cubic feet of gas into the gas treatment plant and about 3.1 billion cubic feet of export. Ports. Okay. And 3.5 billion. So we're assuming that that would be the demand in Alaska at that time.

Representative Galvin, through the chair, so 3.5 billion cubic feet per day into the project. So this represents once the project is supplying both in-state, but then the full level of exports. Okay, thank you. And so we chose this because this is the first year where the full project is really fully going at the full capacity and what is the revenues to state and local look like at that point in time. Thank you.

Slide 5 is another pie chart. We were asked to do an allocation another allocation here. And so this shows the property tax and AVT by municipalities. And so what we've done here is we've shown how that breaks out. Again, in 2033, the largest source of property tax and AVT revenue would go to the North Slope Borough.

For the gas treatment plant at a little over 40%, and then the second largest would go to the Kenai Peninsula Borough for the LNG plant.

And again, the reason for that is that this bill carves out the property tax for gas treatment plant and LNG plant, and we assume that those would pay the current law property tax. And then the alternative volumetric tax for the pipeline is shared between the state and several municipalities.

Slide 6, we were asked to model the impact of different alternative volumetric tax rates for the pipeline. Under the T version of the bill and look at what that would do in terms of impact of cost of supply. And so we've modeled a range of rates. The bill in front of you has the 15 cents rate. We provide a range from 1 cent up to 30 cents for the alternative volumetric tax, assuming all other provisions of of the bill, including the inflation adjustment provisions, and then we compare those to current law.

And so with a price of somewhere between the $0.20 and $0.30 per 1,000 cubic feet AVT, the AVT would actually be a higher cost of supply than current law. And obviously reducing the AVT below the— what's in the bill would have a reduction to the cost of supply.

Slide 7, we were asked to analyze the relationship between upstream gas price and state revenues. And so what we've done for this is we've presented a sensitivity matrix similar to the matrices that I presented earlier. But in this case, we're looking at the project capital cost and the upstream gas price and how that relates to cumulative state revenues over life of project. And we— and again, this assumes that the full AK LNG project goes forward under any of these tax regimes. And what we see here is obviously higher state revenues with higher gas prices because that would increase production tax and royalty from the upstream.

Under current law, we see higher state revenues with higher project capital costs because that would, we assume, increase the property tax burden. Under the bill as introduced by the Governor, higher capital costs would not have an impact on state revenues, and that's because the alternative volumetric tax basically locks in that exposure to tax for the midstream.

And so that's one of the key benefits in terms of de-risking to the midstream developer from having an ABT. And then we compare to the version before the committee, which has a combination of the two, retains some— property tax, but then also the AVT for the midstream. Under the current law, or under the version T before the committee, the only portion of the revenue that would go to the state for property tax or AVT would be that midstream component for the pipeline. But there is a sunset date in the version before the committee. Even if the AVT is fixed through 2056, there would be that sunset and the current law property tax would return in the later years.

So there is some impact on state revenue from a higher capital cost under the T version of this matrix.

Representative Josephson. On slide 6, the MCF price, or rather MCF unit AVT rate, it just looks like when you move from 6 cents to 15 cents, it's nothing. But it's that delta becomes significant over the life of the plan and multiplied into the greater units. And— but just in this single MCF, it's not material, is it?

Representative Josephson, through the chair, I think in terms of project economics, I think an 11 or 12 cent per MCF would be material. But as you mentioned, like, the impact is multiplied over time by having 11 or 12 cents per 1,000 cubic feet when you're putting 3.5 billion cubic feet into a project every day, that becomes material pretty quickly. Thank you. Okay, Representative Tomaszewski. Thank you, Co-Chair Foster.

While we're still on this slide, I thought it was my understanding that the 6 cents was equivalent to 2 mil. Property tax, but in current law is in this slide here, the current law is at the 20 mil tax. So I'm curious if why is, I guess it's the 30 cent mil, why is that higher than the current law if 6 cents is equal? Equal to 2 mils. What is— what is—.

What have I got wrong here? Sure. Representative Tomaszewski, through the chair. So 6 cents per 1,000 cubic feet is roughly equivalent to a 2 mil tax for the entire project. What version T does is it applies the AVT only to the pipeline.

And retains current law property tax for the gas treatment plant and LNG facility subject to municipal elections. Okay, thank you. Representative Skow. Thank you, Co-Chair Foster. Through the chair to Mr. Stickell, I'm just curious, you know, what if you were to just instead of the property millage.

I guess the biggest concern I have is cost overruns on the project and that property being subjected to higher taxation because it's a cost-based tax, basically stacking on a cost-based overrun, right? So if you were to structure something differently where you talk about municipalities and their ability to be engaged in the project, what if you just did it strictly on their volumetric sense instead to kind of mitigate that risk in the project? Through the chair, would that change the underlying dynamics here in terms of this end-user price? Through the chair.

Representative Stapp, through the chair, so if I understand the question correctly, it would be if we simply converted the current law property tax into an equivalent ABT? Through the chair to Mr. Stickel, yeah, basically. If you just were— if you just did equivalency shift volumetric, basically. And that would eliminate the issue of the cost-based stacking on the cost overrun. Through the Chair.

Sure. Representative Staab, through the Chair. So that would certainly be an option. It would de-risk to the developer some of the impacts of potentially having a cost overrun. It would also de-risk the potential for— higher assessments in the future and, you know, the potential that there could be disputes and litigation around that.

I imagine the developer would say that an equivalent AVT would still be challenging to the project and I think our modeling would support that as well. Okay. Thanks. Questions? Representative Josussen.

Yes, following up on a conversation you had with Representative Galvin perhaps an hour ago, what is your understanding of the RCA's role on limiting customer exposure during price— cost-by-price cost overruns? And more broadly, what is the RCA's role to regulate price in this project? Sure. Co-chair Joseph Senso So my understanding is that the pipeline itself is a FERC-regulated pipeline and that the RCA would not have a role in the negotiations between the developer and the purchasers of the gas, whether those are global LNG purchases, in-state utilities, or in-state anchor customers, and that RCA's role would be regulating the distribution infrastructure as they do currently. And so, InStar currently has— InStar, for example, they have a fairly straightforward process for determining the rates to customers.

They have a gas supply cost that is passed on to customers without any markup, and then they have a cost of distribution, which is their cost of operating infrastructure, and that, that distribution earns a regulated return, and that's regulated by RCA. And so my understanding of how this would work is that that gas purchase price would continue to be passed on to customers, and that the regulation would continue to be around the distribution infrastructure.

Okay.

So we had a debate on the floor a couple days ago about whether the pipe portion, Phase 1, would be $10 billion or $16 billion. You may have— it may be your job to watch us. I don't know. I hope it is. And so that sort of delta is not something where the RCA can intervene and say, "Yeah, we are required by statute to protect the customer from that extra $6 billion." It doesn't work that way.

Uh, Commissioner Josephson, that is my understanding. I am getting a little bit out beyond my skis in terms of RCA regulation. I know they have come before committee in the other body. So that might be a good question to kind of bring them before the committee as part of this process to understand exactly where their authority begins and ends. Sounds like it.

Thank you. Representative Hannon. Thank you, Chair Foster. Following up on what Rep. Josephson was asking Mr. Stickell, I guess I was interpreting what you were saying as FERC regulates pipeline, but if that's a cost of the gas line to NSTAR, their end user, NSTAR has to prove the rate case that that cost is an authorized cost to pay on to the ratepayers. But it's NSTAR as the buyer of it.

And so if there's cost overrun and NSTAR's contract for gas from Glenn Farn goes up, then Enstar has to prove the case, and that that's where the RCA regulation is, versus directly on Glenn Farn as the producer, or as the developer. Is that—.

Yeah, yeah, Representative Mahannon, through the chair, so I think that's correct, is my understanding, is Enstar will come before RCA, and they'll say, here are all of our costs. The gas purchase price itself simply gets passed on. And then the piece that the RCA will engage in is, you know, is that the correct gas purchase price? But then the cost of the distribution and infrastructure where Instar earns a rate of return, again, that's my understanding. I would encourage the committee to talk to, get it straight from the, from the horse's mouth, right?

Invite RCA. Yeah, I mean, and then we don't want to subject the Department of Revenue to the pettiness of our debate sometimes when we simplify things. But it's not that the RCA doesn't have a role in regulating Glenfarm and the developer of it. It's that The RCA regulates the consumer cost via NSTAR or whoever the purchaser of it is, seller to consumers. That's where they have to prove the case and may or may not, depending on their contracts for price, whether cost overruns are allowable or not is up to NSTAR's contract with the developer.

Right? I guess those are legal questions.

Please continue.

All right. I believe we were ready to go on to slide 8, and this is the last piece of the request for the supplemental analysis from the committee. We were asked what the capital contributions from the state would be at different levels of equity investment. And so that's what slide 8 shows here. This is based on a 70/30 debt-to-equity structure, which is what we're modeling in our base case.

We are assuming that $46.2 billion real capital cost for the project. We are assuming that debt financing will be paid by the equity investors. And that's actually, with a project of this magnitude and the volume of debt that's being financed, that is a significant cost to the project. But what we show here is in both nominal and real dollars what the state would have to contribute, again, under our baseline cost assumptions, for a 5% up to a 25% equity share of the entire project or if we chose to invest in just one of the components of the project. So we do have the ability to invest in only one or two of the components of the project or the entire project, and we have the ability to invest between 5% and 25%.

So we could invest different amounts in the different components of the project as well. I know there's been some talk of what if we just invested in the pipeline, —for example. Representative Galvin and then Josephson. Thank you. If you would remind us, since it's been a bit, what the timeline is before we have to make that sort of decision.

And that decision is not in this bill specifically. It's in the bill in terms of the percentages and such, but is it in the bill in terms of the timing? And if so, would you remind us of what that was. Sure. Representative Galvin, through the chair, so I'm going to defer that question to AGDC.

I don't know if they're available for questions today or not online. We can answer that question off the top. Pretty sure it's later. And maybe my staff will make sure that we have AGDC in our next meetings. Okay.

Representative Tomaszewski. Yeah, thank you, Co-Chair Foster. So this 25% equity is for the entire project. That's the, that's the pipe pipeline, the import or the export, and the gas facilities on the North Slope. Yes, Representative Tomaszewski through the chair.

So we break out by each of the components, but then the gray shaded section there is if we had a 25% equity in the entire project under our baseline cost assumptions, that would result in $4.4 billion in nominal terms that would be required to invest in the project. And then as we share in the cost of the project, we would also share in any potential higher costs.

Thank you. Appreciate that. Representative Josephson. Sorry. No, just after we're done.

Well, of course, the last sentence from Mr. Stickel is concerning, but I must say, Mr. Stickel, when I look at slide 8, these are remarkably low numbers to me. I understand this is debt to equity, so you're talking about 30% of the cost of the project, as I understand it. And then 25% of the 30%. I think it was Callan that testifies to this committee annually, talked about— when I asked where would we get these resources, they said, well, they recommended overdrawing the ERA. I know that's sacrilege to talk about, and it will be left for the next legislature But I'm just struck by how low these numbers are.

I mean, and I'm just trying to figure out how that's possible. But $4 billion is something this state could probably borrow or find, I guess. Now, if you look at slide 9, Can you explain, and I assume it's because the debt is paid down, the difference between cumulative to 2052 and '62? What's going on there? And similarly on the— both in nominal and real dollars, why the jump up?

Sure, if we're ready to move on to slide 9. Sorry.

So slide 9 is the flip side of slide 8, which shows the total cash flow to the state from the equity investments. And we assume, for purposes of this slide, we assume that we took the 5 to 25% equity investment in the entire project.

To answer the first part of your question about why $4 billion seems low back on slide 8, So it is— we're assuming the $46.2 billion real capital cost, a 30% equity share, and 70% debt financed for the project as a whole. And then the state's share of the capital contribution would be 25% of that 30% equity contribution, plus our share of debt financing fees.

Follow-up? Perhaps, Senator Josephson. I still want Mr. Stickle to follow up on the cumulative to 2052 and '62. This strikes me, 6 months from FID is likely to be the next 35th Legislature.

This is like such a significant decision for the re— what I call the reelecteds, if they don't do it, they could be chastised for decades and remembered for not doing it. But if the project has significant overruns, they could be chastised for that? Is that sort of the political decision that will have to be made? Co-chair Josephson, yes. It's a— I would agree it's a very significant decision.

It's a commitment of, you know, at a 25% equity, it would be a commitment of over $4 billion, as well as an exposure to potential cost overruns. And then as we show on slide 9, there would be the potential for significant revenues back to the state associated with that investment. It is a very material decision.

Historic, absolutely historic decision. Yeah, I would agree with that assessment. And just if I might, on slide 9, again, the delta between the cumulatives is, is what? Why is it growing in that so fast between '52, 2052 and 2062? Sure, uh, kochō jōsu sen.

So what slide 9 shows is it shows the total net cash flow from the equity investments under our Under our assumptions, which include the $46 billion real capital cost and the 10% pretax rate of return on the investment and all the other assumptions that we've walked through, the cumulative through 2042 represents the net impact of our cash outlay into the investment as well as the returns on the investment through 2042. And so those numbers are fairly small because they also include our initial cash investment.

The date at which this becomes a net present value positive to the state in our modeling is in that 2039 to 2040 range.

Generally, I believe that was based on a previous— on a different version of the bill, but it's in that range of around 2040. And then you can see see, yes, the real cash flows to the state are a modest positive come 2042. And then through 2052, we include an additional 10 years where we assume a 10% pretax rate of return. Once we get to the 2062, our baseline modeling assumes that all of the debt financing is amortized over 20 years of operations. So the debt financing is amortized over through 2052, and so once you get to 2053 in our modeling, we assume that we're no longer paying off debt for the project.

And so all of the returns become positive cash to the state. And so a significant increase in the returns to the state once we get beyond that 20-year financing period.

It strikes me that legislators who are concerned about municipalities suffering a tax break, et cetera, if this FID plus 6 months decision is made, particularly at the maximum equity, then it's— from an emotional standpoint, it's just cheerleading. The state just— it must be successful and every advantage possible must be given to the project because you're so deep into it at that point. Is there something to that as a state? Co-chair Josephson, certainly. If we were a 25% equity owner in the project, it would change the calculus on any additional benefits to the project.

Thank you. Because we would share in those benefits. Thank you. Representative Hannan. Thank you, Mr. Chairman.

And again, I'm going to ask Mr. Stickel a question that's a little out of your wheelhouse, but I speculate that you've contemplated it.

Do you view— if we were to take— let's go to the 25% equity investor 6 months, FID plus 6 months. Do you read any of this as the state equity investment different whether we are using UGF investment, ADA invested dollars, or permanent fund invested dollars? Any difference in how that equity investment would be made in any modeling? Does that make any difference or legally the state equity share? Each of those dollars all belong to the state and where they come from is immaterial?

Rep. Hammond through the Chair. So in terms of our modeling, we are agnostic as to the source of funds. Certainly the source of funds would— could impact like the overall calculus to the state in terms of permanent fund has one opportunity cost. In terms of an expected rate of return.

General funds, other state funds have a different opportunity cost. If we were to include a debt issuance, for example, as part of the capital raise, that would change the net result to the state. So certainly the source of that funds is something to consider when making this investment. Representative Pandan. Thank you, Co-Chair Foster.

Have you modeled different source of funds for equity investment, or have you as Department of Revenue not gone through that piece of—. Representative Hannan, through the chair, we haven't for this particular table. We certainly could. I know in some of the past iterations of decisions like this, we have used the permanent fund as an opportunity cost, not necessarily that the money would be drawn from the permanent fund, but that given that the permanent fund is providing significant revenue to the state through the POMV annually, like, it is— the permanent fund is effectively an opportunity cost for the state. And so you look at their expected rate of return of a little over 7% annually, and that can be a lens through which to view an equity investment.

Thank you. Okay, Representative Josephson. Yes, so, so, uh, history major, not an economics major, Mr. Stickle. Looking at slide 9, when we say real, uh, dollars to the state, we're saying net of opportunity costs from the investment, is that right? No, Representative Co-Chair Josephson, when we say real 2026 dollars, we are assuming a 2.5% annual inflation rate.

And so we are taking all of the project cash flows and converting them back to current based on a 2.5% inflation rate. If we were to instead look at an opportunity cost, which Permanent Fund return would be a fair way of looking at that, this would— this chart would look different. And that certainly— that would be a very easy analysis for us to run. Follow-up? Representative Josephson.

And you may have just engaged in this dialogue with Rep. Hannan, but as a 25% equity owner, we're obligated to pay down some of the debt, I assume, and/or to restore the lenders. And are these numbers net of that restoration? Yes, Co-chair Josephson. So we assume that the project issues debt. For the 70% share and that we— yes, we get 25% of— or we get a share of the remaining equity return to the 30% that is equity financed.

Okay. Thank you. Representative Gelman. Thank you. And this is kind of stringing on from what we just heard.

My understanding, and I think it may have been Speaking with a larger group with Glen Farn and I believe maybe DOR was in the room, but the understanding is it is pretty common for large projects that are public utility projects typically do have a lower rate of return. So I am comparing this to, let's say, the permanent fund. And that is not a big surprise, is it to you?

Rep. Galvin, through the chair. So I think a key difference between— a couple ways of looking at it. One is in terms of the rate of return for the investors in the project itself. This project does have more risk than a regulated utility, and so would probably desire a somewhat higher rate of return.

Another is looking at it from the state's perspective as we're making the, the investment. So yes, we would need to look at what is— not only what is the modeled return on the investment, but what is the risk around that investment. And certainly there is a level of risk in making this investment. Thank you, and I have one other question that's not related at all. So if it's not time, I can wait.

You're good. Okay. So this is maybe perhaps something for our next discussion. The one piece of this puzzle that I think is important to consider as well is the understanding of how much cash or revenue— not revenue to us in the state, but revenue in general. So this is sort of the multiplier effect because we're bringing in— or with this project, there will be roughly 12,000 different sorts of jobs related to this project.

And I think 5,000 might be more directly with the pipeline itself. I just wondered if you had considered. I was looking through— I got a lot of really beautiful pamphlets about workforce future, but I really wanted to know the money piece, and that's not in here. It just says what sorts of jobs and things like that. And I wondered, I think it might be helpful for all of us to appreciate how many opportunities we may have in terms of the jobs that will be coming into play, for how long, I know that they're not all lifelong jobs, but some of them are, and at what wage.

So that's just something I wondered if you would consider, or if somebody— maybe it's Department of Labor— looking after so that we would have another understanding about a different piece of this puzzle and how it might affect Alaska.

Sure. Representative Galvin, through the chair. So I agree that's an important aspect of the project. Is the employment opportunities, the jobs, and then the associated costs of supporting those people in the state. Given that our current revenue system is— does not receive revenue directly from those jobs.

But that's definitely a piece worth looking at. That's not really our core area in Department of Revenue.

Follow-up might be— so, Representative, thank you, Co-chair Foster. So one piece of the puzzle is cost to the different communities, right, because of whatever infrastructure and services need to be in play. But the other piece is how much more money is being circulated in the community into the restaurants and into everything. That will impact that community as well in terms of overall dollars circulating. And that was the part that I thought we could perhaps come up with something, but I haven't yet seen any pieces to that.

Maybe you're waiting on learning more about PLAs and other things. Maybe, maybe that's the problem. Sure. Representative Galvin, through the chair, I know there's been some dated studies that have been done publicly looking at economic impacts. We have done some modeling.

I don't think it is quite going to be ready for prime time during the next 30 days. Okay. But using some of the similar tools we had, I know when we were all focused on the fiscal plan at the beginning of session, ISER came before the committee and so did we and presented some economic analysis looking at different fiscal options and using those types of tools to look at the AK LNG project. That's— that can be something valuable to kind of shine a light on the broader economic impacts. Okay, further questions?

Representative Tomaszewski. Thank you, Co-Chair Foster.

Do we expect this project to last more than 20 past 2062? Representative Tomaszewski, through the Chair, yes. That's the hope. And would we— do we have a chart on what the projected revenue would be after that? As far as— I know we're after 2052, our debt service is gone and we're making a lot more money.

If this project was to continue and more gas found and more gas sold and more billions of cubic feet going through that pipe every day, what's that gonna look like? Sure, Representative Tomaszewski through the chair. So once we're getting out to 2063 and beyond, it becomes an extrapolation of assumptions upon assumptions. Directionally speaking, these numbers will only get bigger. The project will be— the debt will be paid off and the revenue will be revenue to the state.

It will be revenue to the developer and the producers.

So it would be a positive upward line in terms of the revenue to the state. Follow-up. Follow-up. So when we're looking at our, you know, that investment capital are buying in for that particular share and the opportunity cost with that, it only gets better over more time in your assumptions? I mean, is that something— I know you can't— it's an extrapolation, but after that particular time of that service paid off and we've made the investment and the opportunity cost, it's only growing and getting better?

Yes. Representative Tomaszewski to the Chair. Generally, generally, yes. Obviously, at some point, there's going to be some additional costs with going back and upgrading components of that pipeline once you've gone 30 years to make investments in maintenance to have that pipeline ready to go for the next 30 years. One of the key uncertainties in our modeling is obviously what does global energy markets look like, uh, 30 or 35 years from now.

Um, but also we project that there will need to be some other sources of gas beyond Prudhoe Bay and Point Thompson once we get out beyond 30 years from now, and just uncertainty around exactly what those sources are. I think there's a lot of confidence that additional resources exist on the slope But what is the cost of those resources? What is the quality of the gas that's yet to be discovered? What land is that on? Is it state land?

Is it ANWR, NPRA, offshore? A lot of assumptions to be made there in extrapolating out beyond that. But yes, directionally, we expect the pipeline isn't going to shut down in 2062. That is just a convenient modeling time horizon for us to look at over 30 years. Thank you, Director.

Okay. Additional questions, comments? Going to take a 5-minute at ease. Be at ease at 3:49 PM.

Okay, House Finance back on record at 3:53 PM Thursday, May 21st. So if there are no further questions, my understanding is that when we have Mr. Stickel back up to quote, Mr. Stickel has a long list of follow-ups And so I think you'll be going through some of those at our next meeting with you. And so the other announcements that I have are the following.

We're going to go ahead and take the weekend off. Monday is Memorial Day, and so our next meeting will be on Tuesday, and that is at 1:30 PM. And I think next Tuesday as What day is next Tuesday? That is the 26th, May 26th. So that's when we'll be meeting, Tuesday, May 26th.

And we have polled the committee and the plan is to meet in Anchorage. And so we're working those details out and we'll let folks know. And today is our 6th meeting with the gas line. And our intent is to meet every day next week when we come back and probably through the weekend, just in terms of folks trying to make some plans, just to give you a heads up. And I think things are probably going to be moving a little faster than we think because 30 days seems like a long time, but when you start backing up the calendar starting June 19th being the last day of the special session and you work backwards and you work in terms of getting the bill to the governor, conference committee, possibly allowing the Senate to have some time, amendments both here and in the House and so forth.

Things are going to be moving, I think, a little quicker than I think most people think. And so we'll try to let folks know what we're looking at more specifically. But just to give a heads up that I think things are going be moving along pretty quickly. So are there any questions? See, Representative Tomaszewski.

Yes, thank you, Co-Chair Foster. So you said we're going to be meeting on the 26th at 1:30 PM, and that is in Anchorage? In Anchorage, correct. Okay. Okay.

That's, that's helpful. So we can, we can plan on being— we need to be there in Anchorage. I would— before you make any solid commitments, I would just say maybe give us a couple hours to work out a couple of details. And we'll maybe send out an email just to confirm that, but I think we just got the 90% letter, I would say, and so we're getting pretty close. Okay, thank you.

That helps with a lot of logistics for the rest. Great. Okay, if there's nothing else to come before the committee, we'll be adjourned at 3:56 PM.