Alaska Legislature: Senate Resources - April 29, 2026 3:30pm

Senate Resources Committee meeting to order. Today is Wednesday, April 29th, 2026, and the time is 3:30 PM. Please turn off your cell phones. I welcome Senator Rauscher, Senator Kawasaki, Senator Dunbar, Senator Myers, Senator Clayman, Vice Chair Senator Wilkowski to the committee today. I am Chair Giesel, and we have a quorum to conduct business.

Thank you to Heather and Chloe for helping us out with the audio. So today we are continuing our hearing with invited guests from the Department of Revenue continuing the presentation. So Mr. Dan Stickle is going to continue his presentation. He also brings a response to our questions from the Department of Revenue, not only in a letter but also in an additional PowerPoint. The other document you've received comes from the AGDC.

It's a fiscal note from AGDC. And you also would have gotten a hard copy of, from the Department of Revenue Tax Division, the North Slope prevailing value chart, just informational, that's all. So, so Mr. Sickel, welcome to the table.

Let's see, online, let me just see if You've got online. Online, there is no one else from your department. Just you. All right, Chair Giesel. I believe I do have a lifeline that will be calling in at some point.

All right. And I was told that Frank Richards from AGDC is also online if there is questions for AGDC. Gotcha. So, yeah, Dan Stickel, Chief Economist, Department of Revenue, for the record. And so we are picking up.

On slide 20 of our presentation, looking at the Senate Committee Substitute for Senate Bill 280, version G. On Monday, we went through kind of our understanding and interpretation of what the bill does, as well as the revenue estimates for each major revenue-impacting component of the bill. And that's where we left off. Very good. So we were moving on to our estimates for implementation costs. So for the bill, we are requesting 11 positions to fully implement the provisions of the bill and provisions of the AKLNG project generally.

We are requesting a corporate income tax auditor to administer the new tax on pass-through entities that would be under this bill. We're requesting a new tax auditor to administer the, the new alternative volumetric tax and the community impact fee. Those would both be set up as new tax types within Department of Revenue. We're requesting several positions for our oil and gas audit group: an oil and gas revenue specialist and two auditors. They would administer and implement the the increased valuation requirements under the bill and also to deal with the increased complexity of tax administration and audit around some of the additional nuances that we're adding to the tax code that we just discussed on Monday.

We're requesting 3 commercial analysts to assist with increased analysis and reporting under the bill. Including those new prevailing— detailed prevailing value reporting requirements, the increased complexity around tax analysis and forecasting, and then also to build up our commercial analysis expertise within Department of Revenue to assist with those state investment decisions and project evaluation. We are requesting— and then kind of some support staff within Department of Revenue, given the The fact that our existing staff are stretched very thinly as it is, and we are adding a significant number of additional positions. So an additional analyst programmer to assist with the reporting and IT and general IT support needs of those additional staff, an administrative assistant so that these new people don't have to do all of their own admin work, and then an appeals officer. We are expecting that there would be increased appeals and litigation around some of the provisions in this bill.

So someone to kind of manage that process and also assist— some of these positions would also assist with our kind of our general regulations development and implementation process. Senator Rosier. Thank you, Madam Chair. So I was just wondering, once the line is up and running, it's built, and are these any of these temporary or all of these going to be needed? Throughout the whole project?

It seems like some of the titles is up and running, getting going kind of stuff, and then maybe later. Um, so it's temporary, or is this, this what we're going to need for the whole hall? Senator Rauscher, through the chair, so for now we're expecting for the— as an ongoing process, um, it is, you know, potentially once the project is in full operation and all of these legal issues have been settled. It takes many, many years to work through some of those issues. You know, potentially we could reduce— this would be looking kind of laid out in the 2030s, very speculatively.

You know, we, we anticipate the new taxes will continue to exist and the increased complexity will continue to exist. And we— it would surprise me if there's not ongoing requests for analysis and evaluation of fiscal regimes. That seems to have been kind of an ongoing thing. Follow-up. Follow-up.

So does that exist right now with the present oil and gas that we work with right now?

Or is it all settled, that kind of stuff? We don't need this kind of— help every day. Senator Rauscher, through the chair, so we do have an existing oil and gas review and audit function. Those folks are stretched very, very thinly, so it's not, it's not always a comprehensive audit, and we would need more staff to implement this bill. So they exist now?

So they exist now? Senator Rauscher, through the chair. Yes, we do have positions. We have people in all of these groups. So this would be adding to additional groups to implement the additional workload.

I just wanted to understand. Thank you. Sure. Senator Myers. Thank you.

Mr. Stickell, could you just remind me under the initial version of this bill that came from the administration how many extra people we were trying to add? Senator Myers, through the chair.

I think, yeah, was it 1? We went with 1 to implement the new tax type. Okay. Thank you. Senator Dunbar.

Yeah, I want to point that out. I'm looking at the other, at your previous fiscal note. 1 Person, not really any new regulations. Yet we're creating an entire new tax regime. And the original bill also said we had to exempt all local taxes.

How are you going to figure that out? Were you going to do a regulatory package or was there no regulations associated with the first, with the initial version of the bill? Sure, Senator Dunbar, through the Chair. So there will be some amount of regulations needed to implement AKLNG broadly regardless. Some of that we can do with existing staff.

So we do have a revenue specialist that works in regulations. We do have support from Department of Law. So some of that we can do internally. The governor's bill as proposed was very— was fairly simple on its face. The project would not be subject to the property tax, and instead we would implement a new alternative volumetric tax.

And so the additional position that we initially requested was just the workload to kind of manage that additional volumetric tax. Follow-up? So the original bill also said you couldn't do bed tax, you couldn't do car rental tax, you couldn't do any of that. That would have created a lot of questions with interacting between the organization and the municipalities. Certainly there would have been, you know, disagreements there.

Was the thinking that Department of Revenue wouldn't be involved in that, or who would have drawn up those regulations? Who would have administered those cases? Sure. So, Senator Dunbar, through the Chair, as I testified previously, the intent of the administration was not to have a broad exemption on all bed taxes and car rental taxes. The intent of the administration with the exemption— and the exemption would be for municipal taxes— was a narrow exemption to property taxes and basically an equivalent to the property tax.

And so the administration was absolutely open to tightening up that definition to make it clear that the intent was a narrow prohibition on other taxes by the municipality. And the, you know, that process would apply at the municipal basis. So there would not be an additional workload for the State Department of Revenue Tax Division in exempting a project from a municipal tax. The only workload that we would have would be the process of exempting the project from the state tax. And then adding the new alternative tax and any of the related kind of issues and analysis and discussion that would be handled by the, the one additional position that we did request in that fiscal note.

Very good. Well, I follow up. No, I just, I look forward to when we create another new tax structure in the future. I look forward to one position, one new tax, one new position. That's the original.

That's the original fiscal note. Thank you, Madam Chair. Senator Kawasaki. Thank you. Actually, I'm looking at a different fiscal note.

It's the one for ATDC, and in services it talks about a lot of outside contracts, and so I don't know if you can address those. It's not by you, it's by— I believe—. DCD. Probably, yeah, probably, yeah, it's by Frank Richards.

And it is an amended one. The previous one had been zero. Yes. So I don't know if it's a good time to ask or—. If you would like to.

Also, Mr. Stickel, Dan Herbert has signed on, just so you know. Mr. Richards is on the phone for questions if you'd like to ask him right now, Senator Kawasaki. Yeah, sure. All right, Mr. Richards.

Madam Chair, Madam Chair, for the record, Frank Richards. It would be helpful if Senator Kawasaki could restate the question. Sure. It was hard to hear him. Yes, I didn't have the question yet, but I do have a question now.

It's on your new fiscal note, it's dated 4/27/2026. The request is for $2.2— relatively $2.2 million in operating expenses over— oh, and it goes up to $4 million in 2032. The question has to do with the Fairbanks Gas Line project, which was not a piece of this, uh, not a piece of the original 280 by the governor. It talks about adding the Fairbanks Gas Line project and accompanying infrastructure and things like that.

So it talks about a lot of other positions, and I'm just curious how these positions came into— I mean, if you could sort of explain the fiscal note, I guess, because there's a lot of contracted positions for accountants, for IT, for I mean, there's a $250,000 contracted legislative liaison per year and things like that. I'm just curious if you can explain the fiscal note for me.

Absolutely, Senator Kawasaki, through the chair. We took a review of the CS for Senate Bill 280 and looked at the provisions in the CS and tried to identify what responsibilities that would be placed on AGDC with those provisions should they become law. So in regard to your— the first part of your question around the Fairbanks Spur, we saw that the goal of the committee was to have the Fairbanks Spur constructed. And so we developed what we thought would be a cost estimate to include not only operating expenditures but capital expenditures to be able to have that Fairbanks Spur line built. So on the second page or third page of the fiscal note, you'll identify that there's $2 million in terms of the operations of the Fairbanks spur gas line, and that is to cover the operating cost of actually operating that spur once it is constructed.

And then in the capital appropriation, there's identified $245 million for actually then the development and construction of the spur line from Fairbanks from the, the mainline project. So that is the goal we thought that the, the committee was asking for, was seeing that the Fairbanks Spur Line be built. And we came up with the cost estimate to be able to accomplish that and utilizing EGDC resources to be able to develop that and ultimately to operate that, or to be able to contract for the operation of that. So that was the, the first part of the question. Does that Answer your initial question?

Yes, thank you, Madam Chair. I guess that answers my question sort of broadly. You know, I think that it is the will of the committee, I'm guessing, to see that Fairbanks does have a spur line. I think Fairbanks has been discussed each and every time we've had a discussion on Senate Bill 138, the original AGDC framework bill. I'm just curious why it's suddenly going to cost us a lot of extra money Because again, I mean, even the governor's statements were that we were going to get gas to Fairbanks and that was a priority.

And so I thought it would be something that AGDC was going to be able to absorb internally because you're already talking like we're going to get a gas line to Fairbanks.

Am I wrong about that? Through the chair, through the chair, Representative Kawasaki, again, It's always been the direction that was provided to AGDC that a gas line be developed to Fairbanks. That was the original lateral that we had from the Alaska Standalone Pipeline Project where we did include that in the initial work and went through a design effort and went through partial permitting of that. But that effort was stopped, again, at the direction of the legislature and our board back in 2015 timeframe because the emphasis and the direction policy call was that the Alaska LNG project was then the priority of the state of Alaska. So we felt that what the committee was asking for was that the project be designed and ultimately be operated to provide gas to Fairbanks.

And so we looked at what it would take to not only conduct the necessary permitting but also update the design based on current demands within Fairbanks and looking out to even the military bases, what their demands might be to be able to meet the needs for power generation on both Wainwright and Ileson as well as heating. So that's why we came up with this fiscal note that would identify that the cost would be borne essentially by an appropriation in this case unless there's another mechanism that the committee or the legislature would like to direct AGDC to conduct this work on. Follow-up, Senator Kawasaki? No, I think that's fine. Thank you.

All right, Senator Wilkowski. Thank you, Madam Chair. Yeah, I'm looking at the fiscal note too for AGDC, Mr. Richards. And how many employees do you have at AGDC?

Through, uh, through the chair, Senator Wilkowski, we currently have 3 direct employees, and then we have contract staff that we have under contract to be able to provide for not only some of our IT work, some of our commercial work, but also some in terms of project development and other consulting efforts. This fiscal note adds one staff member to AGDC, essentially a general counsel, which AGDC had previously, but through budget reductions, we've cut the in-house counsel and been relying solely on Through the work efforts coming from the Department of Law and the part-time Assistant Attorney General. Follow-up, Senator Wilkowski. Yeah, and can you get us a list of your, of your employees that you have and how much they're paid and.

What they do. This fiscal note looks very interesting, and I would like a list of all the contracts for contractors that you have and all the people that you are hiring, and I would like a report of all the money that you are expending for counsel, for— I assume you are paying the Attorney General for the legal fees, or is that being given to the AGDC at no cost?

Through the Chair, Samuel Wilkowski. Now, we have a reimbursable service agreement with the Department of Law for the Assistant Attorney General counsel.

Yeah, nice. Madam Chair, if I could. Yes, follow up. I see you're now asking for $1 million a year for outside counsel in every year. That seems very interesting to me.

That's quite a request. Thank you. Senator Myers. Yeah, thank you, Madam Chair. So, Mr. Richards, on the Fairbank spur, we're not using state money as the capital to build— obviously we spent a lot of state money, but we're not using state money as the capital to build the mainline.

And you've been directed through statute to you for AGDC to build the mainline, and you're doing it by finding a partner. Why is it that you are not doing the same thing if we're directing you to build the spur? Wouldn't the obvious choice then be to turn around and then use the same partner at a minimum, if not find another partner and come up with a similar agreement?

Through the chair, Senator Myers, you're absolutely correct. We had the opportunity to partner with entities to be able to construct this line. I took it to the direction coming out of the CS was that it was a priority of the committee to be able to have the line constructed. So I put forward a fiscal note that would allow it, uh, the surety that it would go forward with funding. Uh, follow-up.

Yeah. So what I'm trying to understand is why do you have a $245 million fiscal note for the capital when it wasn't a $10 billion fiscal note when SB 138 was passed. I mean, shouldn't the two— if you say you're going to use the same process, why didn't you— why wasn't that reflected in the fiscal note then? [Speaker:CHAIR] Through the Chair, Senator Myers, you are correct. Under SB 138, where the state of Alaska was going to have a 25% equity position in the Alaska LNG Project, that would have equated to, at the time, around $10 billion.

And I'm sorry if I don't recall if that fiscal note was ever identified, but truly in reviewing the discussions at the time where the state was recognizing that as an equity partner, it is going to have to provide that level of equity into the project to be able to move it forward.

I just want to make sure that we have the alternative to be able to meet the needs of Fairbanks with either direct appropriation or other financial mechanisms. AGDC does have the ability to use bonds to be able to finance this project. That is a consideration that we could do moving forward, and it would have to then be paid— those would be revenue-based bonds. Again, that does not require the full faith and credit of the state. That would be based on the revenue generated from the contracts within, within Fairbanks.

All right, moving on. Back to you, Mr. Stickle. All right, uh, Dan Stickle again for the record. I think we had worked our way through slide 21 and we're ready to move on to slide 22. Yes.

So this is the capital request of the fiscal note. So we received an estimate from our contractor for our tax revenue management system, which is Fast Enterprise. And about $1 million is the estimate for the cost for them to program all of these new taxes and changes, including some fairly fast time frame changes with some of the retroactive provisions of the bill. And then an additional $500,000 for a capital estimate. This would be for outside expertise above and beyond what we have internally to help with some of the complex regulations around things like the lease expenditure allocations, and then to provide some assistance on our kind of framework for project investment decision-making, to bring in some global experts to supplement our internal expertise.

[SPEAKING IN FOREIGN LANGUAGE] Senator Kawasaki. Yeah, just, um, it has to do with this slide and the prior slide, but just, um, you know, you're asking for several folks that are subject matter experts, professionals. I'm just curious, how many do we have currently? Because I know that there was discussion about the total number of master auditors and things like that, especially in the oil and gas section. There were a lot of recent retirements too.

Can you just tell me, are there a lot of vacancies? Are there you know, is it a competitive wage, a competitive job? Are we having trouble hiring those as it is now? Senator Kawasaki, through the Chair, I believe our total headcount is in the 90 range for the tax division as a whole. We've lost over 30 positions over the last decade.

We have zero master auditors remaining. We have lost all of those. We do have challenges with staffing. So our, our staff are stretched to the limits, and so the ability to absorb new tax types and changes is extremely challenging. Basically, we're at the place where something's got to give.

Follow-up, Senator Kawasaki. Thank you. Um, do we currently contract out those types of services when it comes to audit-level requests and things like that? And then I guess another side question is how far behind are we on the ACES tax audits? Senator Kawasaki, through the chair, I am not intimately familiar with the budget.

I don't believe that we are doing any contract audits presently, but I'd be happy to confirm that. And I believe that all of the ACES has been put to rest or beyond the statute of limitations there, but I can confirm that in writing. Thank you. Further questions? Senator Wielechowski.

Yeah. I don't know who to address this to, but since you're at the table, I don't think I saw a fiscal note from DNR, Department of Natural Resources, and since they're administering royalties and also from DOT, I know we've heard testimony that they would need $450 million over the next 7 years to upgrade the Dalton Highway. I don't see a fiscal note from them. I don't see a fiscal note from DNR, who will be administering presumably a whole new slate of royalty provisions. I know it's not your department, but I'm just curious if there's— on behalf of the administration, has there been any discussion about those two departments?

Sure, Senator Bullockowski, through the chair. So to be clear, I'm not necessarily speaking on behalf of the administration. I would defer those questions to the agencies. I know DNR has been available for some of the prior hearings. I don't know if they are on today.

I'm not ready to speak on their fiscal note. Senator Wielechowski, they are not on right now and they have informed us that their fiscal note is on the way. We have not gotten a response from the Department of Transportation.

Further questions on slide 22? Seeing none, we will move on to slide 23. All right, slide 23 takes the information that I presented on the other two slides and just puts it in numerical form. This is a snip straight out of the fiscal notes. You can see our operating request is about $2.4 million per year for those 11 positions, and then the $1.5 million of capital request.

I see no questions. All right. And so now we move on to the really exciting stuff, which is the detailed project modeling. So we've taken the same set of project modeling slides that we presented for the committee earlier on with various metrics for under current law, if the project went forward as proposed, and then under the initial version from the governor as proposed, and we've also modeled in the committee substitute, to the best of our understanding. So to reiterate, slide 25 just gives a high-level reiteration of some of those baseline assumptions in our modeling.

So we're modeling the first 32 years from first sales of LNG, or 30 years of full exports. We are assuming a 10% pretax equity return on investment to the midstream operator. We're assuming a $46 billion capital cost for the project in 2026 dollars. We're assuming a $1.50 per 1,000 cubic feet gas purchase price in 2026 dollars from the upstream. For Phase 1, we did do a change to our modeling there.

So we are no longer assuming that Great Bear will be a source for Phase 1 based on some of the public information that's out there. We're now assuming that Phase 1 will come from some other field. So there's been discussions around potential agreements that exist with Point Thompson, Prudhoe Bay, or North Star. All, all 3 of those fields would require gas processing. And so that is one of the changes that we've made for our Phase 1.

Analysis is we are assuming that there's going to be a charge for gas processing. For modeling purposes, we've assumed a similar overall cost for the gas processing as for the full pipeline. During Phase 1, the requirements for how low that CO2 amount has to be would be not as stringent as for a full export process, but there would be less economies of scale. So we've just assumed a similar similar amount of charge for processing there. And then again, for Phase 2, we're assuming that Prudhoe Bay and Point Thompson are the anchors for the full project.

We are assuming no impact on Prudhoe Bay oil production as our baseline assumption, and we're assuming an addition of 270 million barrels from Point Thompson of oil production over life of project. So, um, to the non-Great Bear Field requiring treatment, so we have to calculate in now the time it will take to put the grass— gas treatment facility up and running, which previously hadn't really been part of this. Chair Giesel, so we're assuming that that treatment could be installed at this— along the same timelines as the Phase 1 pipeline.

Whether that would be some phase of the full gas treatment facility or some smaller gas treatment facility or some sort of temporary treatment, I mean, those are details that would be worked out. But we're— yeah, we're assuming that that could be done on the same timeline, and my understanding is AGDC's in agreement with that. [Speaker:COMMISSIONER ARKOOSH] A modular-type situation. Potentially. That's one way to envision it.

The details could be worked out. Sure. Further questions? Senator Kawasaki. Thanks.

And so is the assumption that the gas treated at the North Slope point would be of some lower quality, but then by the time it gets exported as LNG, it would be reprocessed downfield? I mean, downpipe. Sure, Senator Kawasaki, through the chair. So the assumption is that the gas from— so utility has about a 2% CO2 threshold. Carbon dioxide is kind of the standard.

Export gas for LNG has a 50 parts per million or lower threshold. So that's a very significant difference.

The North Slope sources of gas outside of the Pantheon, Great Bear, have 4% or more of CO2. So it's getting it from that 4% or more down to the 2% for Phase 1. And then—. Follow-up. Thank you.

And if the offtake at Fairbanks— the offtake at Fairbanks would be at the 2% grade, or would that— could that be processed at that point before it hit the utility in Fairbanks? Sure, Senator Kawasaki, through the chair. So our assumption is that the gas processing would take place before going into the pipeline on the slope, and so what is delivered into Fairbanks would be at the 2% or lower CO2. Thank you. Senator Wilkowski.

What is your estimate of what the lease expenditures would be per year for gas production at Prudhoe Bay— deductible lease expenditures at Prudhoe Bay and Point Thompson? Sure. Senator Wilkowski to the Chair. So we actually have some numbers to that. I have a chart in the response document that we provided and we have slides that get at that.

I don't know if we want to switch to that now or come to it later. It is slide 11 of the response document. Response document to the April 13th and 14th hearings we show, and that's incremental assumed lease expenditures between Prudhoe Bay and Point Thompson. [Speaker:COMMISSIONER TREGONING] We will look at those in depth later. We will move on from— I see no other questions on 25.

[Speaker:COMMISSIONER MAY] All right. Moving on to Slide 26. So, yes. So what we have done here is we have taken the two scenarios that we previously presented and just added a third scenario. Most of these slides show all three scenarios so you can kind of see them laid out together.

The modeling shows the impact if the full project proceeds under each of the scenarios. That's obviously an uncertainty and reflects our preliminary interpretation of Version G and some of the implementation decisions. So we talked about that. For instance, we talked about our assumption on lease expenditures allocation for modeling purposes of assuming that 50% of those incremental lease expenditures would be deemed GAS lease expenditures. There's a few other provisions like that.

And the interpretation of the community— the community payment that we're assuming that would be the $739 million total. So some of those various assumptions that we talked about on Monday.

So Slide 27 is a slide that you've seen before. This was our analysis summary under the current tax law, assuming the project went forward without any tax relief. And you can see what the total cash flows to each of the stakeholders is over life of project, as well as those cost of supply for both the in-state and for LNG into the global market. Those are the two numbers that are really useful to focus in on in terms of like how this impacts the project economics. Madam Chair?

Yes, Senator Myers. Thank you. Mr. Stickell, so we've got the provision in law says that the state can buy in up to 25%. When you were doing the state revenues and the midstream owners, did you take in any of that into account? I recognize that we haven't made the decision decision yet which way we're going to go, but sure.

Senator Myers, to the chair, no. So this assumes that the state will not take an equity position. It's kind of the baseline. We do have the ability to evaluate the impacts of an equity decision. We've presented some of that analysis in the other body, looking at a 5 or 25, um, equity investment under current law and the bill as proposed.

We'd be happy to provide that back to this committee as well. Okay, thank you. So, Mr. Stickle, looking at the North Salt prevailing value for gas, as it's dated, uh, April 14th, um, it's looking at— I'm gonna round it to $3. $2.994. But here it says the gas commodity charge is $1.92.

Sure. Chair Giesel, so the North Slope prevailing value, that's a value that we publish based on information provided by the taxpayers. It represents a weighted average of current gas sold to utilities on the North Slope. So given the current demand that does exist on the North Slope, what is the average price of sales that are currently taking place? The AKLNG project would have a much higher level of consumption and kind of a whole different set of economics from those existing producers.

And we— yeah, the $1.92 represents our assumption for the price that's negotiated with the producers. So again, even the $3 is a weighted average of prices that are negotiated with producers for various gas sales. The $1.92 represents an assumption that the negotiated price would be $1.50 per 1,000 cubic feet, and we inflate that up to $33. And then we also— there's a slight increment there to the commodity charge because we assume that gas is provided to the project and used as fuel gas in operations. So to get one unit of gas delivered at the end of the project, you actually have to buy a little bit more than one unit of gas at the beginning.

So this is taking into account the export facility as well. 15% Of that gas would be used for the manufacturing process.

Chair Giesel, not— [Speaker:MR. HART] I'm not sure if that's the exact number. I'd be happy to have someone chime in on that assumption, but yes, directionally that's correct. We're assuming that the project would have to purchase enough gas to use as fuel gas throughout the project, and that is why the gas commodity charge under the LNG side of the ledger here is higher than under the end state only, because that fuel gas for LNG would only apply to the export gas. [Speaker:COMMISSIONER ARKOOSH] Gotcha.

Other questions? All right, seeing none, slide 28. All right, slide 28. Again, this is a slide you've seen before. It's that same slide with Senate Bill 280 as introduced by the governor, and you can see that the in-state weighted average cost of supply in 2033 would drop from $4.86 to $4.43 per 1,000 cubic feet.

And for delivered LNG into the global market would drop from $9.07 down to $8.48 per thousand cubic feet. Senator Dunbar. Thank you, Madam Chair, and thank you, Mr. Segal. I believe that you explained this at our last presentation, or not the last one, but last time we saw these charts. Could you remind us again why the midstream owners here, their cumulative to 2062 is $68 billion But under the current tax law, property tax, they make $70 billion.

So why wouldn't they prefer our current tax law if they're going to make $2 billion more over the long term to this proposed tax change? Sure. Senator Dunbar, through the chair. So again, these top numbers represent cash flows, not profits. So it's not how much profit any of these stakeholders make.

It's the total cash flow revenue into the project. We assume that the midstream owners will have to— will earn a 10% rate of return on the project given the substantial tax reduction from current law property tax to Senate Bill 280 as proposed.

A— there's a lower amount of revenue needed to pay the taxes and a lower amount of revenue needed to break even on the project, and thus the 10% return is applying to a lower revenue. Follow-up. Thank you. So are you— so you're assuming a 10% return on both or just on the on the latter.

Uh, Senator Dunbar, through the chair, so we're assuming a 10% pre-tax return for the midstream owner. And the way this works is we, we developed our model. So this is a model that we've been using for over a decade. Um, it's developed as a tolling methodology model. So we're basically looking at this the way that a regulated utility would, where any additional costs get incorporated into their rate base, and then they earn a return on that rate base.

And so when you have a higher cost base, including higher property taxes, you do earn a higher return on that higher rate base. That— this would not be a regulated pipeline, but that's the modeling methodology that we've used. Follow-up? Well, yeah, that's interesting. It's certainly not regulated in the sense that, again, the domestic market is a tiny fraction of this.

It's— they're selling into the international market, which is not in any way regulated, uh, you know, in terms of price. So I just— I don't know, it's, it's just, it's a little bit strange, uh, when you're trying to explain this to folks because it looks like they receive the same amount of money, or the same amount of money passes through that company at least. And I don't have a clear sense from here of what their rate of return is at the top graph— I'm sorry, on page 27 versus 28. And you're saying that it's 10% in both even though they actually— well, I don't think it's actually intuitive. I don't understand how that could be the case.

Yeah. Senator Dumbrow through the chair, so we are assuming a 10% rate of return to the midstream owner. In each of the cases.

And what we're doing then is we're looking at how does that cost of supply change. And so really it's the cost of supply that we are focused on when we're comparing one, one option to the next.

Thank you, Madam Chair. Further questions? Seeing none, 29. All right, slide 29 then is the similar analysis looking at the version G before the committee. And so this comparing that cost of supply would be a slight reduction for the in-state cost of supply compared to the current law scenario, but would be a higher cost of supply than the Governor's bill is proposed.

And it would be roughly a similar breakeven global market cost of supply as under current law with all of the different changes, but again, higher than the version as proposed. Madam Chair. Senator Myers. Thank you, Madam Chair. So, Mr. Stickell, effectively what I'm looking at here, comparing the LNG breakeven price on '27 to '29, if this is the version of the bill that moves forward, eventually makes it to the governor's desk, effectively what you're telling me is that we are no more competitive in the global market under this version as opposed to current law.

Is that right?

Senator Myers, through the chair, looking at those delivered LNG prices, yes. Okay, thank you. Senator Wilkowski. What's— so just on that question, so the, the LNG, let's see, is 9— 908 versus 907 and versus 848. What is the amount that you believe we need to get to to be more competitive?

Uh, Senator Wilkowski, through the chair, so I, I can't answer that, you know. I know there's been testimony from AGDC and from the consultants. We can look at, you know, where are current LNG prices? Current LNG prices are over $10 a barrel or $10 per— MCF. —Per MCF.

So current LNG prices are strong. Once you go out into the futures market for delivered LNG, prices are in the 8s, $8 range. So it's a marginal project, just looking at futures markets, you know, looking 8, 10 years down the road when the project would be delivering. Follow-up. Well, when you say in the $8 range, that's— is that $8.01 or $8.99?

Because that's a pretty big difference here, because we're talking about the nominal LNG breakeven price is $9.08 under Senate Version G, and it's $8.48 under the SB 280. So you're talking a 50, 60-cent difference, I guess. I mean, where along that 60-cent sliding scale do we lose competitiveness? Yeah, sure. Senator Wolkowski, through the chair.

So we can speak directionally to competitiveness. Obviously, lower taxes make the project more competitive. There's enough uncertainty around the the project in global markets, it's hard to say with any certainty. And I'm sure the project developer would be happy to kind of echo those comments.

Other questions?

All right. Seeing none.

All right. Slide 30. And again, these are some charts that we presented before looking at annual state revenues broken out by revenue type over the life of the project. In response to feedback from the committee, we have removed the dashed line. [LAUGHTER] And we will keep that out of future versions as well.

So slide 30 shows the annual state revenue under the current law scenario given all of our assumptions and assuming the project went forward.

Slide 31 was the similar slide that we had already presented with Senate Bill 280 as introduced. And then Senate Bill— or slide 32 is the Senate Bill 280 version showing the annual state revenues to the state. Follow-up? Yes, Senator Dunbar. Thank you.

So this chart still has our revenue going negative in 2029 and 2030.

Why? Senator Dunbar, through the chair, so that represents production tax impacts related to the significant investments that we assume will be made upstream to support additional oil and gas development. Follow, Madam Chair. Yes, follow. The version G, and I don't think it's going to be the version that eventually passes, I think there will be other amendments, but version G says you can't count those expenses against production taxes.

I mean, it has a provision to try to accomplish that goal of not allowing the gas lease expenditures to count against production taxes. So why did you model that? Sure. So Senator Dunbar, through the chair, as I explained on Monday, we assumed for modeling purposes that 50% of the additional lease expenditures would be deemed gas lease expenditures.

I talked about some of the complexity around those regulations, um, in particular for Point Thompson, where a lot of the money is gonna be spent. There's going to be billions of dollars of additional investment that we're foreseeing. That's going to, uh, allow for, uh, gas supplies into the project, but also additional oil production. And so again, there's a range of uncertainty around there. We've assumed, uh, just for this modeling purposes, that half of those incremental costs would be gas.

And if you compare this slide to the previous slides, you'll see that those negative bars are about half the size. Follow-up, Madam Chair. So you have included in this modeling expenses that will be counted against the production taxes that are not associated with the project, essentially. I mean, that's what legally they are. They're not associated with the project.

They're going to be for oil, not for gas. And so my follow-up question is, does this— graph include the pass-through entities tax that was added in the G version, in version G? Senator Dunbar, through the chair, yes. So that's included in the corporate tax, the orange line, and you'll see that that orange bar is significantly larger than in the previous two charts. Mm-hmm.

Follow-up, Madam Chair? Yes, follow-up. But is it a pass-through pass-through entities tax associated just with the gas line and with the midstream operator, or does it include other folks who are currently operating in, in the state as pass-through? Because, for example, the little orange dot in 2030 is currently negative. I mean, it's below the line.

So please explain that. Sure, Senator Dunbar, through the chair, and I may have to call on a lifeline for this, I know we included the pass-through entity tax revenue for the midstream operator, assuming that they would be subject to tax under this bill and not under current law. I know we assume the pass-through entity tax for assuming that all upstream production into the project would be subject to corporate income tax. I may call on my lifeline for the assumption of what we assumed as far as current producers under the spring forecast. That would be Mr. Herbert.

Mr. Herbert, welcome to the committee. If you could address, uh, Senator Dunbar's question. Did you hear it? Uh, yes, I did. Um, through the chair, this is David Herbert, commercial analyst for the Department of Revenue.

Uh, through the chair to Senator Dunbar, um, in the graph we're looking at, at slide 32, um, The orange lines, corporate income tax, do not include any additional pass-through entity tax associated with production not tied to the Alaska LNG project. Okay. Thank you. Can I brief follow-up, Madam Chair? Follow-up.

So while this graph does include expenses not associated with the project having to do with oil because we're not going to count them all against production taxes. We did not include the revenue that exists in version G tied to currently producing entities that are also not tied to the project. So in other words, I mean, this isn't— this isn't the fiscal note. I assume your fiscal note would be more complete and include the revenue from currently operating pass-through entities, but If that amount was added to this graph, Mr. Herbert, would we be negative for 2029 and 2030? Sure, I can take that.

Dan Stickle, for the record, to Senator Dunbar through the chair. So we have not included the impact of the pass-through entity tax on currently forecasted production. Under the spring revenue forecast. That was the $0 to $100 million annual range that we mentioned previously. We have not included any impact of the lease expenditure allocation provisions on current production in the spring revenue forecast.

It is possible that some lease expenditures under the spring revenue forecast could be impacted by that provision. It would depend on the regulations that we develop. We have included in this chart the revenues from additional pass-through entity tax for the direct revenues on the project, both upstream and midstream, and we have included in this chart the impact of the lease expenditure allocation provision for additional spending associated with this project. Follow-up, Madam Chair. Follow-up.

What would this graph look like if you included the pass-through entity revenue for the currently producing entities? Senator Dunbar, through the chair, there would be a range of $0 to $100 million per year of incremental revenue. And if we included the impact of lease expenditure allocation on current forecasts, there would be an indeterminate revenue impact there. So it would be a indeterminate, zero to potentially $100 million or more impact in the positive. Thank you, Madam Chair.

Senator Myers. Yeah, thank you. Um, Mr. Stickle, I believe you said that, uh, previously that the assumption was that the, um, current midstream partner is not going to be subject to corporate income tax, but they're currently out looking for equity partners to raise cash to build the project. If they found a C-corp that was willing to throw in money for equity, you know, let's say it could be somebody like ConocoPhillips or maybe some, you know, maybe just an institutional investor like Goldman Sachs, would they then be subject to the standard corporate income tax? Senator Myers, through the Chair, potentially yes.

Okay. Thank you. Senator Wilkowski. Just want to clarify the corporate income tax numbers that are showed here. Did I hear correctly that that only includes the developer corporate income taxes?

Senator Wilkowski, through the Chair, so this includes our estimate of the pass-through entity tax applied to the developer. It includes also our estimate of incremental corporate income tax to the upstream owners associated with the project. And for this version of the bill, we now assume that all of the upstream owners would be subject to corporate income tax or similar tax. Follow-up? What is the amount that you expect the developer to be paying in corporate income taxes in 2062?

Senator Wielechowski, I happen to have that exact number at my fingertips. I thought you might. It's $466 million.

Okay. Follow-up? Did you coordinate with Mr. Fulford? Because he had a very different number. He had very different numbers.

Sure. Senator Wielekowski, through the Chair, yes, I did. And we had a good discussion yesterday and earlier today. My understanding is that our model is significantly more sophisticated and complex, and they had a more simple model. And that their recommendation is basically to look at our numbers as the kind of the working version of those numbers.

So we have additional nuance in our model above and beyond what they did in their simple analysis. Senator Wilkowski, just to follow up on that question for a moment. Just before I came down to this meeting, I had an email from Mr. Fulford. He would like to present again and talk about what he had collaborated with. Follow-up.

So at $466 million in 2062, that is at a 9.4% rate, that's still assuming a profit to the developer of roughly $5 billion? Senator Wilkowski, through the Chair, order of magnitude, roughly, yes. Okay. So we assume a 20-year tolling and debt methodology for the project. And so the corporate income tax payments and the profit to the developer are lower over the initial 20-year time horizon where they are paying off debt and earning that 10% assumed rate of return over the 20 years, but then there would be potentially more revenue beyond those initial 20 years.

Follow-up. Just, okay, so, and just sort of looking back, it looks like from 2048 to 2062, it's around a similar amount, $462 million in profits.

Sure, Senator—. Corporate income taxes, I'm sorry. Senator Wolkowski, through the chair, so looking just at the corporate income tax assumptions that we have for the developer themselves. We project that depreciation and net operating losses will offset those corporate income taxes for the first several years. They'll start paying corporate income tax in 2036 at $29 million, $30 million in 2037.

Increase within the $60 million range for several years, and then it will reach over $100 million by 2046, and then over $300 million by 2048, over $400 million in 2052. Okay. Follow-up? Again, just doing rough math here. If it is a 70/30 equity split and it is the equity on $46 billion, $46.2 billion, that comes to 13— $1.5 billion and change on the equity.

By 2062, it's $5 billion in profit. That's about a 38-37% return on equity in those out years. Does that sound about right? Senator Bulkowski, through the Chair, I'd have to run the numbers and get back to you. Okay.

Thank you. Other questions? Senator Clayman. Just for clarity, the period of time for the total tax $466 million is what time period? Senator Clayman, through the chair, so that was a calendar year 2062 assumption, which is the very last year of our modeling time horizon.

Thank you. And again, we assume the 10% rate of return over a 20-year operations period where debt would be paid. And then Beyond that is really an extrapolation.

Very good. I see no further questions.

All right. Slide 33. This is our break-even matrices that we had presented previously under current law and bills introduced, and then we added in the— the Resources Committee substitute. This shows, given that the entire— that the full project proceeds on our assumed timeframe, under each of these tax schemes, what would the breakeven cost of supply be needed for in-state gas for the— assuming that the developer earns that 10% rate of return. And so we show in our baseline capital expenditures and with different increments of potential increases to capital cost and then of our baseline of $1.50 per 1,000 cubic feet gas purchase price and then different scenarios there.

So the— the end state— the break-even for the end state cost of supply would be slightly lower than current law but higher than 280 as introduced.

Not seeing any questions. All right. And then slide 34 is the similar matrix for the global breakeven price for LNG into the market. And we see here that the, the cost of supply for Project breakeven would be very similar under this bill as current law under the baseline assumptions and a little bit higher than SB 280 as introduced. Yes.

Very good. All right, so some conclusions, slide 35. So again, Alaska LNG Project has the potential to provide significant amounts of revenue for the state, for the federal government, for local governments, as well as beyond the strict revenue impacts, there's economic impacts, energy security. The introduced version of the bill would materially decrease the cost of gas and make the project more attractive to the investors. The bill currently in front of the committee would be a slight tax decrease initially.

It would be a slight tax increase over the life of the project, and it would basically have a very similar cost of gas and competitiveness in the market compared to current law. And then one thing to note with the tax caps on cost of supply for in-state for in-state consumers, this version of the bill would almost certainly preclude an in-state only pipeline. So the economics of building the project, if you don't go forward with the full project and just have the in-state pipeline, that would be extremely challenging under this project. So it would basically be an all-or-nothing decision for the developer. And that's— what we had concluded before.

If all that was built was the pipeline and then suddenly stopped there, we would be stuck with a very expensive gas supply. Um, Senator Wielekowski, if we, um, if we adjusted that number to, um, to say $7.21 and assume that there would be 100% cost overrun, that presumably would not preclude an in-state gas line, would it? Senator Wielechowski, through the chair, I assume you are looking at slide 33? Yes. And I'm going down, see version G, 100%, $7.21.

If we were to adjust that $5 to say $7.21. Sure. So Senator Bullockowski, through the chair, so slide 33 represents the breakeven in-state gas price assuming the full project goes forward. So these in-state gas prices are benefiting from the economies of scale of having the full project. So having the full project in place significantly reduces the cost to to in-state.

And in the other follow-up presentation, I have some additional slides that look at the in-state only option and what the costs around that would be. Follow-up, Senator Wilkerson. And my recollection is that we were told there would be $12 with just Phase 1. And that is what our— so that is what our— I mean, you are referencing this and saying it almost certainly precludes an in-state only pipeline. For the in-state portion only, we had said a $12.

On that number. Sure. Senator Wilkowski, through the Chair, and thanks for the opportunity to provide a little bit more clarity on that number. So when I had previously spoke with the committee, I had given some estimates around cost for a Phase 1 only based on previous modeling. This was based on the fall 2025 version of our modeling, had some different assumptions around capital costs as well as was including the the Great Bear Pantheon as a source of supply, which reduced the cost of the gas input.

Um, and in that I referenced that, uh, the in-state break-even price for a Phase I only would be $12.52 under current law and $10.72 under, uh, the bill as introduced. An important caveat to those numbers is that is a weighted average price. And that's a weighted average between an assumption of a lower price for a baseload industrial consumer and then a higher price for utilities. And so the— those would not be the utility-specific numbers. Those would be the weighted average prices.

Now, those numbers updated for the spring forecast, which I have in the other presentation, those are a little bit higher. Under the spring assumptions, and that has to do with— we've slightly increased our assumptions around capital costs for Phase 1, and then significantly, we added in that assumption that gas processing would be required under Phase 1. Gotcha. Gotcha. So we can go to those slides.

They're in the update. Am I correct? Yes, Chair Giesel, I believe we've provided that to the committee.

Yes, okay, Senator Clayman. Going back to your conclusions page, on the second-to-last bullet you said it would— say it would not make material decrease the cost of gas provided or make the project more attractive to investors. The follow-up question is, would it make the project less attractive to investors? Senator Clayman, through the Chair, I would defer that to the project developer.

Follow-up? So you actually have no opinion on that particular—. Senator Clayman, through the Chair, so I have heard that yes, it would make this project significantly less attractive compared to the bill as introduced, and I would leave that to them to make a definitive statement. Okay.

All right, I see no other questions. Why don't we go to your updated slide deck, which is dated today, of course, and it's titled DOR Response to Senate Resources Committee.

Thank you. All right. So this next presentation, these were some questions that we had when we presented the original version of the bill to the committee on April 13th and 14th.

And so this first slide just shows you.

Lays out the various questions that we responded to. So we do have a written response that goes along with this as well. I put it in slide form to be able to come here and present it.

So the first question, we were asked about the percentage split of state versus local revenues in the 2015 Municipal Advisory Gas Project Review Board report.

As far as we could tell, that report itself did not establish a fixed percentage for the split between state and municipal revenues. There were some significant payment in lieu of taxes associated with that project, $800 million during the construction period and a little less than $16 billion over the first 16— or first 25 years of operations. We didn't see— and those would be in lieu of the existing property tax, but we didn't see a fixed percentage of how those would split between state and municipal.

I see no questions.

All right. And then the second question was— ah, this great question of at what tax rate would the Department assume that the project would no longer move forward? And so we did have an assumption in the initial version of the fiscal note that there would be a positive revenue impact. That was a modeling assumption, not a definitive prediction.

These are good questions, and we would defer that specific question of at what point does the project go/no-go, we would defer that to the project operator. Subsequent versions of the legislation have had many other provisions other than just the simple alternative volumetric tax. And so our plan for future fiscal notes is to do an indeterminate on the front of the fiscal note and then work through a discussion and analysis of the revenues.

I see no questions.

All right, and the next question was to provide a year-by-year state property tax revenue under current law and under the alternative volumetric tax. And so we have provided the numbers in detail here. I know I referenced some of them, uh, in committee, but we put them here in, in writing.

Very good. I see no questions.

And then the next question was about that assumption of zero oil impact on Prudhoe Bay oil production. That is a significant assumption to our upstream analysis and an area of uncertainty. And that was based on an analysis that BP presented to the Alaska Oil and Gas Conservation Commission back in 2015. They indicated cumulative oil impacts of a major gas sale of less than 300 million barrels. The assumption from AGDC is given given that we're a decade further along in this process, that those oil impacts would be lower.

And so that's how we came up with this simple assumption that there would not be a change to Prudhoe Bay oil production. And we have included an attachment to our committee response, I believe, that is a redacted version of that BP analysis that was presented to AOGCC. We certainly have the capability to model additional scenarios and sensitivities around oil impacts at Prudhoe Bay.

Very good. I see no questions.

All right, and the next request was to remove the dotted lines, the dashed lines, and we have done that.

That's the most response I've ever gotten from an agency. That's amazing. Thank you. Now, I agree, Senator Dunbar. I agree those were confusing.

And somewhere along the line, someone had asked us to add that for an additional piece of information. And, um, all right, no one on our team had a problem with getting rid of that dashed line. Very good. Any questions on slide 7? All right, so that was slide 7.

That was also slide 8. Um, the next question was to provide an estimate of the producer's profit per 1,000 cubic feet. And so the gas being sold into the project, um, a lot of those costs of developing the, the fields are— those are historic sunk costs. And so the incremental costs, even at $1.50 per, per 1,000 cubic feet, those incremental incremental revenues to the producers would be significant. So we're estimating an average— or in real 2026 dollars, an average of $1.05 profit to the producers per 1,000 cubic feet.

That represents the additional revenue less those assumed upstream costs. And if we exclude the oil revenue entirely and just look at the additional costs and the revenue only associated with gas, that works out to $1.82 per MCF. And these are assuming the $1.50 sales price. Thank you. Sorry.

Senator Wilkowski. Thank you. Just at what price are you basing this? Is it $1.50? Senator Wilkowski, through the chair, that's correct.

$1.50 In real terms. So just so we're clear. So this is— so you're expecting the producers to sell for $1.50. They'll make $1.05 per MCF profit, meaning it costs them $0.45 to produce it. Accurate?

Senator Wielekowski, through the chair, so the first number also incorporates additional oil impacts. So it looks at the total additional profit to the producers from oil and gas related to the additional upstream spend that we're assuming. The second number, the $0.82, that looks at just the gas profits. Excellent. Follow-up.

Is this just a slope-wide average? Is this the average at Prudhoe? Kaparik, Alpine, Point Thompson.

Sure. Senator Wilkowski, through the chair. So this is based primarily on Prudhoe Bay and Point Thompson. We've developed a non-confidential set of public information-based assumptions to look at— yes, we've used kind of slope-wide averages to set a baseline for tax analysis, and then we've layered on the additional gas sales revenue and an assumption of additional investment that we've developed with AGDC. Follow-up?

This is fantastic. This is a great slide, and the next one is great as well. And I think it just goes to show that there's extreme great profits to be made by the producers. And I know you're going to get the next slide, man. I'm going to have to hop out.

I got a bill hearing. But we're looking at 83% internal rate of return on the next slide. And I guess I don't know how to factor this in, but at some point maybe, maybe that number is more like 75% or 70% internal rate of return and the producers kick in a little bit so that the state doesn't have to bear the full brunt of tax cuts, which we really can't afford. Sure. Yeah.

And Senator Wilkowski, through the chair, again, to reiterate that part of that calculation is the fact that a lot of the foundational capital expenses, Point Thompson has been developed, and so there would not be— some of those costs have already been incurred. The other, the other observation before I get to the question is that this project shifts a lot of the risk to the midstream developer, and that's part of why the focus has been on those midstream developer costs. So the producers our assumption is they are just selling the gas at the wellhead, and all of the risk beyond that is with the midstream. Follow-up. Could we get— could you provide us with information on how much tax credits and lease expenditures have been incurred at Point Thompson?

Because I know you're like— you've said a couple times now, well, the producers have already spent this money at— on these sites and at Point Thompson. But the reality is that Point Thompson in particular, they wrote off massive, probably 80% of the costs under ACES. And then under Senate Bill 21, they're writing off all the additional costs of their existing taxes. So my— I would venture to say the state has subsidized Point Thompson probably to the tune of around 80% of the total costs. So I'd be very interested in getting the lease expenditures, the credits that have accrued based on Point Thompson and at Prudhoe Bay, quite frankly, as well.

Yeah, so Senator Wilkowski, through the chair, so our current determination at Department of Revenue is that we can't provide the Point Thompson-specific lease expenditures and credits. It's a lot. Senator Myers. Thank you, Madam Chair. So looking at— we'll just narrow it down here.

We'll go with that 82-cent number you got in front of us. Is that before or after royalties and production tax? Senator Myers, through the Chair, after. So what we did is we looked at, at the end of the day, How much additional revenue do the upstream producers get versus how much, how much additional expenditures are they incurring? And it's a simple— plug it into Excel and do the IRR formula on that string of numbers.

Okay, thank you.

Senator Dunbar. Thank you, Madam Chair. That was a great question by Senator Myers. So this is after royalties have already been paid. $1.05 From a $1.50 sale, you know, colloquially people don't usually use the term internal rate of return.

They use terms like profit. Is it fair to say this $1.50— $1.05 is the profit from a $1.50 sale? And if so, that's a about a 66% profit.

Sure. Senator Dunbar, through the chair, and again, the dollar— the $1.05 also includes profit from oil sales that are associated with the project.

Okay. No, that's fine. Thank you, Mr. Yes. Our modeling shows that the AK LNG project would be significantly profitable for the upstream producers.

Good. Good to know. Good for—. All right. I see no other questions on number 9.

How about number 10, committee members? Any questions? Sure. And slide 10 takes those— as we were talking about, takes those previous numbers and calculates an internal rate of return. So these are very strong internal rates of return according to our modeling.

And again, just to caveat some of the assumptions around this, that zero oil production at Prudhoe Bay is a significant assumption. So if there were to be significant negative impacts to oil production, that could impact these returns. And again, the returns exclude previously incurred development costs. So it's not a full life cycle return. It's really a return from this point forward for the incremental.

Investment.

Very good. Moving on to 11. All right. And we were asked about those incremental lease expenditures, and so slide 11 represents those assumptions around incremental spending by the producers on the North Slope. Again, these have been— these assumptions have been developed in consultation with AGDC.

So you see some significant capital investments, in particular Point Thompson, early in the project for those expansions. We are— we do have some later capital expenditures. I know 2038 represents kind of an initial— an additional phase that we're assuming at Point Thompson, and then some additional drilling in the, in the 2040s. And then the— those stable numbers at around $200 million per year in most of the years, that represents kind of an ongoing operating cost and overhead to some associated with those increased activities. Very good.

Questions? Yeah, thank you, Madam Chair. Senator Rauscher. Thank you, Madam Chair. So the 2038, where do you get the information to say there will be additional phased drilling for that particular year?

It just seems weird that you can come up with that particular year at that particular amount. Sure. Senator Rauscher through the Chair, so this was a profile that was developed in collaboration with AGDC.

Whether it's all in 2038 or if it's spread out over some other years, but the idea that there would be kind of an initial investment in Point Thompson to bring on the major gas sales and then a decade or so on down the road, there would be another round of drilling or significant investment. Okay. All right. Thank you. It's not that it will happen in 2038 and not 2037 or 2039.

Thank you. Senator Kawasaki. Yeah, I'm just trying to get clarification on the question that Senator Wilkowski had as far as finding out how many lease expenditures and how much was paid. And then you said that— what exactly did you say, that you weren't allowed to release that information? Sure.

Senator Kawasaki, through the chair. So we, you know, as you know, we take confidentiality very seriously. At one point, we were releasing some information related to Point Thompson. We have not been releasing that information for several years now across multiple administrations. Basically, there are not— so we have the authority to release certain information where there are 3 or more producers and taxpayers.

We have deemed that there are not 3 or more significant taxpayers at Point Thomson to release that detail. Follow-up? Yes, follow-up, Senator Kowalski. So I was here in the 2006 timeframe when this lawsuit started and development was to occur and there was a big multi-year fight. And then I was here when the settlement happened during the Parnell years.

So I mean, wasn't some of that data supposed to be just proof that it was actually happening? I mean, wasn't it? I mean, I have to look at the case again, but it seemed like part of that was just, that we're progressing with these leases, that's why we're not taking— that's why the state's not taking the leases back. It seemed like there was like a process that was delineated and that Judge Gleason said you need to show that you're actually performing the work. And so I'm curious why that data would not be available to the public to know that it's actually happening.

Sure, Senator Cowasacki, through the chair, so I'm not intimately familiar with the Point Thompson settlement and litigation. As far as, you know, you know, the requirements to develop the field. The field is developed, it is producing, and it is expected to be a significant source of gas into the AK LNG project. My understanding is they are meeting that agreement.

So I guess that's true. I know that they're developing. We got to fly up there. I remember we flew up there and hung out in the bear cage waiting for bears to show up. Um, but I also wanted sort of an answer to the question about how much the state had to put forward on those.

And I guess, I mean, I, I guess if we're— that's taxpayer confidentiality. It kind of blows my mind because we know there's an outlay, we know we've paid for them, we can see that we've paid for them because we didn't take them into the treasury. So Sure. Yeah. Yes, Senator Bullockowski, under—.

It's all right, I was channeling him actually in the question, so I get it. Senator Kawasaki, so under ACES, we can speak generally under ACES, um, this— there was a very high marginal tax rate, and the flip side of that was that there was a very high marginal tax benefit to making investments. And so if there are multi-billion dollar investments under ACES, there is a very significant tax benefit. And yes, those tax benefits sometimes got to 80% or more in certain cases. Thank you.

Senator Dunbar. Yeah. Another way to say that is the people of Alaska basically built Point Thompson. So through their tax revenue. I want to just briefly touch on Slide 9 again.

I just was trying to remember, the max throughput is 3.5 BCF, is that right? Senator Dunbar, through the chair, yes. So we assume at full production, 3.5 BCF throughput into the gas treatment plant, which results in a little over 3 BCF of exports. So 3— so they're selling 3.5 BCF at $1.50 per and making one 0.05. So if my math is right, your estimate is that the producers will make about $3.85 billion in after-tax profit per year when this is up and running.

Senator Dunbar, through the chair, it's, uh, it's a significant, uh, increase in, in revenue to the producers. It's great. It's good. Um, it puts, it puts some other things into perspective, like the— like Governor Dunleavy's proposal to raise $30 million to pay for the Dalton Highway, for example. $3.85 Billion in after-tax profit, after-royalty profit per year.

That's great, and I hope they earn it, and I hope we build this pipeline. Thank you, Madam Chair. So we, I think, are on slide— no, we're on slide 12. Sure, yeah, so slide 12 is the, the flip side of slide 11. So slide 11 presented our estimate of incremental lease expenditures, and then slide 12 represents the impact of those lease expenditures on production tax.

This accounts for the ability to deduct those lease expenditures against production tax under current law.

And then slide 13 nets those— adds in the incremental revenue from the AKLNG project. And so you can see our— in, in the dark blue is our baseline spring 2026 official production tax revenue forecast, and then the blue bars show the incremental impact of the AKLNG project and related revenues. And so you do see that in the first 4 years, there is a slight reduction to production tax revenues, but then beginning it once the project has full operations, it's a material increase for the foreseeable future. Yes, Senator Dunbar. Thank you, Madam Chair.

Those boxes, those empty boxes,.

About how much money is that? I mean, I can see it there, but can you give us the exact numbers, 29 through 32?

Sure. Senator Dunbar, through the chair, I will follow up. I know we have those exact numbers. In a table, so I would be happy to just give those to the committee rather than trying to eyeball them. That sounds good.

Any other questions on slide 13?

All right, going to slide 14. All right, and slide 14—. Oops—. We were asked What is the per MCF, per 1,000 cubic feet price to the consumer for gas paid? And we looked to figure this out, we looked at— Instar has some really useful public information out there.

They, they show their gas, their gas costs and their prices. So their commodity charge, there's no markup on that. So whatever they buy costs for is passed on to the consumer. They get a regulated return on their delivery cost. That works out to $3.67 per MCF currently.

We inflate that to 2033 to get about $4.36 per MCF. So anytime you're looking at a cost of supply for in-state use, you add the $4.36, and that'll give you a rough estimate of what the, the cost to end consumers would be. So, Mr. Stickel, if it's winter and they're drawing out of storage, there's an additional cost for storage. Do you happen to know what that is? Chair Giesel, I don't.

Okay, we can see if we can find that out. Other questions on this slide?

All right, thank you for looking that up, by the way, the delivery cost. I had meant to do that and Never got to it. Yeah, it's a good, it's a good heuristic of a little over $4 for the delivery. Yeah. So the next slide, we were asked to run some state corporate income tax scenarios and look at the estimated impacts to the state.

And so we've laid out here average annual impacts for different time periods as well as the total impact for life of project if we assume that all upstream pays corporate income tax, and then if we assume that all midstream— the midstream pays corporate income tax, and then the addition of those two. So this is the impacts of that pass-through entity tax that's part of the bill.

Very good. I see no questions. I'm going to pause here and ask the committee— there are a few more slides. If you are willing to continue through them. All right.

Yes, we will continue. So are we to slide 16? We would be on slide 16. So we were asked to provide— and this goes to some of the questions earlier— a sensitivity matrix for in-state gas costs if only Phase 1 proceeded. And so to do that, we kind of start by laying out what are some of the assumptions that we put into this Phase 1 modeling.

So we are assuming only the in-state pipeline with an $11.6 billion capital cost. We are assuming $1.14 per thousand cubic feet of gas treatment costs under current law or 96 cents under the bill in front of the committee. Those Costs are assumed to be similar to the full AKLNG project. And again, that reflects the impact of needing to do gas treatment now that we're assuming that Great Bear is not a source of Phase 1 gas.

Slide 17 touches on the demand assumptions related to the assumption. So we're assuming that Phase 1 in-state demand for consumers would start at 15 BCF per year in 2029 and would gradually ramp up to 60 BCF per year by the end of the modeling period as the pipeline gas gradually replaces Cook Inlet production. It wouldn't come in and displace all Cook Inlet production on day one. We assume that the project would be anchored by a major industrial customer. That could be a restart of the Agrion fertilizer plant.

It could also be large data centers, in-state mining, some combination of those.

Madam Chair. Yes, Senator Dunbar. I just have to note, I think that means— because 3.5 BCF per day is the throughput, right? Or what is the— I'm trying to remember where the 3.5 BCF is. Sure.

Senator Dunbar, Through the chair, so the full AKLNG project assumes that at full capacity, there would be 3.5 BCF per day into the project and a little over 3 BCF per day exported. Then I have to just correct myself. My math, when I went back to slide 9, then was wrong, because I was thinking 3.5 for a year, but that's— it's 3.5 per day. Anyway, my math was wrong. Still very— still a lot of money, but I was wrong.

Thank you. Thank you, Madam Chair.

Yes, Senator Rauscher. Thank you, Madam Chair. I don't know whether this question is for you, but since we're really close to what we're talking about, what happens to Cook Inlet Gas? You said once this starts to replace Cook Inlet Gas, is what I heard. Cook Inlet Gas happen— what happens to it?

They— do they need to quit drilling now? Sure, Senator Rauscher, through the chair. So we have a We looked at a— there's a Cook Inlet gas study that was done by Department of Natural Resources. It's a few years old now, but it basically did a long-term projection of what is the shortfall in Cook Inlet gas production. And so the assumption here is that the AKLNG project would fill that gap.

Follow-up, please? And Cook Inlet production would continue. I mean, it's still there. They're drilling. When this pipe goes by them, what happens to them?

Senator Rauscher, through the chair, the assumption is that roughly a current— roughly a level of activity similar to current would continue, and Cook Inlet would continue production. Those fields have been declining in their production, and so the assumption is that the fields would continue production, and as they fall off, further decline in the out years that the AKLNG gas would fill in that gap in demand. Follow-up. So are they putting gas into the pipe? Senator Rauscher, through the chair, no.

What are they doing with their gas now that we have all this gas coming down from the north? So follow-up. Sure. Senator Rauscher, through the chair, the assumption is that Cook Inlet production would continue selling gas into the market. —Until those fields reach an economic limit.

They have existing pipelines that inject it into the Enstar system. So— This is a contract carrier that Glenfarn is building, not a common carrier. So not just anybody can throw their gas into the pipeline. Follow-up? Yes, follow-up.

So is the pipeline subsidizing at this point In 4 years?

The cooking, the gas? Senator Rauscher. So they are coexisting? Senator Rauscher, through the Chair, yes, they are coexisting. So we are assuming that there would be— there is roughly 65 to 70 BCF per year of gases used in South Central presently.

We are assuming that in 2029, an end state The line would deliver about 15 BCF of that, and that represents our assumption of the shortfall based on the current production. Follow-up? I just wanted to make sure that we understood what they're actually— how they're involved now. That's all, because it seemed— unless the question was asked, it was confusing on what they're doing in the middle after this happens. Thank you for asking the question.

And yeah, so Senator Rauscher, through the chair, the assumption here is that Cook Inlet production will not be sufficient to meet demand and something will need to be done, whether it's imports or some other source of supply. Follow-up, yes. Follow-up, Senator Rauscher. I understand that they're running out of gas, but they're not running out of gas in 4 years, and I just want to make sure that we're that whatever they are drilling for now is not for nothing. That is all.

That was it. Further questions?

Okay. I will let you proceed. All right. Excellent. So that was our in-state demand assumption is that we will come in with the 15 BCF for consumer demand and that will gradually wrap— ramp up to 60 BCF by the end of the modeling period.

50 BCF from the anchor tenant.

Pricing on Slide 18. So, we are— again, we are assuming that anchor tenant— we are assuming that they would pay a reduced gas price of $6 per 1,000 cubic feet. That is in 2026 dollars. And that that would be the lower price required to make those investments economic.

Now, that would be a lower— and then consumers would pay a higher price than the weighted average price. But still, consumers, given economies of scale, the consumer price would be lower than it would be without the anchor tenant. And that's why attracting an anchor tenant is so important and why it's valuable to provide an attractive gas price to that anchor tenant.

And these assumptions were developed in collaboration with AGDC. I see. Okay. And so that kind of lays the framework for slide 19, which is those weighted average in-state breakeven prices given Phase 1 only. So under current law, we assume $14.55 as the weighted average in-state breakeven price.

And under SB 2280 as introduced, it is $12.45. We didn't include the committee substitute here because, as I mentioned earlier, the phase 1 would not go forward under the bill as currently before the committee.

The phase 1 only. Senator Wielekowski. I'm sorry, next slide. Ah, Madam Chair. Okay, pause for a moment.

Senator Myers on slide 19. Yeah, thank you, Madam Chair. So, um, I wonder if the chair might indulge us slightly. So we've got Mr. Kissinger from AGDC in the audience here, and I believe he may have some interesting comparisons for us, uh, to to this slide, if we only did Phase 1, this is if we only did Phase 1, and my question is how does that compare to either what we're expecting for imports or what the price will continue to climb to if we just rely on what's coming out of Cook Inlet?

I'd like to have Mr. Stickel finish his presentation. Okay. So if you could continue. And we can always have Mr. Kissinger another time. Okay.

Sure. And to Senator Myers' question, I do have some numbers around potential import costs that might be a useful comparison. So to the final slide, which is slide 20, which gets to the question from the committee, which is what is the price to consumers? And so what we've done here is we've taken those Phase 1 breakevens and we've accounted for the fact that there's a baseload consumer that's going to receive the gas at a discounted price, which makes the whole project more economic. But then the weight— the price to utilities would be higher than that weighted average to offset.

So under current law, the breakeven price to utilities would be $22.70 per MCF under the Phase 1 only scenario. And under the governor's proposal, it would be $18.60 per MCF. And again, to get the final price to consumers, we would add the $4.36 for the distribution infrastructure to these numbers. Um, to the question about comparing to imports, um, we looked at a study by BRG that was done for, uh, InStar a few years ago. And extrapolated those costs to current dollars, that gives us a 2033 cost per 1,000 cubic feet of about $17 for imported gas.

Oh, pretty close. Mm-hmm. Questions? Senator Wilkowski. So just— maybe I'm just I'm not understanding you, but the previous slide was on in-state breakeven, the weighted average breakeven price.

You're saying this slide right here is probably what utilities are going to pay? Is that correct? Senator Bolkowski, through the chair, correct. So the weighted average is when we look at the breakeven price from the developer's point of view and a project economics point of view, which is originally what we developed the AKLNG modeling for. This slide 20 further breaks out that weighted average price into the $6 per MCF that is assumed to be charged to the baseload consumer, and then the higher price that would be charged to utilities.

So— So the number we've heard is that we expect gas to sell for is $1.50, probably. Base CapEx, that assuming $46.2 billion project. Which I don't think anybody thinks is going to be the number, you're looking at $18.60, add on another $4.36, so we're looking at basically $23 gas, like best-case scenario. Senator Bullockowski to the Chair, that would be if only Phase 1 proceeded and there were no full project under the Governor's proposal and our baseline assumptions. Follow-up, Senator Bullockowski.

I've heard utility executives say this could go sideways and in, and in years out could be $50 gas. And sure enough, here's, uh, getting pretty close to $50 gas. This is only in year 1. What does this look like? Does this have an inflation adjuster so that it goes up in 2034, '35, '36?

I mean, what do the numbers look like as you go out? Senator Wielekowski, through the chair. So this is a 2033 number, right? And so, yeah, the numbers would increase with inflation over time. Follow-up?

Is that a— like, what's your expected inflation going forward, 2.5% or—? Senator Wilkowski, through the Chair, correct. So we assume 2.5%, and we would use that same assumption for prices from the project as well as for any other comparison prices. Yeah. So— Follow-up?

Could you—. Do a chart projecting what the cost of gas would be under this going forward to 2062? Sure. Senator Bleakowski, through the chair, so it would be a flat line in real terms and then it would show 2.5% increases in nominal terms. We'd be happy to provide that.

Yeah. Yeah. I mean, When you stack on 2.5% over the years, these numbers get really big, really quick. And I don't know that this is cheaper than doing imported gas.

Again, Senator Wilkowski through the Chair, so about $17 would be the comparison price for imported gas.

[FOREIGN LANGUAGE] And that's better than your best-case scenario here. And the reality is you're looking at probably 20 to 40% CAPEX increase.

So, I mean, it's the consumers of South Central will be paying a premium for this project.

Well, and just to interject, Senator Wielechowski, we realized that long ago, that if it's only Phase 1, we're underwater, which is why it's so risky at this point. They can't get anyone willing to help fund Phase 1. No investors for Phase 1. But yeah. Anyway, Senator Dunbar.

Thank you, Madam Chair. Just because we're at the end of the presentation, I want to say I did the math again and I came up with like one— I just, I would ask the department to do it. I came up with $1.4 billion instead of the previous $3.85 billion. And if you could check my math at some point, I'd appreciate it. Yes, Senator Dunbar, we have through the chair, we have all those numbers.

We'd be happy to provide them. Thank you. Yes, Senator Myers. Yeah, thank you. I just want to compliment the chair on the seating arrangement.

If Senator Kawasaki and Senator Wielechowski were seated next to each other, it just makes the situation worse.

Very good. Yes. All right. Thank you, Mr. Stickle, for staying afterward as well and for having all this information at your fingertips. I appreciate it.

All right. So that concludes our meeting for today. The next meeting will be tomorrow morning at 9:00 AM. We're going to hear from Philip Rossetti. He's with R Street.

He'll be speaking about the Defense Production Act. Uh, and its potential implications. We will stand adjourned at this time. Let the record reflect the time is 5:17 PM.