Alaska Legislature: Senate Finance - June 8, 2026 10:00am

Call Senate Finance Committee to order. Today is June 8th. We're in Senate Finance Room in the State Capitol. Present today, Chairman Olson, Chairman Steadman, Senator Keele, Senator Merrick, Senator Cronk, Senator Kaufman, and myself, Senator Hoffman, we have a quorum to do business. We have one item on today's agenda, that being the Senate Bill 2001 Gas Pipeline Volumetrics Tax.

We're going to hear a presentation from the Department of Revenue. Providing an update on modeling and follow-up questions that were raised last week. Presenting today, we have the Chief Economist for the Department of Revenue, Dan Stickle. Please come forward. Introduce yourself.

And looks like you did lots of homework over the weekend. This is volumes of paper to follow our volumetric tax bill. Yes, sir. For the record, Dan Stickel, Chief Economist with Department of Revenue. So we did most of our homework.

So we've responded to some supplemental modeling requests from the committee from last week. We still have some additional follow-up questions that we will be providing in a written form hopefully later this week. Before we get started, I would I would like to recognize that we have 3 distinguished senators that are in the audience today. Senator Bjorgman, Senator Yunt, and Senator Myers. They have been with us since the bill started.

Welcome to Senate Finance. Mr. Stickle. All right. So there's a lot of slides in this request. It was volumes of analysis that were requested.

I will try to move through them fairly quickly. Slide 2 gives an introduction of the analysis that we are going to present. So this was all kind of based on the presentation that we delivered last Monday and the Friday prior to that in our overview presentation of Senate Bill 2001. Do want to note that we did revise that presentation and have submitted a revised version of that to the committee. There was a modeling issue in the version that we presented that had to do with how we were reflecting the allocation of Fairbanks Spur Line costs.

So in the slides that we presented on Monday, we were incorrectly allocating those across the entire project, including exported LNG, and we have now correctly reflected that to allocate the Fairbanks Spur Line costs over the in-state portion of the pipeline only, which is what's in the, the bill before the committee. And that model fix is included in all of the slides that we're presenting today as well that deal with Senate Bill 2001. So, and then these bullet points here at the top of the slide list out the various modeling requests that we received from the co-chairs. So there was a set of alternative project assumptions that we received We were asked to do modeling of our baseline assumptions with a $60 billion capital cost. We were asked to provide oil production sensitivities and price sensitivities on that as well.

We were asked to model a 10-year property tax deferral and a 10-year federal income tax holiday. And then we were asked to model alternative higher amounts of contributions to the Community Impact fund. And so we will walk through all of these in turn. I have also included for— as a reference in the appendix is a handful of slides that just summarize the baseline information for the presentation we gave last week. And so if anyone in the committee or at home wants to reference as we go through these scenarios, reference our baseline assumptions and modeling as a comparison.

We have that in the appendix at the end. Senator Steadman. Thank you, Mr. Chairman. I think just for clarity on the $60 billion, that is the mid-range number of the Phase 1 and Phase 2, which is $49 billion plus a 20% contingency. So that's important because most of the dollar costs that are reflected in the news media is without the 20% contingency.

And cost overruns start above the 22— or the 20% contingency. So the contingency does not include cost overruns. And we are looking at $60 billion And also I'd like to know, Mr. Chairman, I think Phase 2, which is the LNG liquefaction plant and the gas treatment plant on the North Slope, they're at a much lower level in their cost estimates than Phase 1. So they're a little looser numbers. So just—.

Thank you, Senator Stidman. Yeah. Mr. Stickle. All right. So moving on to slide 3.

So we start with a set of alternative project assumptions that were provided by the co-chairs. Those alternative assumptions are detailed on slide 4. So we have modeled an alternative scenario for both the full AKLNG project as well as the Phase 1 only project. Under 3 different fiscal frameworks, being if the project were to proceed under current law, the regular session bill is introduced, Senate Bill 280, or the special session bill as introduced, Senate Bill 2001. And so for this set of assumptions, we were asked to model a project cost of $59.4 billion, which is an upfront from $46.2 billion in our baseline analysis.

We were asked to model a 6% cost of debt, which is up from 5% cost of debt in our baseline analysis. We were asked to model a 30-year debt term for the pipeline and a 20-year debt term for the gas treatment plant and LNG facility. In our baseline modeling for the full project, we assume a 20-year debt debt term for all components of the project, and then in the Phase 1 only analysis, we do assume the 30-year debt term. So this scenario kind of assumes that the initial raise for debt would be for a 30-year term for the pipeline, and then there would be a subsequent raise for— on a 20-year term for the remaining components of the project, and all of that would be at a 6% cost of debt. And we were asked to model an 80/20 debt-to-equity split.

Split, which varies from the 70/30 in our baseline modeling. So those are the assumptions for the full AKLNG project. We also used a similar set of assumptions for the Phase 1 only, with an $18 billion capital cost for the Phase 1 pipeline. Again, the 60% cost of debt over 30 years and an 80/20 debt equity split. Senator Steadman.

Yes, and again, Mr. Chairman, just for those watching at home, on Phase 1, the $18 billion includes the 20% contingency because the numbers that are being reflected in the press is $15 billion. That's the difference. And if there's cost overruns, then that's a whole other calculation, but that's where the $18 billion came from. Do any other members of the Senate Finance Committee have questions on project assumptions? Seeing none, Mr. Stickle.

All right, moving on to slide 5. So this is our standard cash flow and cost of supply summary for the full project under current tax law, given these alternative assumptions. And so under this set of alternative assumptions, the breakeven LNG price into the global market would be $10.34 per thousand cubic feet, and that compares to $9.07 per thousand cubic feet under the baseline assumptions. So a pretty material increase to the, the— the delivered price of LNG that would be required under this set of alternative assumptions.

Slide 6 is the similar slide under Senate Bill 280 as introduced by the Governor. Under these alternative project assumptions, the breakeven price into the global market to get that 10% return for the investors would be $9.63 per thousand cubic feet. That compares to $8.48 per thousand cubic feet under our baseline analysis. And then on slide 7, which is the bill before the committee, the very LNG breakeven price would be $9.69 per thousand cubic feet, comparing to $8.54 per thousand cubic feet under our baseline assumptions. And so across the board, these, these alternative assumptions increase the required sales price of gas into the global market by a little over $1 per 1,000 cubic feet.

Senator Kiel. Thank you, Mr. Chairman. So a couple of these alternate assumptions help bring the cost of gas down, right? 80/20 The— it comes straight to mind.

The— and of course 30-year money on the pipe. The others tend to bring it up, capital cost and then 6% debt. 6% Only on the 30-year money or is that on the 20-year as well? Senator Keele, through the Chair, so we are assuming 6% for all the debt in this scenario. Okay.

Can you give just a certain order of magnitude sense of which of these things are the biggest elements, which of these things are the smaller elements in terms of effect on delivered cost of gas to Asian market? Sure, Senator Kiel. So those— I mean, it's really both of those assumptions are significant. The higher capital cost, so moving from 46 to 59, that's about $15 billion more capital cost. And we are— the 80/20 split does reduce the price required slightly, but then we're issuing that higher amount of debt, the 80% debt, at a higher cost.

So you're issuing more debt at a higher cost on a significantly higher capital cost for the project. Senator Keele. Thanks, Mr. Chairman. I'm—.

I understand the directions. It would be interesting to have a vague sense of this one is a quarter and that one is a dime. I mean, obviously these things are rough estimates and they are estimates on estimates, but worth sort of just trying to wrap my brain around. Thank you. Sure.

And Senator Kiel, through the Chair, so in our initial introductory presentation, we did provide some tornado charts where we went through several different assumptions and laid that out. And that is certainly something we have the capacity to do if that's helpful to the committee for any of these scenarios. Thanks. Thank you, Senator Keehl. Mr. Stickle.

All right, so moving on to slide 8, the next couple of charts are just our annual revenue charts that we've, that we've presented. Illustrating the annual revenues to the state under these various scenarios. So slide 8 is with the alternative assumptions under current tax law if the project were to go forward.

Slide 9 is under Senate Bill 280 as introduced if the project were to go forward. And then slide 10 And then the red line is under Senate Bill 2001 as introduced.

And so in all of these we see kind of that similar trend of some modest reductions to state revenue during the early years of the project as upstream companies in particular are making expected investments that will be needed to bring gas production online. And then once the full project is producing in fiscal year 2033, significant annual incremental revenues to the state under our— under this alternative scenario. And can you explain the significance of 2038?

Sure, Chair Hoffman. So what we've done here is we have a set of assumptions around required upstream lease expenditures that will be required to make additional investments in Prudhoe Bay and in particular Point Thompson to bring that gas online. And we're assuming that for Point Thompson in particular, there will be two rounds of significant capital expenditures. One will be in the very near term as additional wells are drilled and facilities are constructed to bring gas online. And then our baseline analysis assumes that there will be a second round of investment required about a decade further on for additional, additional drilling.

And we've put that additional investment— it's about $1 billion of additional investment that we've put in 2038 for modeling purposes. But sometime around that line, around that time, we would expect some additional investments to take place. Please proceed. So the next couple of slides walk through similar analysis with the Phase 1 only. So this is the scenario where the pipeline is built.

Again, with this alternative project cost of $18 billion for the pipeline with the 6% debt, 30-year debt term, and 80/20 debt equity split. So if this project were to go forward under current law and only Phase 1 were developed, we— here on slide 11, we're showing a cost of supply to break even for the developer of just over $20 per 1,000 cubic feet.

Senator Keele. Thank you, Mr. Chairman. So, Mr. Stickel, I'm having trouble lining this one up with anything in the previous presentation. And it could be because the alternate assumptions make such a colossal difference in this one. When I pulled back up the presentation from the Department of Revenue previously in the heat chart, and I looked at $1.75 gas, I just split the difference between $1.50 and $2.

You had columns for those, and I think the CapEx on that was $12 billion. This is $18, so I just kind of ran up to halfway between your plus 40 and plus 60. That's like— $30 in-state break-even instead of $20? Is it that big a difference to extend the term 10 years? $10 In MCF?

Sure. Senator Keele, through the Chair. So one, we've presented two sets of in-state numbers. So we've presented a— we started out with a weighted average statewide cost of supply, which is looking at the cost of supply required to break even from the project perspective, from the developer perspective. What is that cost of gas?

And under the baseline analysis, under current law, that was in the $14.55 per thousand cubic feet range. And so we see that increasing by over $5 here in this scenario to a little over $20. The other way that we've shown this, following some requests that we've had throughout the process, is to break out that total cost of gas from the developer perspective and to break that out into— we have one tranche of gas, if you will, that's being assumed to be sold to a baseload customer at a lower value, at $6 per thousand cubic feet, and then an additional tranche of gas that's assumed to be sold to in-state utilities at a higher cost. And I think that's probably where you're getting that higher $30 number in certain scenarios. Senator Keele.

So thank you, Mr. Chairman. Mr. Stickel, just to make sure I'm clear then, here on slide 11 of of this presentation, well, these 3 slides, you're looking at a weighted average assuming somebody comes in and gets a smoking deal, but this wouldn't be a price an Alaskan could expect their utility to get. Senator Kilcher, the chair corrects. This is what the weighted average in-state breakeven price would need to be for the developer to break even. If we assume that some portion of the gas is sold at the lower value to incentivize a baseload customer, and then the cost to— to Alaskan utilities for the remainder of the gas would be higher than what's shown here.

And so certainly under this alternative set of project assumptions, without a tax relief, it would be a relatively high cost of gas. And one thing, I guess one other thing to mention about this alternative set of project assumptions is we have used our baseline demand profile for all of this modeling, which for Enstate assumes a 65 billion cubic feet per year initial consumption, increasing over time to 110 billion cubic feet per year. What we've been hearing from the developer and AGDC is that they're actually targeting a higher level of in-state consumption, in the 180 billion cubic feet per year range. And so if you did achieve that higher level of in-state consumption than what's in our baseline analysis, that would move prices in the other direction. Senator Kiel.

Thank you. But as you talk to the developer, that's— and I apologize for these multiple units— 180 B's a year, that's 500,000 cubic feet per day, roughly. So that— when you talk to the developer, are they assuming everybody pays at this average price or do they share the assumption that you have in the revenue model— of very large customers at extra low price. Sure. Senator Kiel, through the chair.

So our initial baseline assumptions were developed in collaboration with AGDC. And so that's where the 65 billion cubic feet ramping up to the 110 billion cubic feet, that's where that was originally developed. Those assumptions were developed in prior years and then updated last fall. And that's where we assumed, yes, a 50 billion cubic feet per year of a baseload customer and a $6 price, and that was— that $6 price did come from AGDC. What we've heard more recently, just in the last week or so, is this target of 500 million cubic feet per day for in-state gas sales, and that that target could potentially support a gas price to Alaskan utilities of around $16 per thousand cubic feet in real terms.

And that's some of the information that's been presented by Glen Farn. So I thank you. All that detail is very helpful. Just in that very last statement, did that include differential pricing or everybody on the same price? Senator Kyl, through the Chair, I don't know.

Fair. Thank you. But just to point out that there is potentially a different demand assumption between what they are working off of versus what we've built into our modeling. Thank you. Thank you, Senator Keele.

Senator Steadman. Yes, thank you, Mr. Chairman. Along the same lines, I think the conversion— and I think this is important— the conversion they're using at JGDC at $65 billion a year, that's about 178,000 cubic feet a day, which just rounded off to 200, right? Say it's 200. And they want to get to 500.

The Donlin Mine is 30, I think, million cubic feet a day, if I recall. So that's, then you're at in the low 200s, 220, 230. How do you get to 500? That's a huge spread. And the timeframe it would take to get there.

So I have some challenges there when we get into the details of this as far as getting something that seems reasonably attainable if we're stuck with an in-state gas line as far as production. So could you help with that a little bit on— on those numerics of the growth? Sure, Co-chair Steadman. So several different options there. I know Donlin Mine is, is one potential option.

There's been talk of large-scale data centers in South Central. There's been obviously a lot of interest in expanding gas into the interior market, both for resident plants as well as potential military and industrial applications there. There's been talk of restarting a fertilizer plant in South Central. There's been talk of potentially doing small-scale exports by restarting the previous export facility. And then potential to take some of the existing consumption that's currently being filled by Cook Inlet production.

And I believe we have, I believe we have someone from AGDC online as well that might be able to speak to some of the sources of demand that they're considering as they target this 500 million cubic feet per day number. We do have two individuals online from AGDC. We have Frank Richards, the the president of the corporation, and Matt Kissinger, who is the commercial director of the Alaska Gas Line Development Corporation. Do you have questions for them, Senator Steadman? Well, it'd be nice to have a little more detail brought forward by AGDC on the 178 or 200 million cubic feet a day growth up to 500 in more detail.

Because anybody can just sit down and have a hypothetical and stick numbers in a model and say we're gonna magically double or triple our sales. It's a whole different ballgame, Mr. Chairman, to actually deliver it. Mr. Richards or Mr. Kissinger, do you have any comments on the 500 per day?

Hello, Chair. Yes, this is Matt Kissinger for the record. Senator Steadman, through the chair, if you add on certain things like starting the Nutrien plant, there are 4 different trains there, 2 trains of ammonia, 2 trains of urea. And so it depends on which trains you believe can come back online., as well as the potential for Keene LNG to export. And then we also do a risk view of the potential for a data center growth or some mine expansion and the buildout of Fairbanks demand.

We have different sort of risk scenarios that can go up to 500. And so I think it's probably best if we provide this in, in writing to the committee. That would greatly be appreciated. Further questions, Senator Steadman? No, I think when it comes time to financing it, they're gonna wanna have hard numbers to finance, not hypotheticals.

I mean, we're dealing with billions of dollars here, $14 billion in debt requests.

Senator Cronk. Thank you, Mr. Chair. A quick question. What would the cost be with the current daily use?

This is Dan Stickel again for the record to Senator Cronk through the chair. So currently, current daily use is in the $65 to $70 billion range.

Or 65 to 70 billion cubic feet per year range, which is just under 200 million cubic feet per day. So our assumption here of the 20— or the finding here of the about $20 breakeven price, that starts out with a total consumption of around what's being consumed in South Central currently. We do have that increasing over time in our assumptions with some growth. And so if that were to remain flat, then the overall breakeven price would be a little higher than the $20. Senator Cronk.

Thank you. Thank you. Please proceed, Mr. Stickell. All right. Slide 12 is the similar, similar slide, but under Senate Bill 280 is introduced, if the Phase 1 only proceeded with these alternative project assumptions, the breakeven cost of supply would be $17.12 per 1,000 cubic feet.

And then under slide 13, Senate Bill 2001 is introduced, it would be the $17.32 per 1,000 cubic feet. And one of the— One of the differences between slide 12 and slide 13 is that Fairbanks spur line requirement. And so the cost of the Fairbanks spur line is incorporated into that break-even price for in-state gas in slide 13. But that was not part of the regular session bill that was presented on slide 12. And so that difference That Fairbanks Spur Line in our modeling does add about 20 cents per 1,000 cubic feet to the in-state gas price.

Senator Steadman. And I'm still a little slow here, putting all these fancy things together, Mr. Chairman. But the Aggregum plant, I think, is further south than the termination point of Phase 1. So maybe AGDC can add that to their response. And then when they give us a list of the hypothetical future sales, I'd also like to see the range of potential prices of those.

Because Agrim, I know that business model for fertilizer needs low-cost energy, not high-cost gas, low-cost gas. The data farms want low-cost energy, not high cost. So I'd like to see the ranges because I assume that not everybody's going to be paying at the $16 cap that the Alaska residents are going to be at. So we can do a— get a rough blended or average rate.

That would be helpful. Mr. Chairman. And the data centers that I heard being discussed were up on the North Slope where it's much cooler and would not— would receive a much lower cost if data centers were built on the slope. Further questions on slide 13? Sir, and just to clarify, Mr. Mr. Chairman, that's a follow-up for AGDC or DOR?

AGDC. Yes. AGDC. Excellent. Please proceed.

So I have some of these state revenue charts. So slide 14 is the annual state revenues for the Phase 1 only under these alternative assumptions if the project were to proceed under current law. So you can see that the annual state revenues— would be, um, well, well over $200 million and then over $300 million per year, um, come the late 2030s, uh, with, uh, property tax on the $18 billion pipeline being the, the vast majority of that if the project were to go forward under current law.

Slide 15 shows the, uh, the similar chart under Senate Bill 280 is introduced by the governor. So significant reduction, replacing that property tax with the alternative volumetric tax, which would be zero for 10 years and then 6 cents per 1,000 cubic feet on just the in-state line. And then— Senator Steadman. When he's done though, I'd like— I have a question. Are you done with this?

With this slide, I was going to move on to the next slide, Mr. Chairman. Can we go back to 14? Just trying to keep all this information straight. And we look— it's easier to look, I guess, way out in hypothetical land as 2062 because it's the bar's easier to see. But that's 20 mils property tax or 2% of value.

Corporate income tax is non-existent. We get royalties and we get our production tax and the production tax. I need a little bit of help. We've got a 13% tax on gas. Or are you doing a— in your model, a barrel of oil equivalency and running it through in that regard?

How are you handling that? Sure. Co-chair Steadman. So in this In this modeling for the Phase 1 scenario, yes, we're assuming the property tax at the 20 mills, and then we are assuming state royalties and a 13%. It's a 13% gross production tax.

However, since all of this gas would be in-state, it would all be subject to the in-state gas tax ceiling. Of 17.7 cents per 1,000 cubic feet, which brings the effective tax rate down to less than that 13%. And that's why the production tax bar is a little smaller than the royalties bar. With 12.5% royalties, the effective gross tax with the tax ceiling ends up being something closer to 10%. Senator Steadman.

I think that's all well and good, and I thank you for that clarification, because it does get confusing. And I don't think any of us are grousing about the break for in-state gas tax at all, not even on the table, just for people at home. Also, the property tax is nonexistent through construction by current law, if I'm not mistaken.

Chair Steadman, that is correct. The modeling, the Phase 1 modeling based on some prior discussions with AGDC, we do, we did incorporate some assumption of a property tax payment in lieu of taxes, if you would, for the for the in-state pipeline. The property tax numbers here also include not just the direct property tax from the project, but also any property tax associated with additional North Slope development. Senator Steadman. What value are we using?

If it's 2%, what value are we using for what we are taxing?

The value of the line. Is it $18 billion or $65 billion? What's our gross tax number? If you can help me with that, I'd be—. Sure.

Co-chair Steadman, don't have that exact number off the top of my head. We'll be happy to provide that in our follow-up.

We do assume that some of the value becomes taxable property, and over time we assume that that is— that the value of the pipeline for tax purposes remains fairly stable, as we assume that inflation and depreciation will roughly offset over time, but we'll get the exact taxable value in our response document. My lifeline that would have that at his fingertips is unfortunately on call for the other body. Senator Steadman. And that's fine, because we— I don't expect you to be able to answer all these questions, and we're just working with these models. But if the pipeline here, we're looking at Phase 1, if it was valued at $18 billion, it would be $360 million which is about $100 million higher than the number here.

So there's obviously some form of a— it's not being taxed at $18 billion, it's some other number. And if you can just help the committee understand what the professionals think that number is going to fall out at, then we'll be able to correct our numerics on our side and it'll be helpful. Thank you, Senator Stidman. Please proceed, Mr. Stickell. Alright, and then we moved on to slide 15, which is the similar chart under Senate Bill 280, which is the regular session bill as introduced.

And as you can see, eliminates the property tax and then replaces that with a very small alternative volumetric tax in, in the later years. And then slide 16. Senate Bill 2001 as introduced, which is a similar-looking chart, slightly higher alternative volumetric tax in terms of rate and then in terms of inflation adjustment as well. Senator Keele. Thank you, Mr. Chairman.

So, Mr. Stickle, the For this in-state Phase 1 only concept, no drop, I guess looking back at slide 14 I should, I don't see a drop in production tax associated with major investments at Point Thompson or other gas infrastructure the way the export project. Is it the estimate that the volumes will consume in-state Nobody's going to have to spend more in the out years than they do just getting some gas offtake from Prudhoe in the first place. Senator Kiel, that's roughly— through the chair, that's roughly correct. So for our phase 1 modeling, we haven't identified an explicit source for that gas, but the offtake is the offtake assumed to meet our throughput assumptions is small enough that we we wouldn't see major new investments being needed in any of the fields. And then the production tax numbers that we are including here are all— it's basically the 17.7 cents per 1,000 cubic feet cap on gas times the taxable throughput.

Thanks. Thank you, Senator Keogh. Please proceed. I would just have a—. Senator Steffen.

Before we jump on to the full project when we really got lots of variables. Corporate income tax, it's not showing there because there's no profit to tax, or what happened to corporate income tax? Uh, Co-chair Steadman, so we assume that the pipeline developer is not subject to corporate income tax. That's our baseline modeling assumption. We have assumed that the Phase 1 supplier of gas would be not subject to corporate income tax.

That's a conservative assumption. Certainly if that gas does come from a corporate income tax eligible entity, I know there's been some announcements that that could potentially be the case, that would be a potential upside to the numbers in this chart. But under current organizational structure, isn't Glenfarn, not an S corp?

Mr. Chairman, so we have assumed that the pipeline developer would not be subject to corporate income tax.

Senator Steadman. It would be interesting, Mr. Chairman, if we could see at some point the year which this this hypothetical triggers into a taxable income event, which would be, you know, dealing after depreciation and interest costs. Just trying to get a feel for how sound this project is. Regardless if you pay corporate income tax or not, you have to have a net profit to pay a tax. So, and that would include even an S corp.

So it would be nice to see when that— those lines cross, because there's significant interest costs here and significant depreciation, no matter if you use the 7-year, which would be substantial loss carryforwards, or even a 20-year straight-line depreciation. In other words, it would be nice to see when the cash flow starts turning around. Thank you, Senator Sedgwick. Senator Kaufman. Thank you.

Yes, I'm just thinking out loud. So the Phase 1 will really— I keep thinking of it as a utility. So they're not producing the gas. The gas is put into the line. The gas is pressurized, charging all the way down to the other end of it.

So it's essentially a utility. It's a pipe full of gas. And I guess I would wonder, as a— really, if you think of them as the transmission part of the utility as opposed to the distribution part of the utility, for especially Phase 1, what's the right tax structure for something where, for whatever profits and all that there are, really the taxpayer is going to end up being the ratepayer, hence the need to keep that low at that point. The people producing the gas, they'll be paying it, you know, whatever royalties, production tax, etc., that they're due to pay. But I think for the pipe itself, it's just moving the gas.

Thank you. Thank you. Senator Steadman. Well, there's no property tax on construction, and then we're looking at modifying it after construction, and my understanding is the proposal pretty much has no tax until we do major exports. Even if we made zero property tax to major exports, I question the economics of what's in front of us.

But no property tax ever. That's how strained the project appears to look.

So Mr. Stickle, please proceed.

All right. So moving on to slide 17. So this next scenario was a request from the committee presentation from last week, and it was a request to model a $60 billion capital Capital expenditure scenario. So similar in total capital expenditure cost as the scenario that we just walked through, except that this next scenario keeps all of our other baseline assumptions unchanged. So the 20-year debt agreement, 70/30 debt split, 5% interest rate on debt, and other baseline assumptions, simply adjusting that capital expenditure from the $46.2 billion real up to $60 billion real.

So this scenario really looks just at that capital expenditure change and what the impacts of that are. So slide 19 shows the current tax law analysis with a $60 billion capital expenditure. This would result in a breakeven LNG price into the global market of $10.69 per thousand cubic feet. That compares to $9.07 per thousand cubic feet under our baseline assumptions. So a move of about $1.60 just from increasing that capital cost assumption really highlights the importance of of that capital cost assumption.

Again, this is under the current tax law scenario. Slide 20 is the similar analysis under Senate Bill 280 as introduced. Moving to the $60 billion CapEx increases the breakeven cost of supply from $8.48 under the baseline up to $9.91 per thousand cubic feet. And then under Senate Bill 2001 as introduced on slide 21, that would be $9.97 per 1,000 cubic feet, which again compares to $8.54 under our baseline assumptions.

The next slide is— set of slides is the similar revenue charts as to what we just walked through with slide 22 being The current law scenario, slide 23, being the 280 as introduced, and then slide 24 being the current bill before the committee as introduced.

And so the next set of slides is some analysis that looks at alternative oil impacts as well as some price sensitivities thereof. So this is going to be a fairly robust section of the presentation.

Starting with slide 26, kind of lays out the assumptions here. So our baseline AKLNG modeling assumed no impact to Prudhoe Bay oil production, and it assumed an increase to Point Thompson unit oil production of 270 million barrels total over the life of the project. And we have developed— we've provided some alternative scenarios for the impact of gas development for both Prudhoe Bay and Point Thompson with a range showing potential oil losses at Prudhoe Bay and then potential for less oil increases at Point Thompson. And the slide Here we built this starting with some information that we had presented in Senate resources.

And in the slide deck, we actually don't have producer rate of return slides in this presentation, but we do have slides looking at upstream state revenue and total state revenue under a range of different scenarios.

So slide 21. 27 Walks through some assumptions.

So we actually— this section had a lot of slides, so we've actually pared it back a little bit for what we've presented to the committee. I think we had something like 100 working slides and tried to pare it back into something a little bit more manageable. And so we're just showing current law and Senate Bill 2000 and and one. Under our— we use our typical baseline assumptions of $1.50 unprocessed gas price. In terms of gas production, the baseline modeling has about 2.2 billion cubic feet per day coming from Prudhoe Bay and about 0.7 billion cubic feet per day coming from Point Thompson.

And then some additional gas coming from an unidentified source for Phase 1 that we do assume continues into Phase 2. For our production profile sensitivities, these are fairly simplistic scaling of the production profiles that we've done, and just to disclaimer that if we had an advanced petroleum engineering analysis,, the profiles would look a little bit different. Um, the broad conclusions should remain.

Slide 28 shows our, uh, gas production assumptions in the, the baseline modeling. Um, so again, about 2.2, uh, billion cubic feet per day coming from Point Thompson, or from Pudó Bay, and about 7.7 billion cubic feet per day coming from Point Thompson. Once we get into the 2050s, we do— the baseline modeling does assume that the Point Thompson production will start to show declines and that that will be offset by Prudhoe Bay production for a period of time. Once we get out into the later 2050s, there is going to be a need for for additional gas. That is so-called yet-to-find gas, but that's a— we have not modeled out the revenues associated with that.

I think there's lots of activity and exploration going on on the slopes. I think there's a lot of optimism that that gas will be identified once we get to 2050. The other line here is, as I mentioned, we do have a Phase 1 gas source that originally we built that, originally we modeled that based on potential for Great Bear Pantheon or a similar field. At this point, we've left that unidentified, so certainly hope that Pantheon would come to fruition at some point during this time horizon. There's been talk of potential gas from, from North Star or from Prudhoe Bay Point Thompson or other fields.

Senator Kaufman, thank you. That was just the point that I just want to— it's not like unidentified. We don't know where prospects might be. There's, there's definitely some known reserves that have yet to be developed or yet to be freed up for use. Thank you.

High expectations. Please proceed. All right, so slide 29 starts to get into the meat of this analysis. So we start with Prudhoe Bay unit here. So we've laid out 5 scenarios in the, in the chart on the left.

So what this represents is the change in total So the lines show annual oil production that are assumed in the modeling, and then the 5 scenarios represent the total change to oil production cumulatively over the life of the AQLNG project. So on the top, in the, I guess, purplish line, is our baseline assumption for Prudhoe Bay oil production with no oil losses, and then we ran up to a 500 million barrels of oil losses in the red line, and then 3 intermediate scenarios as well. So there was a study that was presented in the Resources Committee where Department of Energy had estimated that the LNG project could reduce oil production from Prudhoe by a little over 450 million barrels total. And so that's where we developed the 500 as a nice round number to illustrate kind of a worst-case scenario there. And then again, the range of intermediate scenarios as well.

Slide 30 is a similar analysis for the Point Thompson Field, again, with the purple line representing our baseline for oil production from Point Thompson with— zero is without the AKLNG project, what we anticipate Point Thompson production would be. And then the red line is our baseline oil production from Point Thompson with the AKLNG pipeline. So the baseline modeling assumes a total of 270 million barrels of additional production from the field at as the significant additional development to bring the gas online brings on additional oil as well. Now that scenario and those production assumptions were developed collaboratively with Department of Natural Resources in 2018 and 2019 based on the best information that was available at the time. Since then, we have had new information as the field has continued producing, and there has been testimony from, from Alaska Oil and Gas Conservation Commission, which was before this committee last week, and they are now saying the performance of that field has not been as strong as was hoped, and there's been some technical issues with the performance, and now they are looking at potential for a technical recovery from Point Thompson of around 100 million barrels of oil oil.

So far about 20 million barrels have been produced, and so that would imply potential— potentially 80 million barrels of oil left that could be technically produced, and how much of that is economic would be a lesser number than that. And so that testimony from AO GCC really implies a lower incremental oil production from Point Thompson than what we've baked into our baseline modeling. Probably something closer to the 67.5 million barrels of additional oil production scenario. And so, what we've presented in the modeling is kind of the two goalposts being the full 270 that's baked into our baseline modeling and a zero incremental production from Point Thompson and then three intermediate scenarios.

Scenarios. Mr. Chairman. Senator Steadman. Mr. Chair, if I may.

Senator Kiel. Thanks, Mr. Chairman. Mr. Stickel, I think I forgot to ask AOGCC, maybe you know, when we talk about Point Thompson, are we talking about barrels of crude oil or are we also including the liquids, the gas liquids? Sure. Senator Kiel, through the Chair.

So my understanding is that when they look at maximizing recovery for the field, they're looking at barrels of oil equivalent. Broadly, when we are modeling out production, we consider natural gas liquids that flow into the oil pipeline as oil. So for purposes of royalties and tax, those are essentially the same product. I know AOGCC does, does track and manage those differently. Senator Keel.

Thank you, Mr. Chairman. Thank you, Senator Keel. Mr. Stickel. All right. So slide 31 is a heat map chart of sorts looking at oil impact sensitivity, and we'll have several slides like this.

And so, what we've done here is on the— on the top, on the horizontal axis is we've laid out our 5 scenarios for Point Thompson incremental oil production ranging from the 0 to the 270 as the 2 kind of sidebars. And then we've laid out on the vertical axis our 5 scenarios for Prudhoe Bay incremental oil production ranging from the zero down to the 500 million loss. And so, on the top right is our baseline scenario, which is going to be the 270 million barrels additional production from Point Thompson and the zero oil impact at Prudhoe Bay. And then on the bottom left is kind of the worst case scenario with zero incremental Point Thompson production and a 500 million barrel loss at Prudhoe Bay. And so, looking at these scenarios, there's a total of 25 different production scenarios that we can look at.

On top of that, we had 3 different price scenarios, so we could have a lot of slides. What we've done for the— when we get into some of the detailed slides is we've basically shown the 2 goalposts of of the baseline assumptions and then the worst-case assumptions, and we're happy to provide detail on any of those to the committee. But what this shows is under all of our baseline assumptions, upstream oil and gas incremental revenues— this would be taxes and royalties and property tax paid by the producers— we assume $22.2 billion of incremental upstream revenue over the model time horizon. And in the worst case, that drops to $6.9 billion. So still positive, but not as much as in the baseline.

Please proceed, Mr. Stickle. Slide 32. So the upstream revenue that we showed on slide 31, that analysis is the same under any of these, under current law or the two bills introduced by the Governor, because those don't impact upstream fiscals directly. What slide 32 shows is total state revenue, and this is where the— including the midstream, which is the taxes from the pipeline from the AK LNG project. And so you do have a different analysis under each of the three bills.

So including the midstream, if the AK LNG project were to proceed under current law, the range of potential revenues to the state would range from the $29.7 billion down to $14.4 billion in, in the worst case. And under Senate Bill 2001 as introduced, That range of state revenues would range from $22.8 billion in our baseline down to $7.5 billion over life of project in the worst case.

So the next couple of slides look at some price scenarios. We were asked to look at price sensitivities by the committee. So our official price forecast is for a $75 oil price in the next fiscal year, with that decreasing to about $70 later in the decade. Looking out over the next 10 years, our average oil price is around a little over $71 per barrel. And so for sensitivities, we picked two sensitivities.

We picked a $60 price and a $100 price. The $60 oil price represents a price that's a little bit lower than what we're forecasting and is a situation where most of the upstream producers will be in a minimum tax floor situation in the forecast. The $100 per barrel scenario represents something closer to current prices and would be a situation where most of the producers are in a net tax situation for the production tax. And so the impact of that net versus gross tax is significant when it comes to running these price scenarios. But anyway, starting with slide 33, it's the same heat map chart looking at the upstream oil and gas revenue at $60 per barrel oil price.

And under that scenario, we would be looking at about $22.7 billion of upstream revenue under our baseline analysis, and that would drop to about $5.9 billion over life of project in the worst-case production scenario.

Slide 34 is the similar heat maps for the three different tax regimes at the $60 per barrel price. And so under Senate Bill 2001 as introduced, when you include the, the midstream revenue, which would be the alternative volumetric tax revenue, that range of positive revenues to the state would be $23 billion under our baseline assumptions, and then that would drop to about $6.6 billion in the worst-case production scenario at $60 per barrel oil. And these oil prices are in real terms, so $60 real.

Slide 35 is a similar analysis but with $100 per barrel oil. And what we see here is at a higher oil price, the impact of lost barrels, if you had a scenario where Prudhoe Bay production was declining, the impact of those lost barrels is significant to state revenue, both in the reduction of value and the fact that at higher oil prices, when companies are paying under the net profits tax, we're getting a larger share of a larger pie. And so the The impact of, of a lower production scenario could be significant. And so at $100 per barrel, we expect in our baseline production scenario an additional $28 billion positive to the state of incremental upstream revenue. But then in the worst-case production scenario, it would actually be a $17 billion incremental a fundamental negative to state revenue.

Senator Keehl. Thank you, Mr. Chairman. Mr. Stickel, you may have said this, but I'm trying to keep all the variables in my head. As you vary the oil prices on these slides, what are you doing with the gas price? Senator Keehl, through the chair, we're assuming $1.50 real gas price in all of these scenarios.

And Senator Keel, if I may. So I know they're not one-to-one, but they do tend to move together as of some of the time. Is that correct? Is there a reason we don't see some movement along with—. Senator Keel, through the chair, said they can move together.

Brent. Is sometimes a benchmark that's used for pricing LNG. That would be an additional set of assumptions that we could layer on top. We could certainly run this with higher— we could run this at $1, we could run this at $2, any sort of range of gas purchase prices.

Mr. Chairman, I don't know if I need to see another model, but I guess Ordinarily, if gas goes up with oil somewhat, we're gonna see reduced losses in this scenario, but still potentially losses, and reduced benefit in the low-price scenario, but still benefit, do you think? Senator Kieltjer, the chair, yes, that's roughly correct. And you highlight, anytime we're doing, these models, there are lots of assumptions, and we're picking a couple of assumptions to vary here in terms of oil price and two oil production assumptions. And yes, we're holding all other assumptions equal to our baseline modeling. Senator Kiel.

Thank you, Mr. Chairman. Should—. I guess, Mr. Stickle, should I be sticking with the 6-to-1 ratio in my head, or is that just a really old old-fashioned notion. Senator Keel, through the chair, so in terms of energy equivalence, that's a good ratio. In terms of prices, it's usually a little bit higher than that.

Thank you, Senator Keel. Mr. Stickel. Slide 36 then looks at total state revenue. This would be all in change to state revenue with the AKLNG project at $100 per barrel oil under our baseline assumptions, except with the various oil production sensitivities. And so at $100 real, under current tax law, our baseline modeling is about $36 billion of incremental positive revenue to the state.

State. But then under the worst-case production scenario, that would be about $9 billion incremental negative revenue to the state. Under Senate Bill 2001 as introduced, in our baseline production assumptions, $29 billion positive revenue to the state. And in the worst-case scenario production assumptions, $16 billion negative revenue to the state. And so what this set of slides really illustrates is the importance of that production— those oil production assumptions to the modeling and the overall state economics, and then the importance of the oil price as well.

And again, our official oil price is for something in the $70 range.

So we were asked by the committee to put the annual revenues into a table form, and so the next set of slides shows a table form detail for a few of these scenarios. Slide 37 is our forecast oil price under our baseline oil production. Assumptions, and we break out the annual royalty and production tax for both oil and gas. And so you can see under our— under this baseline forecast, we have a couple years of negative incremental upstream state revenue. Again, those are associated with investments that are made in Point Thompson and Prudhoe Bay.

And then once the full export ports begin, we're looking at over $700 million per year of incremental upstream state revenue.

Slide 38 is a similar chart in our worst-case production scenario. And again, 25 potential production scenarios here. We picked 2 to show, to kind of set the— set the goalposts.. But under the— at the forecast oil price, again, in our worst-case production scenario, again, we'd see the 2 years of the negative incremental revenue as money is being invested in the fields. But then once LNG exports begin, it would be a positive revenue to the state.

In this case, in the first year of of full exports, it would be $330 million positive to the state and a little bit lower in later years.

Slide 39 is a similar chart at $60 per barrel oil under our baseline production assumptions. And we can see that the incremental upstream revenue to the the state under $60 oil is quite similar to what it is under our official revenue forecast. We assume a gross tax floor situation for the companies largely there, so there's not a whole lot of change to the upstream revenue between the official forecast and the $60 real.

On slide 40, this is the worst-case production scenario for the oil production, and again, looks fairly similar to the official revenue forecast in terms of incremental state revenue from from the the gas line project, this would be a positive to the state, which at a $60 oil price would be material to have that incremental revenue coming in.

Slide 41 is the first of our $100 per barrel oil scenarios. So this chart shows our baseline oil production scenario, and at $100, we actually have 3 years of reductions to state revenue during the early years as companies are offsetting that net profits tax calculation with lease expenditures. But then once full exports begin, the positive revenue to the state is more significant with over $1 billion per year additional production tax royalty from the upstream producers in our baseline oil production scenario. In the worst-case production scenario, which is shown on slide 42, at $100 per barrel oil, it would be a reduction to state revenue in most years under this worst-case production scenario, and that again has to do to do with just the value of those barrels, we're actually in this worst-case production scenario, we're actually forecasting that oil production will be lower than it would be absent the AK LNG project.

And so we have a few of our state revenue charts. Slide 43 is the baseline oil price with the baseline oil production scenarios and $29.7 billion of cumulative revenue through 2062. Slide 44 is the baseline oil price forecast and the baseline baseline oil production forecast under Senate Bill 2001 as introduced with $22.8 billion of cumulative state revenue.

Slide 45 is the worst-case production scenario under current law with $14.4 billion of cumulative state revenue.

Slide 46 is the worst-case oil impact scenario under Senate Bill 2001 as introduced at our official oil price forecast that generates $7.5 billion of cumulative state revenue.

Slide 47 is the $60 per barrel oil price with our baseline baseline oil production scenarios and current law, where we estimate $30.2 billion of cumulative state revenue over life of project.

Slide 48 is the $60 oil price with our baseline oil production scenario and Senate Bill 2001 as introduced, which generates generates $23.3 billion of cumulative state revenue.

Slide 49 is the $60 oil price with our worst-case oil production scenario and current law, which would generate $13.4 billion of cumulative state revenue.

Slide 50 is the worst-case production scenario at $60 real oil price under Senate Bill 2001 as introduced, and that would generate $6.6 billion of cumulative state revenue.

Slide 51 is our baseline oil production forecast with $100 per barrel oil and current tax law. That would generate $35.9 billion of cumulative state revenue through 2062. Slide 52 is the $100 per barrel oil, um, with our baseline oil production case and Senate Bill 2001 as introduced. That would be $29 billion of cumulative state revenue.

Slide 53 is our $100 oil price case with our worst-case production scenario under current law. That would be $9.3 billion of cumulative reduction to state revenue. And you can see what's going on here is we're getting the property tax revenue and the royalties from gas are largely being offset by reduced royalties from oil, given the lower oil production. But the most significant impacts here in these $100 barrel oil with the worst-case oil production scenarios is due to reductions to production tax revenue.

Slide 54 is that $100 per barrel oil impact scenario with the worst-case production scenario under Senate Bill 2001 as introduced by the Governor, which would be a $16.2 billion reduction to state revenue through 2062 in this scenario.

And that's the last of these oil production price sensitivity slides, Mr. Chairman.

The next set of slides walks through a deferred property tax scenario that was requested by the committee. Slide 56 outlines this scenario. So we ran all of these under current law with the understanding that this would be a potential alternative way of looking at property tax relief from what is being discussed under the bill before the Committee. We used all of our baseline modeling assumptions and we ran 3 different scenarios here. One is a 10-year tax holiday on all property tax with no repayment.

And then we ran a scenario where that property tax that would have been paid during the 10 years is repaid over the subsequent 10 years, and then another scenario where that would be repaid over the subsequent 20 years. So the first scenario is essentially zero mills for 10 years and then 20 mills, and then the others would be— would have 10 years at effectively a 40-mill tax rate or 20 years at a 30-mill tax rate to make up for the lost revenue. We did not model any changes to upstream property taxes. So the property tax relief in these scenarios is exclusive to the AKLNG project.

So slide 57 shows our usual cash flow and break-even cost of supply scenario with the 10 years of deferred property tax. And this would generate an expected break-even price into the global market of $8.57 per 1,000 cubic feet. That actually compares to $8.54 per 1,000 cubic feet under the bill introduced by the governor. So simply a 10-year exemption from property tax for the midstream would have a similar impact on project economics as the bill before the committee. Senator Steadman.

And then could you clarify for us, Mr. Chairman, the timing of the starting/stopping of the 10 years? Is it from final investment decision or first gas or where— what's the start and stop dates?

Sure. Co-chair Steadman, so I believe it's 10 years that property taxes would be due. So there is currently the property tax exemption during construction, so this would be 10 years of production.

Slide 58 is a similar chart, assuming that there is a 10-year deferral of the property tax and then that the property tax that that would otherwise be due to the state and importantly to the municipalities is repaid over the subsequent 10 years. That would generate a break-even cost of supply of $8.73 per 1,000 cubic feet, which would be roughly in between the current law scenario and the, the 2001 as introduced scenario.

And then slide 59 is this— is a similar analysis assuming a 20-year repayment schedule would generate a breakeven cost of supply of $8.65 per barrel, which would be a material reduction from the $9.07 in our baseline, but a little bit higher than the $8.54 in the bill as introduced by the Governor.

And then we have our state revenue charts for those various scenarios. Slide 60 is with no repayment to the state. And so you can see we would still receive corporate tax royalties as well as any property tax on associated additional production. But there would be no, no, no property tax or alternative volumetric tax until 2033 in this scenario. And I guess to somewhat clarify the response to the previous question from Co-chair Steadman, so it looks like we're doing a deferral of 10 years of full export operations here.

So 2043 would be the year that we have of the property tax coming back into play.

And then slide 61 is with the 10-year deferral and a 10-year repayment period. And so we would assume basically double what would otherwise be owed for the 10 years from 2043 through 2052, and then a return to the, the 20 mills property tax thereafter.

And slide 62 is the revenue chart assuming a 20-year repayment period. So basically 1.5 times what would otherwise be paid in property tax for those 20 years after the 10-year, 10-year deferral. And in each of these, we are presenting just the state revenues in terms of property tax. Municipal impacts would be again about twice as much as those state impacts.

So slide 63, the next scenario that was asked for from the committee was a federal tax holiday scenario. Those details are outlined on slide 64. So again, we use all of our baseline baseline AKLNG modeling assumptions with the 3 different bills, the current law, 280 is introduced by the governor, and 2001 is introduced by the governor. So the original request was for a corporate income tax holiday. So for the midstream owner, as I mentioned earlier, we assume that the developer will not be subject to federal corporate income tax.

Will not be subject to state corporate income tax. We assume that they would be a pass-through entity, and so that potential federal tax liability would be a pass-through to an individual or a partnership. For our modeling purposes, we assume a similar 21% marginal tax rate on the developer regardless. And so this would be a tax holiday on whatever that federal tax is, be it personal, corporate. So slide 65 looks at the impacts of that 10-year holiday.

So under current tax law, assuming the project went forward, it would be a $9.07 per 1,000 cubic feet break-even price. On the LNG. That compares to $9.07 under— without the tax holiday. And so essentially the tax— a 10-year federal tax holiday under our modeling would not have a material impact on the project economics. And so why is that?

Is that we are assuming that during the initial years of production, there would be significant— there would be significant net operating losses that would be incurred early on as the project is being built out, and then significant depreciation for corporate income tax purposes during the early years of the project. And we actually modeled that the first— in our baseline AKLNG modeling, that the first corporate income tax revenue to the state would be in the early 2040s. 40S. And so this 10-year tax holiday, if it's just a 10-year holiday, may not have a material impact on the project. Senator Steadman?

Looks like they're on a tax holiday regardless.

Coach R. Steadman, so we do assume significant depreciation impacts and then loss carryforward impacts. In our baseline modeling, once those run out, the federal corporate tax cut is expected to be over $600 million per year starting in the early 2040s. Senator Steadman. Just as a side note, Mr. Chairman, I think if the standalone Phase 1 has a similar issue. Large depreciation and substantial loss carryforwards eliminating taxes for a couple of decades.

Thank you, Senator Stidman. Mr. Stickel. Alright, so slide 66 is the similar chart here again.— not a material impact to the break-even cost of supply here.

And similar analysis for slide 67 as well.

Moving on to slide 68. So we were asked to model some alternative Community Impact Fund scenarios under Senate Bill 2001 as introduced using the heat map chart approach.

So what we have done here is we have looked at the Senate Bill 2001 given all of our base baseline assumptions. That bill, as introduced by the governor, includes a $40 million contribution to the Community Impact Fund, which would be a contribution paid by the developer to go towards grants administered by the Department of Commerce, Community and Economic Development. The committee asked us to look at what that would look like in terms of project economics with a $400 million or $800 million impact fund contribution instead of the $40 million as, as proposed by the governor. So slide 70 shows our usual heat map charts for the in-state gas breakeven price. And so we're looking at if the full AK LNG project goes forward under all of our various assumptions, what would the price needed to break even for the developer with their 10% rate of return be under these various bills, and it would be $4.64 under bill as introduced by— or $4.64 under current law, $4.68 per— excuse me, $4.64 under Senate Bill 2001 as introduced by the Governor, and then $4.68 with the $400 million Community Impact Fund and $4.73 with the $800 million Community Impact Fund payment.

So going from the 40 to 400 would increase that breakeven cost of supply by about 4 cents per thousand cubic feet. And then going up to the full 800 would be about a 9 cents per thousand cubic feet increase to that required cost of supply. Slide 71 is the similar chart with the LNG breakeven price into the global market. And so going from the $40 million under— as proposed by the governor, up to $800 million would be again a 9-cent increase to the breakeven cost of supply. Going from $8.54 per thousand cubic feet up to $8.63 per thousand cubic feet, and we show the range of potential values for that with different capital cost assumptions as well as different upstream gas prices.

I think based on some of the information that's been put out by Glenfarn just last week in this committee, looking at something probably closer to that 20%, plus 20% capital cost sensitivity. And then if you assumed a 20% contingency on top of that, something in that 40% sensitivity.

Slide 72, we were asked to look at these alternative Community Impact Fund payments for the Phase 1 only scenario. And again, this is our baseline Phase 1 only scenario., with the about $11 billion, a little over $11 billion capital cost for the pipeline.

And under Senate Bill 2001, as introduced by the Governor, there would be about a $12.65 per thousand cubic feet weighted average cost of supply required for the developer to make their 10% rate of return.. And if that increases— if we increase that community impact fund payment up to the $800 million, that would increase from $12.65 up to $13.20 per 1,000 cubic feet. And so these changes to the cost of supply are more significant than in the full project because we are taking that $800 million upfront payment, or the $40 or $400 or $800, and we're spreading that over a much smaller number of molecules to recoup those costs.

And then slide 73 is the similar chart but looking just at the breakeven price for utilities. Again, in our baseline Phase 1 analysis, we assume 50 billion cubic feet per year of industrial baseload demand at the $6 per thousand cubic feet with the remainder of the utility demand being made up— or the remainder of the demand being made up by utilities paying a higher rate. So the price to utilities— and in this scenario, since we're assuming a fixed $6 per thousand cubic feet price to the baseload consumer to incentivize that production, the entirety of this community impact fund payment is essentially borne by ratepayers on the utility side. And so with the $40 million impact fund payment under the bill as introduced by the governor, the break-even cost of supply would be $18 97 cents for sales to utilities, and that would increase to just over $20 per 1,000 cubic feet with the $800 million Community Impact Fund payment.

And that is the end of the slide deck for these supplemental requests. As I mentioned, the appendix was just some baseline analysis slides that we had included as reference for the committee.

Questions on the presentation? Lots of numbers. Senator Steadman. I'm just curious, this is kind of a side note, but operating— this, if we do the in-state gas line by itself, Phase 1, do we have the annual operating cost expectations? We do.

We do, Co-Chair Steadman. I'm happy to provide that. I know that's been in some of our various responses to the committee, but we'll include that in our follow-ups. Thank you. Senator Steadman.

And then how are you handling the small gas treatment plant on Phase 1? Sure. Co-chair Steadman, so we have not received detailed information from the developer or AGDC on exactly how that gas treatment will work for Phase 1. We have assumed for modeling purposes that there would be a similar treatment cost on a per molecule basis as for the full project.

Mr. Chairman, I think we've requested that information from Glenfarm this morning. We should be able to get that to you so we have more accurate— the more accurate data we can get, the better we are to more apt to make a proper conclusion to the work. So we're trying to help refine those numbers. And I think a lot of us are using $18 billion for the cost of the in-state gas line, $60 billion for the project in the aggregate. Just to— I get a little concerned when they talk in the press of— and they're off $3, $4 billion, or they're off $15 billion on the big project.

Are there questions of the presenter? Thank you very much for the presentation. It's very insightful. That concludes this morning's meeting. Our next meeting is this afternoon at 1:30, where we will be hearing from North Slope Producers, Hiltcorp, ConocoPhillips, and ExxonMobil.

If you've seen nothing, we are adjourned until then.