SRES-260518-0900

I call Senate Resources Committee meeting to order. Today is Monday, May 18th. 2026, And the time is 9:00 AM. This is our 63rd resources meeting of the 34th Legislature, second session. Please turn off all your cell phones.

Committee members present today: Senator Rauscher, Senator Myers, Senator Dunbar, Senator Clayman, and myself, Senator Giesel. I believe that Senator Kawasaki and Vice Chair Wilkowski will be along shortly. We have a quorum to conduct business. Thank you to Heather and Chloe who are helping us out with audio and keeping the minutes. So today we are hearing again the Gasline for Alaskans Act.

This is our 35th hearing on this topic. 55% Of Senate Resources meetings this session have been on this bill. We do need to adjourn today at 10:00 a.m. as the room will be used by someone else. So First thing we want to do today is adopt a committee substitute. I'm going to take a brief at ease.

Back on the record. So first up today we have a new committee substitute with Senator Myers' amendment number L4 incorporated. Senator Dunbar. Madam Chair, I move the committee adopt the Senate Resources Committee substitute for Senate Bill 280, work draft 34-GS2038/S, as our working document. All right, I'll object for purposes of discussion.

I want to call out Senator Myers' amendment. It has been incorporated as the only change in version S. As in, let's see, S-S. Shishmaref. Shishmaref. That's one I wouldn't have thought of. Thank you for that, Senator Dunbar.

All right. The S-H version. Yeah. The Senator Myers amendment is in— I was in error before. It's Section 40 and 41.

I believe it is partly in 41 also. Would you look at that, Senator Myers, and Just confirm. Actually, 41 may still be the same wording. Yes, I think it is actually. But it's basically in 40, would you say, Senator Myers?

Yeah. I will—. Page 37. Yeah, so, Madam Chair—. Page 37, yes.

What I'm seeing is the new Section 3 that we added that had to do with the municipal taxes and then the new Section 40 having to do with the state taxes. And that is accurate. Very good. Oh yes, I see. Very nice.

So Section 3 and Section 40. Perfect. So that is the only change in this committee substitute. So with that, I'm going to remove my objection. Is there further objection to adopting Version S as our working document?

Seeing none, Version S then is before us. We requested additional modeling from the Department of Revenue. Mr. Stickel, who is the Chief Economist, is not available. He is being employed before another committee, but part of his staff is with us today online. Owen Stevens, Commercial Analyst, Tax Division, Department of Revenue, is here to go through the slide deck with us.

Also online is David Hebert, commercial analyst. He is available for questions, a lifeline. Welcome, Vice Chair Senator Wilkowski, to the meeting. Mr. Owen— or excuse me, Mr. Stevens, we have a short meeting today. We have to adjourn by 10 o'clock.

So in reviewing the slides, if you would move along pretty quickly. We will, of course, have a meeting this afternoon as well. But welcome. Thank you for joining us, Mr. Stevens.

Uh, thank you, Chair. Um, and in fact, um, uh, Mr. Stickle's actually also just come online, so if you— I'm happy and willing to present, but I think he's available as well. So, well, that would be great, but on the other hand, if he is otherwise engaged, we're happy to have you do it. That may happen later, but for the moment I think we're ready. If he can— he seems to lack sound, so maybe I'll get started and we'll let you know when he's ready.

Sounds great. Okay. Well, thank you. Thank you to Lacey. So for the record, I'm Owen Stephens.

I'm a commercial analyst with the Department of Revenue. Thank you for the request to present to the committee today. And we're responding to several requests for analysis from the committee, mostly received last Wednesday. The way we're planning to present this today is either Dan will talk through all of it, or myself and David Herbold will share the presenting as we walk through. But we understand the committee needs to be flexible and is short of time, so if there's anything that you'd particularly like to focus on, we can, we can do that.

As you can see, this has been a lot of work to put together in a short amount of time. And what we'll do— so we've got, we have the request for detailed slides modeling an increased rate to the oil production minimum tax law. That was received on May 12th. And when we have a request for an alternate Phase 1 scenario, And then we have multiple other additional analyses received last Wednesday: the 10-year sunset, um, 80/20 equity scenario, um, alternative oil impact scenarios, and also increased rates of return for the midstream. And then for each of these analyses, certainly for the, the last set, um, we'll be including current law, we'll be including SB 280 as introduced, and we will be including SB 280 version L. And your version S just introduced, my understanding is that should not cause any significant changes to our analysis.

Very good. We can go on to slide 4.

Okay, moving forward. So to talk about the minimum tax law, We've looked at increasing the minimum tax floor for the production tax and the impacts on production tax revenue from increasing that from the current rate of 4% to 6%. And we've done this in two connected ways. So firstly, we've looked at the impact on the Department of Revenue spring forecast.

For this year, and then we separately looked at the AK LNG project model.

So other than for the variation to that minimum tax floor top rate, we have assumed current tax law.

Very good. I am going to ask committee members to hold questions so we can actually get to some of the presentation versus the the description. Moving on to slide 5.

Okay. So slide 5, this is the disclaimer that goes with all of our production tax slides. This is a very complex tax system, as I'm sure the committee are aware, multiple interacting provisions, and these numbers are based on our preliminary interpretation of the bill provisions. And how those would apply to the spring forecast. Many of the provisions here would need to be addressed through regulations, and this presentation is solely for informative purposes.

I'm an economist, not an auditor, as Mr. Steckel would usually say.

Very good. Slide 6.

Moving on to slide 6. Last week we spoke about the North Sea gas segment. We're on the left-hand side. You can see we're now talking about the oil tax segment.

And there are similar complexities— more complexities, shall we say— than there are involved for the gas tax, particularly the minimum tax law, but also some of the credits.

So moving on to slide 7, these are the assumptions that we have going into the, uh, spring 2026 forecast. Um, this includes the oil price from Brent futures as of March 11th. Clearly there's been quite a few changes since then, um, but that was taken during the— after the initial rise in, in oil price recently. Uh, the model assumes the current production tax structure, and, uh, tax is calculated as the greater of the 35% net tax or the applicable minimum tax law. So that's— and that's a gross tax.

The North Slope oil minimum tax law is currently 4% of the gross value at the point of production. Um, that's been North Slope oil price exceeds $25 per barrel, which it has done for a long time now. Net tax reflects the production tax value, allowable lease expenditures, and applicable statutory adjustments, including the GVR, the gross value reduction. It includes pretaxable barrel credits, and it, and it includes carryforward lease expenditures.

So moving on to look at the modeling for the AK LNG project. You've seen a lot of output from this model from us already over the last few weeks. The model timeframe, we assume 32 years from the first LNG sale in 2031 going through to 2062. And it isn't anticipated that the project will continue beyond this. We assume 10% IRR for the midstream.

We'll look at sensitivities on that later, um, with construction costs estimated in real 2026 dollars at $46 billion. We assume an unprocessed gas price of $1.50 per MCF, with production from the non-Great Bear field, so something requiring gas treatment. And then Phase 2 production, once LNG exports start, that's from, from that Phase 1 production, but also and more so from Prudhoe Bay and Point Thompson. Uh, the base case model, we assume oil production at Prudhoe Bay, uh, the overall impact of the project on post-production, they seem to be zero. And we assume the liquids production is increased by 270 million barrels over the life of project for Point Thompson.

Moving on to slide 9. So this slide shows the, uh, impact, uh, on the spring— official spring 2026 production tax revenue. Uh, this excludes the AKRNG project. And you can see here that we have current law with the 4% tax law on the upper line, and then in the increased 6% on the line below. The average annual impact over FY27 to 36 is $132 million.

And if you look through, through those numbers, that's increasing from 2027 onwards. Peaking in 2033 with $199— sorry, $199 billion. And the negative impact you see in FY34, that reflects a change in companies' ability to apply carryforward lease expenditures and an interaction with the taxable barrel credits. Just to explain on that a little bit more, what happens is As you increase the minimum tax floor, some of the companies cannot use as many of their carryforward lease expenditures and can't deduct as many in the preceding years, which means they have a larger balance left over when, when they get to 2034 in the 6% case than they do in the 4% case, and that leads to more lease deductions happening in 2034.

But overall, you can see this is an increase, increase in state revenue.

So putting that on a chart, this is what we have here. The lower blue line is the 4% current tax law, and then the increase to 6%, the floor, and that's shown in orange in the upper line. You can see the two numbers cross over slightly in 2034.

And then moving on to slide 11.

We then went ahead and modeled this separately within modeling of the Alaska LNG project. So this is incremental revenue. This is not in addition to the production tax modeling I just showed based on forecast. And this is done slightly differently in the— but this is a separate aggregation of the production data and the costs here. So we're not splitting things out based on separate companies in this analysis, which could potentially have a material difference.

Having said that, the average annual impact we see from FY27 to FY36, and that is $16 million per year.

In the early years, the increased minimum tax law limits the leased expenditures that can be applied against tax, and so that results in a positive impact on state revenue. And then you see from FY34 onwards, The increased minimum tax law, what that does is it increases the baseline revenue, so the revenue that companies are already getting from the oil that they're producing from— through their vein points onshore under the forecast. And so what happens is that— and this is kind of difficult to explain— but what happens is that under the— with the project going, you're paying— their companies are paying the net tax, so an increase in the gross tax law doesn't impact them. But that's also the case with the project going at the 4% as well. And so essentially there's no change for the totals, but there is change for the— sorry, let me get this right— there's no change for the totals when you include the project and the underlying oil production for the base case development project.

But there is a positive impact on state revenue once you exclude the project and you only have the underlying oil revenue. And when you combine those, those two different things together, you then end up having a negative impact between the two on state revenue over those years.

Moving on, this is a— on slide 12, we have a chart of that revenue. And similar points being made here as well.

I see no questions. I'll let you move on. Okay, thank you. So slide 13, we have those two numbers added together. And then now let me make, make clear, these two models are not necessarily directly joined to each other.

So if we were to model the gas production and the incremental oil production from the project fully within the company, company by company revenue. That could potentially change to some extent, but directionally this still should be reasonable. This slide shows how much more revenue the state would receive from increasing the minimum tax from 4% to 6% with the two, two models in combination. And the high tax rates generate more revenue while it's equal.

So you can see those numbers peaking in 2032 at $243 million, and the, the lowest value there, um, comes through a combination of, of, of the lower values on— for both with and without the project, the lowest value there is -$50 million in 2034.

And that's just a plot of those numbers again, just to show you what that looks like year on year. And that was the, um, the last slide I had on the, on the minimum tax. Um, and I know that my understanding is that Dan is still, um, called in as well, so he's here to answer questions and jump in if he has the best response. So I guess go ahead and fire ahead with questions, please.

Are there any questions on this section about increasing the floor from 4 to 6? Senator Rauscher. Thank you, Madam Chair. So I'm trying to understand the language that we're using in the slide. The minimum tax floor top rate.

I've never seen it written that way before, and I'm trying to understand why we're using that language.

Which—. Senator, through the chair, Senator Roscher, which slide are you looking at? Slide 4, I guess, will work.

Senator Roscher said slide 4. Ah, yeah. Thank you, Chair Giesel.

I'm not sure why it says that. I think you would be fine to simply remove the word top from that slide, and then it would would certainly work just as well. In tendency, that is correct. Obviously, at lower oil prices, below $25, you gradually decrease the percentage that applies down to 1%. Just a quick follow-up.

I just never seen it—. Senator Rusher. —With the wording top rate in there because I'm not sure how that applies. To the floor. But anyway, that was, that was the question.

Thank you, Senator Rauscher. All right, I see no other questions, so we can go on with Alternative Phase 1 scenario, slide 15, moving to 16. Okay, I'm going to hand over the slides now. Um, I, I'm either going to hand over to Dan or David, and I'll let, um, let them decide who's going ahead now. Very good.

All right. This is Dan Stickle, Chief Economist with the Department of Revenue. I guess I can take it from here.

So we were asked for several additional sets of modeling from the committee, and this is the first one. We were asked to do an alternative version of our Phase 1 analysis. So slide 16 lays out the details of that request that we were given. So it was an alternative demand scenario for Phase 1. And the Phase 1 is where we assume only the pipeline is built with only the in-state demand and there is not the full export project.

We were asked to model a scenario where Phase 1 demand started at 20 billion cubic feet per year of initial demand. This is a difference from the 65 billion cubic feet per year of demand that we include in, in our main Phase 1 scenario. And we were asked to model a scenario where we start with that 20 billion cubic feet per year and then have the in-state demand increase by 5 billion cubic feet per year every year thereafter. And so we've done this— we've, we've modeled out that particular scenario. One of the key differences between this and the in-state demand scenario that we've been presenting in most of our Phase 1 analysis is that this would really not include the large anchor customer at the beginning of the at the beginning of the project.

So in our baseline analysis, we assume that there's a large anchor customer that's contributing about 50 billion cubic feet per year of demand. Um, whereas in this scenario, we're starting out with just the 20 billion cubic feet, which could be a small anchor customer combined with, um, in-state resident use. To note, the Senate Bill 280 version L, which is— which we did the modeling on, and the Fairbanks Amendment that was adopted into the most recent committee substitute would not materially change our analysis. The bill includes a price cap of $12 per thousand cubic feet for gas sold to utilities. We've modeled out what the break-even prices would be It's interesting for comparison, but with that $12 price cap, we don't believe that the Phase 1 would, would proceed.

So this scenario is really just for illustrative purposes. Mr. Stickel, I also wanted to note that on page 8, when you were talking about the assumptions, Phase 1 includes treatment facility, or a treatment facility, on the North Slope because it would include non-Great Bear Pantheon field. True, Madam Chair? That's, that's correct. So we've used the same Phase 1 scenario assumptions that we've used in our other modeling.

The only thing we've changed here is the demand. Very good. Thank you. Madam Chair. Yes, one second.

Senator Kawasaki, question? Yes. And then I just wanted to make sure that the assumption for the pipeline was $16 billion.

Through the chair, yes, that's roughly correct. So our $15.5 billion in, in real 2026 terms is our pipeline construction cost assumption. Okay, and then, and then follow-up through, and then, um, Senator Giesel mentioned that the gas treatment plant, but it may be not a full gas treatment sized plant, which would be, I think, in the $20 million or $15 million range, right? It would be a smaller type of cycling plant. Was that correct?

And then how much, what was that Total cost.

Um, yes, through the chair. So what we've done here is for the full project, um, we have an assumption of $10.9 billion in real terms for the gas treatment plant on the, on the North Slope. Um, we don't have a detailed assumption for the, the cost of a treatment facility, uh, for the Phase 1 scenario, um, or potentially exactly how that would be implemented. What we've done for this analysis is we've assumed a similar cost on a per 1,000 cubic feet basis for treatment between the Phase 1 scenario and our, our full scenario. And that could be— there could be a smaller treatment plant, there could be some sort of a modular operation.

It's uncertain exactly how that would play out in the Phase I scenario. And you can see on the next slide here, we've actually laid out the estimates for the cost of that treatment. So it's a little over $1 per 1,000 cubic feet. Thank you.

All right. You had a question, Senator Clayman? Yes. Mr. Stickle, you mentioned at the bottom of slide 16 that the— at the $12 price cap that the facility would not be built. Do you have an estimate of what price it would need to be for the facility to be built?

Senator Clayman, through the chair, so I think the next couple of slides will be instructive to that, to that question. We show it under our assumptions we've used. We show an in-state gas breakeven price in 2033 of just under $18 per 1,000 cubic feet under current law. A little over $12 per 1,000 cubic feet under Senate Bill 280 as introduced by the governor, and a little over $17 per 1,000 cubic feet under the committee substitute before the committee.

And another important point relating to that price cap is the committee substitute does not inflation adjust that price cap. And so the cap is $12 nominal forever, and that presents a challenge.

Thank you. That's a good point for improving the bill. Thank you for that. And so you've really summarized the next 3 slides, 17, 18, and 19.

Yes, Madam Chair. And if we're ready to— are there further questions on slide 16 or ready to move to slide 17? Yes, we're ready to move to slide 17.

Okay. So moving on to slide 17. And yes, so slide 17 is the the summary of cash flows to different, different stakeholders, as well as that breakeven cost of supply. This is the similar slide that we've shown for many scenarios throughout the analysis and presentation, so this should be familiar to the committee. Typically, when we show this slide, there's an in-state breakeven as well as a delivered LNG breakeven.

In this scenario, we're assuming the Phase 1 only with the custom— customized demand run. And again, as I, as I mentioned earlier, in nominal terms, $17.71 is the estimated in-state breakeven gas price under current law. And if we were looking for a real number to inflation adjust, that would be a just under $15 per thousand cubic feet in 2026 terms.

Very good. Slide 18 is the similar slide under SB 280 as introduced by the governor. And as I mentioned before, $12.45 is our estimated in-state breakeven price in 2033. In real dollars terms, that would be $10.48 per 1,000 cubic feet.

No questions there.

And slide 19 is a similar slide under the committee substitute before the committee with a breakeven cost of supply of $17.14 per 1,000 cubic feet in 2033. Which would equate to about $14.42 per 1,000 cubic feet in, in real terms. So in terms of where would you want to set— to the question from Senator Clayman of where would you want to set a price cap, this would kind of represent the, the minimum of where such a price cap could be set and still result in a viable project under our modeling. Of course, if there's any— these are based on our baseline CapEx assumptions, so if there would be any cost overruns, that would increase the required breakeven prices.

Senator Myers. Thank you, Madam Chair. Mr. Stickel, do either you or either of your coworkers online happen to have an estimate of what an import price would be if we started getting LNG imports into South Central for 2033 instead?

Senator Myers, we do actually.

And to the chair, apologies, I was just pulling up the, the relevant analysis here.

So we have an estimate in the range of just under $17 per 1,000 cubic feet. In 2033 terms for, for LNG imports. And where that price came from was a report that was done by BRG for NSTAR a couple of years ago. And we've taken a couple— they laid out actually a couple of different import cases, and we've taken, taken a few of their cases and just inflated up to current dollars. But gets into that $17 range.

So these prices that we're looking at would be roughly on par with what we're looking at for imports. Now again, the— we're looking at a different demand case here for this, this custom model than, than what would be in the baseline. So there is Potentially some differences in assumptions between those two, but roughly speaking, comparable price to imports, and then a lower price to imports under the 280 as introduced by the governor. Okay, thank you. And I'll just add the BRG report is online.

You can Google it. Senator Clayman. Mr. Stickle, could you repeat again the number you had for estimated imported natural gas in 2033?

Senator Clayman, through the Chair, $16.93. And again, a whole host of assumptions that underlie that number. Senator Wilkowski. Thank you. And I apologize if I missed this.

I had to step out for a minute. But what— okay, so this is a very different number than we saw in a previous presentation you did where you said it would be $22.96. And I'm curious what the difference is.

Uh, Senator Wielechowski, through the chair. So this is a— an in-state breakeven price would be a weighted average price. It's based on the specific demand assumption that was requested by the committee. And so we're starting with the 20 billion cubic feet per year of initial demand and then increasing that by 5 billion cubic feet per year into perpetuity.

And so that's a fundamentally different case than our, our standard in-state case, which assumes demand starting at 65 billion cubic feet per year and then remaining at that level for, for several years before increasing in the later years.

Follow-up, Senator Wielechowski. Is this the break-even for the price to consumers? What's the price to the consumer utilities? Because I remember you had— I'm looking for the chart, but I remember you had two different slides, one for sort of a kind of a standard in-state, another for the utility price. What's the utility price?

Yes, so Senator Wielechowski, through the Chair, so in our Our Phase 1 scenario that we presented, we had a starting demand of 65 billion cubic feet per year, which consisted of a 50 billion cubic feet demand from an anchor customer and then 15 billion cubic feet of demand from utilities.

The scenario that we were asked to model for the committee started with a 20 billion cubic feet per— of demand per year in total. And so to calculate out a, a cost of utilities separate from a cost of baseload demand, we would need an assumption around baseload demand.

We assume a $6 per thousand cubic feet real price for that. Base load demand. So based on these weighted average prices, it would be possible to calculate out a utility price if there was a base load. But a 20— a 20 billion cubic feet per year demand scenario really doesn't seem to include a base load customer, which is why we haven't broken that out separately here.

Senator Wilkowski. What? Okay. It was a request made by the committee. What if there was no baseload large user?

If it was just utilities and a small throughput? And— but how is it possible that you've dropped from 60 to 20 and you have a lower price? That's 60 BCF per year to 20 BCF. It seems like the price would go up in that situation. Explain to me why that's not the case.

Senator Wielechowski, through the chair. So it is a different— it's a lower starting demand, but we actually end up with a higher final demand for the end-state summary.

So it's a fundamentally different scenario that we were asked to model.

And I'm not— I don't have the prior Phase 1 analysis at my fingertips, but we'd be happy to follow up with a detailed some more detailed notes comparing this alternative Phase 1 scenario to our baseline Phase 1 scenario.

Senator Myers. Yeah, thank you, Madam Chair. Actually, Madam Chair, I believe there's a question for you. Um, this scenario that Mr. Stickel is modeling here, um, this sounds very— I'm trying to remember all the details, but this sounds very similar to what, um, when the current contracts with Hilcorp and the other Cook Inlet producers are running out. Is that roughly what this is based on?

Roughly, yes. Okay. And no baseload, no Donlin, uh, sure. Pull. Yes, Senator Wielekowski.

I think I found this slide, and it's from a presentation you did, um, looks like April 29th, and you had two different chart— you had two different heat maps, and one was for a weighted average in-state breakeven price, and you had $1.50 gas. That was the in-state breakeven price. You had a dollar— you have $12.45. And so you're saying compared to, to that, this number is now up to $17.14, is that right?

Uh, Senator Bullockowski, through the chair, and I believe I also found the the slide up. We're looking at slide 19 from, from that presentation? Correct. Um, okay, so Senator Wolkowski, through the Chair, so this, the slide 19 from that presentation in late April, that modeled out two scenarios, which was the current law and the SB 280 as introduced, and that would be comparable to slides 17 and 18 of this presentation. And so what we're seeing here is in our baseline Phase 1 scenario, we had— under current law, we had a $14.55 weighted average breakeven price.

Under this alternative scenario, we have a $17.71 weighted average price in 2033. And so this scenario that the committee has asked us to model does have a a somewhat higher breakeven cost of supply given that there's a, a lower demand and not that anchor customer. Looking at SB 280 as introduced, um, we're actually showing the same, uh, price in nominal terms, and I'll need to verify if that's a typo or if that's a correct number there. But looking at this, at the— looking at slide 17, for instance, which is showing the higher cost of supply, that would be due to the fact that we have a lower demand without that anchor customer. Okay, so yes, under Wilkowski.

So you— okay, so going back to that April 29th, you, you had two slides, 19 and 20, and you had a— the one slide was for in-state break-even price and the other slide was for break-even price for utilities, which is the price that consumers would pay. And so, and correct me if I'm wrong here, so at SB 280 as introduced would have produced a cost of $12.45 under break— in-state breakeven, but, but for the utilities it was $18.60 and then you added $4.36 and that, that's where you came to the $22.96. So what you're doing here is you're, you're— this is the slide that compares to the in-state breakeven. It's not the price for utilities because if it's the price for the utilities, you probably have to add at least $5 or $6 onto this price. Is that right?

Uh, Senator Wielekowski, through the chair, uh, that's correct. So we assume about $4.36 per thousand cubic feet to get from the price to utilities to the final price to consumer. Senator Wielekowski, follow-up. But you also have to add another $5 on because looking at the difference between the in-state break-even price and the price for utilities there was about a $6 difference. So you're showing the slide for the in-state break-even, but what really matters to consumers, the South Central consumers in my mind and Fairbanks consumers, is the price for utilities.

And what you need to do in that case is you need to add $6, because the difference was $6. It was $12.45 for the in-state break-even and it was $18.60. So that's about a $6 difference. And then you got to add another $4.36 for the cost to get it. So really what you need to do is to this price, you probably need to add $6 for the utility price, and then you need to add another $4.36.

So you need to add probably $10 onto this. Does that sound about right?

Uh, Senator Wilkowski, through the chair, so adding If you're trying to get from the cost to utilities to the cost to consumer, we do have an estimated value for that of about $4.36 per 1,000 cubic feet. And where that comes from is taking the current cost for distribution from— in STAR and just inflating that out into the future. For a difference between the weighted average breakeven price and the price to utilities, that depends on if there is a, a baseload anchor consumer. So in our Phase 1 modeling that we presented in late April, those numbers assumed a baseload customer with 50 billion cubic feet per year of demand. And a $6 price delivered to that baseload customer.

The analysis that we were requested to do for the committee was essentially looking at a scenario where there was not a significant baseload customer. Um, based on these weighted average prices, you could certainly make assumptions around a baseload customer. And extrapolate what the implied cost to utilities would be if a baseload customer was given a lower rate.

Further questions?

Thank you for clarifying that, Senator Wielechowski. It is— the question is delivered to customers.

Uh, let's see, any other questions on slides, uh, going up through slide 8— or excuse me, 19?

Uh, so on to slide 20, please, Mr. Stickel.

All right, so slide 20 is our annual state revenues chart that we've been presenting for the various gas cases. This looks at this alternative Phase 1 scenario under current law, and you can see this would be positive to, to state revenues, starting out with very small state revenues, reaching $200 million per year by around 2050.

I see no questions.

Uh, slide 21 being a similar chart looking at annual state revenues under SB 280 as introduced by the governor, with the, the big difference between slides 20 and 21 being the removal of the vast majority of that Well, initially the removal entirely of the property tax and then the replacement with the small alternative volumetric tax. So a lower, a lower amount of revenue. Senator Clayman. Thank you, Mr. Stigl. I'm looking at both slide 20 and slide 21, and in the key there's a note for corporate income tax with an orange code, and it's almost invisible of any corporate income tax.

Is that because under both the current scenario and the SB 280 as introduced by the governor, there's really no meaningful corporate income tax that we receive?

Senator Clayman, through the chair, so these slides 20 and 21 represent incremental revenue to the state, and the incremental revenue from the small amount of gas sales would be essentially de minimis in terms of our state revenue forecast.

Thank you. And slide 22. Yeah, so slide 22 is the similar chart under, uh, the committee substitute before the committee. So we can see a higher amount of revenue from property tax and related revenues. A significant— that orange bar does show up significantly in this chart.

And the reason for that is that we have the pass-through entity tax involved in the, in the committee substitute. And so that would apply corporate income tax to the midstream developer, which we assume is not subject to corporate income tax under current law. As well as to additional North Slope producers. The majority of what you see here in terms of the corporate income tax impact is from that— applying that tax to the midstream developer. And so there's a moderate amount of taxable profit through the first 20 years of tolling period and then a more significant amount of taxable profit once we get to the 2050 and beyond.

Senator Myers. Yeah, thank you, Madam Chair. Mr. Stickell, if a— they're currently looking for equity partners right now. If they get an equity partner that already is a C-Corp, will they, even without the pass-through entity tax, will that equity partner pay the state corporate income tax?

Uh, Senator Myers to the Chair. So under current law, um, if any of the owners are C corps, they would pay the corporate income tax. Okay. Um, if that answers the question. Uh, yes, it does.

Just trying to make sure that it depends on on the— who the equity owners are, whether or not we're missing the corporate income tax or not. Thank you.

All right. Moving on to Slide 23.

All right. So the next set of slides, we were asked to evaluate the impacts of a 10-year sunset to the alternative volumetric tax, and this relates to some of the information that was presented by Gaffney Klein over the weekend. The 10-year sunset was included in the current version of the, of the bill before the committee.

So slide 24 kind of lays out the request. So what we've looked at here is under Senate Bill 280 as introduced, we modeled a 10-year after commercial production sunset to the alternative volumetric tax, which then would revert to a current law property tax.

This is built into the current version of the bill, and so we've modeled the, the current version of the bill with and without the, the sunset. And we show here what the annual revenues from the alternative volumetric tax would be under those two versions of the bill. So under the bill as introduced by the governor, there would be $76 million on average of alternative volumetric tax over the 10 years with the sunset in place. And under the, the committee substitute, there would be $565 million of alternative volumetric tax. And these are total alternative volumetric tax, both state and municipal.

I see no questions.

Slide 25 is our, uh, our, uh, standard slides that we've been showing with the distribution of cash flows to the various stakeholders, as well as the cost of supply and the breakeven prices under the bill as introduced by the governor. And so here under— for delivered LNG into the market with a 10-year sunset and the bill is introduced by the governor, we would estimate a breakeven LNG price of about $8.62 per thousand cubic feet. That compares to $8.48 under— without the sunset in place. So you can see a change there of about $0.14 to the breakeven price compared to having no sunset. Madam Chair?

Yes, Senator Myers. Mr. Stickel, could you elaborate on that? Why would a sunset 10 years out create a higher price in 2033 when we've just started that 10-year period?

I— to Senator Myers, to the Chair. So when we're modeling this sunset, we're assuming that once the alternative volumetric tax kicks in, that it would apply for 10 years. And then sunset. And so the, the sunset here is actually, uh, after 2042. We assume that the ABT would kick in in 2033, apply through 2042, and then current year property tax would apply starting in 2043 in this scenario.

Follow-up, Senator Myers. Yeah, Mr. Stickell, that's— that was my understanding of it. I'm trying to figure out why the price went up when I understand why the price would go up after the sunset, but why is the price going up before the sunset?

Uh, Senator Myers to the chair. So what we're doing here is we're looking at the break-even from the project developer viewpoint, um, and as we heard from Gaffney Klein over the weekend, there's a discounting factor here. So We're looking at the entire stream of project revenues over the 30-year model period, and what is the breakeven price required that would give the developer that 10% pretax rate of return over the entire life of the project. If the alternative— the alternative volumetric tax represents a significant tax reduction to the developer. And so if that tax exists for 10 years, the 10— even if it's the first 10 years, which are the most important for project economics, but having that tax apply for only 10 years instead of for a longer period does require a higher price for the project to break even.

Okay, thank you.

All right, moving on to slide 26. Uh, slide 26 is the similar chart under the committee substitute. Um, we show a breakeven LNG price of $8.97 per, per thousand cubic feet, and that is That is with the sunset is modeled into the bill. If we did not have a sunset, that would be a different number, but probably fairly similar because as we saw, the alternative volumetric tax and the property tax actually generate fairly similar revenues under our modeling. Once you get out beyond the 10 years.

Senator Wielekowski. Why does the gas commodity charge rise from $1.52 in slides 18 and 19 to $1.73? How is that impacted by this version L?

So, Senator Wilkowski, through the chair, so slides 17 and 18 were a gas commodity charge for just in-state, and I am going to actually kick this over to Owen or David to answer that question, if that's okay. Yes.

Madam Chair, I do apologize. I have to drop off at this point, so I'm going to let Owen and David wrap up the last few minutes of the presentation. Thank you. Mr. Stevens, I believe that's you.

I'll jump in to attempt to answer this question, and then maybe David will take over. I'm sorry, could you repeat the question? Senator Wilkowski. Yeah, I was curious about the discrepancy in the gas commodity charge on, for example, on Slides 18 and 19, it's $1.52. In slide 25, it's $1.62.

In slide 26, it's $1.73. I'm just curious about the cost of gas commodity charge.

Um, uh, I'm gonna pass that out. To David, I think, is probably the best, best way. Mr. Herbert. So, um, thank you. That is David Herbert, a commercial analyst for the Department of Revenue.

Um, with regards to the gas commodity charge differences between our Phase 1 analysis, which was the prior slides, and this analysis on the sunset and later on in the presentation. The key difference between those two numbers are our assumptions around gas fuel used by the project, which do differ in our Phase 1 scenarios versus our full AK LNG project scenarios.

Any other questions? Seeing none, moving on to slide 27.

Um, since Dan is dropping off, this is David Herbert, commercial analyst again. I will continue just providing presentation, but I'll hand it off to Owen in a little bit if the need arises. Slide 27 is just graphically showing our 10-year sunset on SB 28 as introduced by the governor.

Very good. I see no questions.

Slide 28, you can see this is our 10-year sunset on Committee substitute for SB 28, version L. Um, I see no questions on this one either.

All right, and that brings us to slide 29, which is where we modify the debt-to-equity ratio for those scenarios. Thank you, Mr. Herbert. We have been told that this room is in use. Uh, we only have it now till 10 o'clock, which is about a minute away. Um, and so we do need to conclude here and take this up later this afternoon at our next meeting.

So, uh, thank you. I'm going to pause at this point in the presentation. Um, so this necessitates the concluding of our meeting today. We will meet for the 64th time this afternoon at 3:30, and we'll hear additional information about Senate Bill 280. So at this time, the meeting will stand adjourned.

Let the record reflect the time is 10:00 a.m.