Alaska Legislature: MSC2-20260626-1410

And this is the difference between us getting to a point where we can't achieve FID and Glenfarn leaving the project, and the state having an option to push Glenfarn out if they don't meet certain milestones. This was an option, the latter, where we can push them out. This is an option that AGDC wanted. This is a state option that we requested and negotiated for our benefit And if I may, on April 23rd of last year, so 2025, this question was brought up in front of Legislative Budget and Audit. And so you had the following members present.

You had Representative Fields, Representative Foster, Representative Josephson, Representative Kopp, Representative Tilton, Speaker Edgeman, Senator Giesel, Senator Wilkowski, Senator Kawasaki, Senator Gray Jackson, and I believe that they also had President Stevens, Senator Myers, and Representative Hannan and Elam, Representatives Hannan and Elam in the audience. Representative Fields asked about these clawback mechanisms at that meeting, and what I said was, I said there, I said, and just to address this clearly, This is my words. And just to address this clearly, because I've heard many questions that dance around this, the clawback would be a paid clawback. And there's real important reason for that.

If you're moving towards milestones and you're going to penalize your developer and they miss a milestone and you can just take everything away from them and they can lose everything, they will put nothing into it. And this is a $44 billion project that we're building. We need to put the very best work going into it. And that's why we're— there were these paid clawbacks with respect to our ability to push the developer out. Again, that was not in the main agreement.

And the main agreement has the abandonment provisions that we have also discussed where there is not a payment. And I'll just ask if my colleagues would like to add anything to that. This is Adam Prestidge from Glenfarn. To add to that, as I've said many times in this committee, in this forum and others similar, our effort here is to come to Alaska, build a pipeline and a historic transformational piece of infrastructure that has a tremendous, tremendous benefit to the state. We come here to— we came here on the back and the legacy of a lot of attempts to deliver this project that weren't successful, and we are now in a position of having taken it further in its development than ever before.

Along the way, one of our core principles has to do things right by the state, and so to prioritize low-cost domestic gas as low as possible, to do the project as quickly as possible, and more above all, to make sure our contracts and our arrangements with the state are fair to all parties involved. There is no reason real path forward unless everyone feels like things are fair. One of those things that we think is fair is the state's clawback option. That's something that AGDC proposed to us in our negotiations. It's something that AGDC, in their capacity as representatives of the state, pushed for and advocated for.

And it's something that we, Glenfarm, saw as a fair protection to the state, and we agreed to have it implemented as part of our contract. Again, this is a mechanism that is only exercisable at the state's option. In terms of Glenfarn's ability to seek recourse or any kind of compensation, we don't have that mechanism. We can't ask the state to exercise this option. If Glenfarn decides to abandon the project, we do so with no recourse.

And that is the very important characterization of how this has been set up. Chair Chiraghi, again, Frank Richards for the record. One thing that I would add to my colleagues is that it was important from AGDC's perspective to allow the opportunity for the state with a callback position, but it didn't obligate the state to pay it. It would be something that we, if it was exercised, we would come back to the legislature to ask if they wanted to go forward with the opportunity to pay this. Or we have the opportunity then to be able to look to the open market to bring in another developer to be able to take on that expense and take on those responsibilities that Glenfarm is now doing.

Very good. Appreciate you addressing this issue on the front end. I know there's been a lot of media attention over it the last few days. One question that I would have, which has not been addressed as of yet, is who is able to claim value for any tax abatement that's provided by the legislature. I think I've not heard that issue addressed yet and would appreciate hearing from you on that.

Representative Sharkey, Chair Sharkey, that's, I'll say, somewhat of a unique question and really was not contemplated in any sense prior to the question being raised over the last few days.

It is beyond any practical sense that Glenfarn would be would be seeking this tax arrangement with any type of a view to evaluation in terms of if hypothetical after hypothetical occurred and the whole project fell apart. That's not— that hasn't even entered into our thinking. That said, I understand the sensitivity around it, and we do have the view that if there were ever a cash consideration or a cash repurchase, we would not ask for the monetary value of any tax arrangement to be reflected in any repurchase. So Glenfarm's position is that you would not claim credit for any value added through tax abatement or other relief from the legislature? Representative Sharkey, essentially yes.

We would not ask for any numerical value to be assigned based on the implementation of a tax arrangement. Thank you. Senator Hoffman. Thank you, Mr. Chairman. Mr. Kissinger, you stated that the secret document, or however you want to call it, was stolen and not leaked.

That is immaterial. The question that I have, and I guess the answer is, with that out there, both Glenfarm and AGDC is willing to proceed and we can still potentially have a project. Senator Hoffman, through the chair, it was a draft document done before we finalized agreements. It's noise to us and absolutely feel like it should just be left that way. Thank you.

Senator Steadman.

Well, noise it's not.

One recommendation that you may want to consider due to the volume of individuals that have that document is to possibly redact some of the information in it and release it to the public. I don't see how you're going to pull it back.

My understanding from reading some of the articles that one of the news media person got it from somebody outside the building. Unconnected to the legislature. So where that came from, I don't know, but it's circulated. So I think dealing with the clawback, I recognize the effort being put in by Glen Farn and the potential value that we're talking about here in hundreds and hundreds of millions, if not billions of dollars dealing with this. Project, it's significant.

And that I'm sure we'll be looking as we go forward in this process to ensure that there's, um, that it's clearly delineated that there could be no monetary value put on that, um, concession, whatever concessions we make here with property tax. So it won't be left up to an arbitrator in, in arguments. It'll be— you know, just as clear as we can make it.

As far as it being a hypothetical potential of not going forward with the project, I don't believe it's that hypothetical because we've had numerous gas line projects that have not succeeded. This is just the latest one over the last 30 years. And there's a lot of FERC permits issued that never come to fruition. The projects aren't built. So it's a real instance that this project may not go forward.

How the, if that does happen, which I think none of us wanna see, but if it does happen, how Glen Farm is separated out willingly, unwillingly, Whatever happens, AGDC, you know, that's a statutory issue we have to deal with. All is left up to the future. But clearly there's a reasonable chance that this project, as large and as challenging as it is, will not go to fruition. And when we look at the FERC timelines, the clock is ticking. And we recognize that.

I think the deadline is May 21st of '30, '30, and then there's export deadline in '32. So we'll be having those discussions here also, working with our deadlines with your FERC deadlines. So this is, I don't think it was overly hypothetical when some of us at the Senate Finance Committee brought up the potential. I think it's a real concern how the— if we end up crossing the bridge, how the dissolution happens is yet to be, you know, be seen and worked out. But my recommendation that I'd like you guys to consider is some form of a public release of that document, just because it is so prolific and people are going to— be concerned about things that aren't in there or there's these other controlling documents, contract, and it's a draft.

So you got two issues there. They can draw erroneous conclusions from just reading that in isolation. And we've tried to ferret some of that out in our questions.

And I think the buyback is one of them. There's mechanics if you take a literal interpretation of that document, it may not be as accurate as looking at it in the entirety.

Senator Steadman, through the chair, if you would be willing to provide us with a copy of that document, then we can consider redacting it and reviewing it. But as of now, we've only been able to look at that document. We don't have, uh, we don't have our own copy of that. Of that document. I don't believe every member of the committee has a copy of that document.

That was Mr. Kissinger for the record. Any follow-up, Senator Steadman? No. Speaker Edgeman. Yes, thank you, Mr. Chairman.

I wanted to maybe build a little bit on this line of questioning because to Senator Steadman's point about the amount of attention it attracted, both in mainstream media but as well social media, definitely, as best as I could observe, lent sort of an aura of scrutiny that maybe wasn't there before on this whole effort, or at least brought in sort of a different audience, if you will. But my questions, I'll see if I can weave all this together in one overarching question, but is the draft document that got leaked or stolen or whatever it was, is that part of the eventual definitive agreement? Number one, and it would be interesting to know, again, to sort of contextualize this a little bit more because there's a lot of people interested in what this may or may not have divulged. Is this the only provision of concern that you're aware of that came from this document? And then it also perhaps to Glen Farn would be interesting for the listening audience to know if the competitive disadvantage that might have ensued from all of this, if that sort of has played itself out, or is that a real ongoing sort of concern?

Through the Chair, through to Speaker Edgeman, again, Frank Richards for the record. The document that we are discussing today is a draft document that AGDC staff created specifically to provide information to AGDC's board while we were working on the definitive agreement. It contains a summary description of the, the documents that we were negotiating with Glenfarm at the time, specifically naming them, but it also includes information around the selection of Glenfarm as the lead developer as compared to other parties. And so there is commercially sensitive information in there about other parties that we would find, again, would breach our confidentiality agreements with those other parties. So that is of concern to me that, and I tried to address this in the public media, is that we have put out a confidential document within the confines of the organization, AGDC, and our board of directors, and then it has miraculously arrived now into the halls of the the Alaska State Legislature.

That's unfortunate because it creates, again, this dialogue, but it provides potentially then commercially damaging information to other parties who aren't at the table today, who we have confidential information— confidentiality with, but then also to Glenfarm now as the lead developer. And I'll allow Adam to describe the impacts to them. Senator Prestidge, for the record.

First, in response, Senator Hoffman, you asked about Glenfarm's willingness to continue to pursue the project, and we're absolutely willing to continue to pursue the project, and we will. It doesn't— it creates a little bit of a hesitation around how— around business principles and how, you know, how we will be able to trust certain confidential— confidentiality protections.

With respect to Speaker Edgeman's question in terms of how this impacts the project, what I can tell you is that throughout all this process over the last— particularly over the last 4 weeks of the special session, now going to the second special session, my team, myself, our CEO and founder, many other members of our team are getting daily calls from our counterparties who want to know what's happening in the legislature. You would be very surprised. Asian utility LNG buyers are actively tracking the committee process on a daily basis, calling us and saying, what's happening with this version? What's happening with that version? And it's, it's not just LNG buyers.

Its international construction contractors, its investors, it's the US federal government are all watching to see what's happening here. And it is a— it does— it presents a challenge. It's not an easy thing to explain that confidential preparation materials or briefing materials from a state agency were leaked and ended up in the media. So it's not something that outside parties would find as a positive for conducting business in the state of Alaska. However, it is where we are today.

We still think the project is a good, strong project, and the reason that we're here, this tax arrangement for the pipeline, will facilitate significant advancement on the project and allow it to go forward. So that's, I guess, the— Response to Senator Hoffman and Representative Benjamin. Uh, Senator Croft. Um, thank you, Chair. Way before my time, I think this legislature created AGDC to work on the behalf of Alaskans to bring a natural gas pipeline, and I, I think we've spent nearly a billion dollars doing that.

Um, I, I believe it's up to us to put the trust in AGDC to bring that project to fruition, and if we're going to second-guess or sit here and second-guess, I don't think there's going to be a project that's going to come forward. I think We put our trust in these people to bring this forward for Alaska. I mean, that's just the bottom line. So I think we should, you know, sit back and allow them to work the process. I mean, obviously I don't think we want to be in the closet or in the darkness on anything that's out there, but this is what we've paid them to do.

Thank you. Thank you, Senator Cronk. Senator Steadman. Just some of the earlier comments about the document and the sensitivity of it. I would agree that there's some information in there that's best left to be private.

And you've— Mr. Richards has expressed that several times here at the committee. I would recommend you redact that information out of them if you were to release it. It seems like the bulk of that document is not commercially sensitive from what I could see. There's a few things in there that's best left private.

Very good. Representative Ruffridge. Yeah, thank you, Chair Froggy. Couple questions, uh, just based off of what Senator Cronk was asking. I think, uh, first question, uh, do you have at AGDC the statutory definition to ask— act in the best interest of Alaskans with your project development?

Through the chair, Representative Ruffridge. Yes, we do. That was in our enabling statutes, and I believe it's in the 3125— Alaska Statute 3125.05. Thank you. And a follow-up, if I may, Mr.

Chair. Yes. Why would a confidential document be in the best interests of Alaskans? Through the chair, Representative Ruffridge. When the legislature created us with House Bill 9 in 2013 and added to it in Senate Bill 138 in 2014.

It was at the time that we were looking to advance projects to be able to deliver energy for Alaskans and to commercialize the North Slope natural gas resources. That was our mission. As such, the legislature saw that we were going to be acting in a commercial realm where we needed to be able to exchange information, share information with potential partners, and that would be commercially sensitive. So they gave us specific confidentiality provisions in those Alaska statutes, Alaska Statute 3125, to hold information confidential. So they— the legislature at the time gave us these powers to act as a commercial— in a commercial entity for the benefit of the state.

And to be able to work as such in that arena by holding information confidential. Thank you. Mr. Chairman. Yes, Speaker Edgeman. Yeah, so I, you know, I don't think we need to belabor this point.

We have a lot of work in front of us, but as an onlooker, I've not been sitting on a committee that's been hearing this issue. It's been a little troubling to me. To hear whether it's legislators or others, you know, sort of make this a binary issue. You're either for the gas line or you're against it. You're either for AGDC or you're against AGDC.

I don't see it that way. I think there's a tremendous amount of intricacy. There's nuances at every turn on this issue. There's complexity from the policy perspective, all of that and above. And I really appreciate the forthcoming sort of responses we've had here already at the start of this meeting, and we look forward to that continuing.

But just for anybody listening, knowing that this issue is, as you described it, it is what at the moment the largest energy infrastructure project on the globe, on the planet. And in terms of protecting the state's interest while also giving the developer and certainly AGDC the tools it needs to to get through this project. It's at times a very delicate balance. So I just want to be very clear that this notion that you're for or against something just outright is not necessarily the case. Thank you, Speaker Edgeman.

I would have to say that I align myself with those comments strongly, but appreciate them. With that, not seeing any additional questions from committee members at this time, Mr. Kissinger, please proceed. All right, this is Matt Kissinger for the record.

Chair Schrag, these are the sections of House Bill 381 as it came out of Senate Finance Committee. I have all of the sections listed out here, but on the following slide, on slide 3, I've grouped them into functionally what they do. And with your permission, I'd like to walk through the sectional analysis based on what the different aspects do. Please do. Thank you.

All right. So I'll start first with tax provisions. Let's move on to slide 4 and 5. This is the real bulk of what the concession is that's being sought, is a tax abatement for a period until volumes hit 500 million cubic feet per day, or 5 years from commercial operation. So this is no taxes during the early part of the project when it is delivering gas clearly just to in-state customers.

After the abatement period, it creates this alternative volumetric tax. I have a further slide on that. It establishes some eligibility criteria, such as needing or requiring the Fairbanks Spur Line. Again, I have more detail on that. It establishes a collection and allocation methodology, appeals to distraint in case of nonpayment, sort of standard property tax statutes.

It has termination timelines. It has reporting requirements. And then, of course, there's definitions within that particular section. Such a broad section. Further, there are municipal impact grants.

Municipal impact grants are in lieu of property taxes during construction. According to the current statutes, any project that AGDC is a joint venture partner in does not pay any property tax during construction. And so this is us realizing that the project will have real impacts on communities. Those impacts will be during construction, not as much during operation, in fact. And so this is sort of to make sure that it's— the communities aren't holding the bag with respect to the project during the, the construction period.

Uh, further in Section 32 outlines conditions to be met, uh, and then there's an effective date that's set in Section 33. Going on to slide 6. This is one major change as the bill worked its way from the House through Senate Finance. As it left the House, there was somewhat of a complicated method of allocating the tax itself. There was a— I believe it turned out as a 13-cent, 6-cent, and 13-cent tax rate for the GTP, the pipeline, and the LNG facility respectively., but then weighted by the amount of capital that you spent.

This was really simplified as it went through the, the Senate Finance Committee to, uh, just a simple 6.2 cents before commercial operations of the LNG plant, 10.6 for, uh, the first 10 years of operation after you have the LNG plant moving. Then that doubles until 2060, and then in 2060 it doubles again. That last change, having it double again in 2060, really had the effect of removing all the sunset provisions that were included in the bill as it left the House and moved on to the Senate. So I think it made it a lot more streamlined, actually, in the applicability of it.

The tax rate is adjusted annually using a 5-year average Urban Alaska Consumer Price Index. And just for people's reference, when we say 1 MCF, that's 1,000 cubic feet of natural gas. Any questions? Not seeing any, please continue.

Municipal Impact Grant funds, as I said, the law establishes Municipal Impact Grant within the Department of Commerce, Community and Economic Development for up to $80 million. Again, as the House— as this bill left the House, There was an initial $40 million paid in, and then additional up to $80 million would be paid in, in $10 million tranches based on actual need. This simplified it again, requires a $40 million paid in at Phase 1, and an additional $40 million paid in at Phase 2. That's actually a very handy mechanism for fear that the original $80 million could have somehow been expended before you hit Phase 2, and you wouldn't have anything left for the impacts to Kenai if you had gone with that route. So this ensures that in Phase 2 you have sufficient funds for the impacted communities of Phase 2.

Impacted municipality hasn't changed. Definition includes North Slope Borough, Fairbanks North Star Borough, Denali Borough, Municipality of Anchorage, Matanuska-Susitna Borough, and the Kenai Peninsula Borough. Any questions on this? Please continue.

Section 32 sets this conditional effect. Essentially, the Commissioner of Revenue needs to determine 3 things have happened in order for this alternative volumetric tax and the tax abatement to take effect. First is that the primary owner or the primary developer has paid in that initial $40 million that we just spoke of with respect to the municipal impact grants. Second is that the property owners enter— enters into a project labor agreement. So that's not, you know, agrees to negotiate, but it actually enters into.

And that the property owner is committed to construct the spur line to Fairbanks. And then there's more detail with respect to the spur line to serve Fairbanks and the Fairbanks North Star Borough, that it must be sized to meet the reasonable projected demand, must be scheduled to commence operations within 2 years of the main pipeline commercial operations, designed to connect with local distribution infrastructure as they've been building that out with trucked LNG, designed to operate and deliver gas at the lowest reasonable cost. And then the important point is that it allocates costs across all system-wide consumers including to the export consumers to the extent allowed by federal law. Essentially, this is South Central Alaska would be paying rates to underpin that pipeline, but it should be acknowledged that the demand in Fairbanks, the potential demand as that grows, will lead to lower prices sooner even for the South Central customers. So there's a benefit to ensuring that that line gets underpinned.

Any questions? Please continue. Next, we will go into the utility buyer protections. I think it is best to hear this directly from the developer because these are very sincere developer commitments. So I would like to pass on to Adam for these.

This is Adam Prestidge for the record. Subject of much discussion and again, one of the things that we as a developer have done to protect the state be fair to the state, is an agreement to a price cap on the price of gas sold on the pipeline to regulated utility buyers, regulated buyers of gas. We agreed to have that set at a price of $16. As we have said, it is highly customary for a commodity price like that to be adjusted by by inflation, and we have structured this in the bill so that— or the bill has been structured so that the inflation is reflective of the underlying contract between the pipeline and the utility buyer with a cap on what that inflation can be. We also were supportive of language being added to the bill, and language was adding to— added to the bill to ensure that utility customers are not exposed to the risk of cost overruns or the cost of cost overruns.

And again, one of the key features of the pricing structure and the phased approach here is that after a certain volume of gas is brought online to the project, the price of gas will decrease, potentially very significantly. And another component here in the bill is that the price can't increase after there has been a decrease in the throughput.

Very good. This is Matt Kissinger for the record. Another aspect that came from the Senate Finance Committee was the introduction of the Alaska Affordable Heating Fuel Fund. Section 22 of this bill establishes the Alaska Affordable Heating Fund provides that 20% of remaining royalties after payment to the permanent fund are allocated to this fund, and that the legislature may make appropriations from this fund to reduce the cost of heating fuel in areas across the state that don't have access to the North Slope Natural Gas Pipeline.

Please continue.

Move on to the AGDC provisions. There are a number of AGDC provisions, adjusting the statutes that President Richards was just referring to. I will just move through these. First is AGDC as a fiduciary. This is language adding "and as a fiduciary" to existing language which already says that AGDC is a public corporation and government instrumentality acting in the best interest of the state.

So now it'll say acting in the best interest and as a fiduciary of the state. Um, the implications aren't that great, wouldn't change the way that we operate. Perhaps it would add a little bit more process to our board meetings in that the board members need to be reminded that they're acting as a fiduciary. I think it is pretty standard that board members of corporations across the USA have a fiduciary duty to their shareholders, and so again, this is not that impactful.

Thank you. On slide 15, AGDC procurement procedures are changed. Right now there is a requirement that the board adopt procurement regulations. This law changes that to include some of the Administrative Procedures Act language around competitive bidding, having procurement methods to meet emergency and extraordinary circumstances where you don't need the competitive bidding, and then comply with the 5% preference under AS 3633.

321. That's the Alaska preference where Alaska bidders can essentially have a 5% greater markup. And then Section 15 just amends the AGDC statutes to enact Section 7. Not seeing any questions. Please take us to slide 16.

On slide 16, there are AGDC JV and disposal limitations for— on a go-forward basis. This would have impacted our ability to transact with Glenfarm had this been in there historically. What it does is it requires that we get legislative— that we notify the legislature if we intend to dispose of or sell off any of the AGDC assets or ownership in any of the AGDC subsidiaries, JV partnerships. The way it's crafted is it's a disapproval. There are 90 days.

These are not legislative days, so it is crafted in a way that would ostensibly allow us to operate in the commercial world and rather than in the legislative world, which is important. But it does reduce that sort of ability that AGDC has now to do that with just board authority. And Mr. Kissinger JV is joint venture? That's right, Chair Schragi, joint venture. All right, not seeing any questions, please continue.

Slide 17 is about investment options. This is referred to as involvement in revenue-generating projects in the bill. Sections 14 and 31 apply to this, and what it does is it, it basically requires that in the future we do what we did already in the past with Glenfarm, where we negotiated this opportunity for the state to participate in up to 5— between 5 and 25% of all capital raises in the 8-star structure. And this would just require that any future negotiations, we have to do that. So take, for example, if there was an expansion, maybe a 4th train, uh, or additional pipeline capacity, uh, anything that would require additional equity to be issued and capital raised, then we would have that.

We, we would be required to negotiate that, which I think we would have done anyway.

Please continue. Slide 18 refers to the confidentiality restrictions. It adds in Section 10, just subject to restrictions, and the restrictions are outlined in Section 11. It's a new subsection to the AGDC confidentiality agreement powers. It does provide a method to release information provided the parties agree.

It allows for information subject to confidentiality agreement to be shared in committee sessions, again, if we consent and if one or more parties to the confidentiality agreement are there to testify. But the real limitations are here in that it may not— we may not enter into a confidentiality agreement that prevents compliance with an administrative court order mandating disclosure. That's standard. Make any terms confidential that could extend to or encumber the state or may lead to a significant fiscal liability, obligation, risk, appropriation, or other state funding or in-kind payments to the state. So that's a change.

Or make any terms confidential related to the existence of a state interest option.

This is something that we worked out in the House while the bill was going through the House, trying to find this fine line between when AGDC is allowed to operate with full confidentiality and when it's important that the information that was negotiated under confidence is provided to the state so that the legislature and the people are able to make an informed decision.

Questions from committee members? Not seeing any. Please continue. Slide 19, revenues and bonding. Right now, under the current statutes, AGDC has extremely broad bonding authority.

We can raise revenue bonds provided there is no recourse back to the state without any further approvals other than board approvals. This would require AGDC to come to the legislature for approval of any of those bonds. Again, we did frame this under 90 days, not legislative days. That would need to be approved by law, so I believe there would have to be a special session were we to try and do this. But at least that provides us with, again, within 90 days, hopefully that would be a timeline that would allow us to operate within the commercial world.

No questions? I think that takes us to slide 20. Slide 20 is other AGDC reporting and notifying. This changed quite a bit as we went through Senate Finance. There was the inclusion of a dashboard concept that AGDC would have to maintain.

But in addition to that, by February 15th and August 15th of each year, AGDC board would have to deliver a report on the pipelines to the, to the Commissioner of Revenue, must notify the governor and legislature and publish it on the online public notice system, must provide a qualitative assessment and update of the timeline, budget, and cost containment progress, must provide current status of the projects including construction status, projected timeline for completion, and description of remaining phases and provide an assessment on the effect of the projects on the state's labor market. Further, in Section 20, there's also a require— requirement that AGDC notify the President of the Senate, Speaker of the House, and the chairs of each finance committee if an entity in a legal relationship with AGDC plans to make a significant change in ownership structure. So if there's a sale by one owner of, of 8 Star Pipeline LLC to another owner of 8 Star Pipeline LLC and it meets the threshold of being significant, then we would need to report that. And then further, there's a final report that AGDC under Section 29 must provide before Phase 2 investment, the final investment decision on the effectiveness of this legislation at all.

I'm not seeing any questions. Please continue. The remainder of this are what I call the technical provisions. As a non-lawyer, as I read through these, there's the Section 1, which is findings and intent. Section 2 does have the public school funding calculation, so that is not just purely a technical issue.

I know that that can be a contentious issue around how that's done. Section 3 removes property from the local contribution calculation. Section 4 removes it from the municipal property taxation. Section 6 removes it from the municipal tax cap. Section 24 removes the property from state property taxation from the definitions.

Section 25 conforms to Section 24. Section 30 ensures that these AGDC limitations are on a go-forward basis. Section 34 establishes an immediate effective date. Chair Stronge, that is all I have for the sectional analysis, but I am happy to answer any questions on the bulk of the document. Do committee members have questions for AGDC while we have them before the committee today?

Speaker Edgeman. Yeah, I think I will just— thank you, Mr. Chairman. I think I will just throw out a general question. I am not sure where this is actually I know you're leading, but it's interesting in the Municipal Impact Grant Fund that the property owner must deposit $40 million into the fund within 60 days of Phase 1 FID, but then there will be additional contributors, right, during Phase 2, and as the project evolves, the equity structure changes, you may get more people contributing into this fund. But is this fund ever— in terms of who actually is contributing to it made public?

Mr. Kissinger. Yeah, Speaker Edgeman, through the Chair. So the municipal grants will come from the property owner, but that will be the lead developer. So in this case, it would be Glenfarm. So as there are changes to ownership structure within 8 Star, there won't be different amounts deposited.

It's just simply a $40 million deposited on the FID of Phase 1. Another $40 million deposited on the FID of Phase 2. Representative Ruffridge. Thank you, Chair Sharkey. I think this is actually just a request for you, Mr.

Chair, maybe not within AGDC purview, but Sections 2 and 3 are sections of the bill that I personally would just like to discuss at some point. They seem to be there's some challenges in how those are written, and I don't know if that might be something for another day, but I don't think you, you all have any comment on that. I wouldn't imagine. Representative Ruffridge, I think we will have an opportunity for that likely at tomorrow's meetings, so we will work with you to make sure that that is addressed. Uh, Senator Hoffman.

Thank you, Mr. Chairman. As we worked on this bill Senate Finance, it was quite late in the first special session, and as a result of that, we were not able to hear any responses either from AGDC or from Glenfarm on the final product that came forward in, in this version. I'm wondering if If you might comment on the CS at this time, I mean the presentation concerns.

Senator Hoffman, through the Chair, just to clarify on the version that came through the Senate Finance Committee. Would you like to start? Senator Hoffman, Adam Prestidge for the record. We would be very happy to walk through that. Personally, my expectation is that will happen in in follow-up hearings over the next couple of days.

If you'd like, we can quickly put that assessment together and talk about it later this afternoon. I just don't have all of those notes in front of me to give a kind of comprehensive reaction right now. We'll wait for our seal of approval.

This is Matt—. I'll add some more. This is Matt Kissinger for the record. Senator Hoffman, through the chair, From AGDC's point of view, you know, obviously we feel that the statutes as they were written have served AGDC very well and have gotten us to where we are. But we understand that as the project evolves, then AGDC statutes and our requirements would naturally evolve.

One place that we would like to at least refocus on, and it feels like there was never any disagreement, it was just that the language never quite came out to reflect what we are trying to achieve is if AGDC has bonding authority and we do issue bonds, or if we have co-investors such as the municipalities that co-invest through an AGDC vehicle, it's important to us that as revenues in the future flow into AGDC, AGDC are able to service those bonds and pay those co-investors without those payments going through the appropriation process. And that just never came through the way we were trying to word it.

Senator Hoffman, would you like any follow-up? No follow-up. Thank you, Mr. Chairman. Additional discussion from committee members? All right.

With that, we are going to take a brief at ease before transitioning to our next presentation. We are at ease at 2:56 PM.

All right, back on the record at 3:00 PM. We'll now move on to our presentation from the Department of Revenue. Mr. Stickel, Chief Economist for the Department of Revenue, if you could please come up to the table, put yourself on the record, and when you're ready, take your time, begin with your presentation.

Good afternoon. Dan Stickel, Chief Economist with the Department of Revenue. Thanks for the opportunity to come and present on the Senate versions of the AKLNG legislation. So the beginning part of the presentation Well, the presentation generally follows the same format of the way that we've been presenting this in the various committees throughout the process. So, for folks that have tuned in before, the overall flow and information should be familiar.

So, we start with a list of acronyms here on slide 2. Lots of jargon in the industry. Include this as a reference as we're going through the presentation. So we will start by giving a little bit of background on the property tax itself. We will walk through the proposed legislation and revenue impacts and detailed project modeling.

And then we were asked to provide some information for the committee on the calculation detail of the alternative volumetric tax and how that rate in the bill— in the bills that came out of the Senate compares to the bills that came out of the House.

So slide 5, a little bit of background on the property tax. So the essence of the bill before the committee is a change to— is a reduction to the property tax burden of the project on the developer. The tax that we're levying— so Alaska levies an oil and gas property tax on the value of of all taxable exploration, production, and pipeline transportation property for oil and gas in the state. The state manages that centrally within Department of Revenue. It's a 20 mills, or 2% of assessed value tax.

Any municipal property taxes are allowed as a credit against the state tax. So for qualifying oil and gas property, which under this project would be the gas treatment plant and the gas pipeline, as well as any upstream oil and gas facilities, those would pay the 2% or 20 mils tax regardless of what the municipal tax rate is. The one exception to that is the LNG plant part of the project. So under current tax law, the LNG plant is not part of the taxable property definition for the state property tax, so that would only be taxable under the municipal property tax.

So moving on to slide 6, in our official spring 2026 revenue forecast, conservatively, we do not include revenue and impacts from the AK LNG project until— we'll reevaluate that assumption once there's a final investment decision on, on the project. So there would be no impact of a tax reduction under our official revenue forecast. If the project were to proceed without tax modifications, under current law, there would be a midstream property tax revenue to the state at estimated at about $24 million in 2029. That would be when, when there's first production from the project, and that would ramp up to about $239 million in 2030. '33.

Those are the state shares of the revenue. In addition, there would be municipal revenue of about $50 million in 2029, ramping up to just shy of $100 million or $500 million in 2033. So looking at nearly $750 million of annual property tax impact once the project's at, at full production, that's under our baseline capital cost assumptions. If the project were to come in higher than that, there's been information from the developer that the range may be higher than what we've been projecting, then the, the potential property tax impacts under current law would be even higher than what's shown on this slide. And that, in essence, is the burden on the project as well as the, uh, the revenue impact to the state and municipalities that the, the bill before the committee is modifying to benefit the project.

Please continue. So moving on to our summary of the proposed legislation. So a lot of this will be kind of a repackaging and reframing of the information that you just heard from AGDC, kind of showing our interpretation of various provisions and how they impact Department of Revenue. Do want to stress that these are preliminary interpretations. There will be a robust regulatory process that we will undertake, so nothing that I'm presenting is an official tax interpretation or statement on how we're going to treat the project when we go through that regulatory provision.

And then also, for the numbers that we are presenting, those are based on the spring 2026 revenue forecast that we came out, uh, we came up with in March is our baseline for the revenue impacts, as well as what we call our baseline AKLNG model. And I have a slide later on that will walk through some of the assumptions in that baseline AKLNG model. Some of those are dated assumptions, but they— we have used a consistent set of modeling parameters throughout this process. Process, and I'll walk through those later on. Representative Ruffridge.

Thank you. I think I just heard through the chair Mr. Stickell say that we were going to go through where those assumptions came from later on. Is that correct? Yes, Representative Ruffridge to the chair. I have a slide coming up.

It would—. I think it's in the 20s, slide 26, and I'll speak to that in a little bit more detail when we get to there. Thank you, Mr. Chair. Please continue, Mr. Stickel.

All right, so slide 9, what would this legislation do? So broadly, it creates the policy framework for replacing certain state municipal property taxes with a temporary tax abatement period followed by implementation of the alternative volumetric tax. Specific to Department of Revenue is the eligibility condition and various detailed information around the revenue collection and allocation. One additional bullet point that should have been on this slide for the version that passed out of the Senate floor is the implementation of a new pass-through entity tax that would apply to certain oil and gas companies in the state.

Please continue, Mr. Stickle. So slide 10, eligibility conditions. Under this version of the bill, to be eligible for the tax exemptions and the alternative volumetric tax, the company— the developer must satisfy to the Commissioner of Revenue that they have paid $40 million into the state within 60 days of the there's a final investment decision of Phase 1, and that would go to those municipal impact grants. And then they— that they've made a commitment to pay an additional $40 million when there's a final investment decision on Phase 2. They must commit to enter into a project labor agreement for construction of the gas pipeline, and then they are responsible for committing to construct a spur line to Fairbanks.

Slide 11 has a little bit more information around the specifics of that spur line. So the spur line commitment must be scheduled to begin operations within 2 years after the start of commercial operation of a component of the project. Practically speaking, that would be Phase 1 of the gas pipeline. So within 2 years of gas flowing to South Central operations would— they would need to have a plan to have operations of the spur line to Fairbanks. The spur line has to connect into the local distribution infrastructure in Fairbanks.

So there was some concern in previous committees that potentially there could be a spur line that bypassed the local residents and went straight to a major industrial customer or military base. Under this language, the spur line does have to connect directly into the Fairbanks distribution infrastructure. And then importantly, the costs for constructing that spur line are required to be allocated system-wide. And so that would include not just the customers in, in the interior that are benefiting directly from the spur line,. But also those costs would be shared among South Central consumers, and to the extent allowed under law, those costs would also be shared with any export consumers.

And the developer needs to commit to begin the permitting and regulatory actions before completing Phase 1, and then they have to commit to begin spurline construction within a year after receiving those requirements. Required permits and approvals. All right, thank you, Mr. Stickel. Please take us to the AVT. Slide 12 talks about the Alternative Volumetric Tax.

So this replaces the, the existing property state and local property tax for the qualifying property. So there is a— under current law, a, a gas pipeline project with AGDC as as part of the project is exempt from property taxes during the construction phase. This bill would add an additional tax abatement period, and that tax abatement period would be up to 5 years of production or until the throughput of the pipeline exceeds 500 million cubic feet per day.

And during that abatement period, there would be no state or local property tax. There would be no alternative volumetric tax. Once the alternative volumetric tax— and the alternative volumetric tax, that would apply only if there is a final investment decision before January 1st, 2028, only if the pipeline construction is complete by 2030, the end of 2032, and only if at least one component is in operations by 2037. And so if any of those three requirements are not met, the ABT and the tax abatement would repeal and the project would revert to current law property tax.

Slide 13 lays out some additional details around the alternative volumetric tax. As I mentioned, the tax abatement is good for 5 years or until the project exceeds 500 million cubic feet per day. Practically speaking, that would likely be a situation where you have made the commencement of full exports. You could also envision a scenario where there was an extremely robust in-state demand to support that 500 million cubic feet per day threshold.

The alternative volumetric tax is based on a definition of throughput. The definition of throughput is gas coming out of the pipeline, so it's gas So the— any fuel gas used in the pipeline or in the gas treatment facility would effectively be exempt from tax. The tax would apply on gas leaving, leaving the pipeline, and so then any fuel gas used in the LNG export facility would be subject to the tax. The initial alternative volumetric tax rate would be 6.2 cents per thousand cubic feet. Before the LNG plant commences commercial operations.

So this would be the— when there's the pipeline only delivering in-state gas. Once the LNG plant commences operations and we have exports, that alternative tax rate would increase to 10.6 cents per thousand cubic feet. And after 10 years of export operations, there would be a doubling of the tax rate up to 21.2 cents per cubic feet. And then in 2060, there would be a doubling again of the tax rate up to $0.424 per 1,000 cubic feet. And all of these tax rates would be inflation adjusted.

As soon as the, the project comes into operation, all of these numbers would be inflation adjusted. It would be based on a 5-year average of Consumer Price Index inflation. Between a range of— with a 1% annual increase floor and a 3% annual increase cap.

Representative Ruffridge. Thank you, Mr. Chair. I did not understand fully how this would operate with the inflation adjustment when you start this doubling at 10 years Would that number that's in statute or would be proposed to be in statute of the 2 or 0.212, would that number continue to inflation adjust so it wouldn't be 0.212 or would it sort of reset the inflation adjustment at the 10 years of LNG operations? Representative Ruffridge to the chair.

So our understanding is that all of these numbers would be inflation adjusted. So these are all the base numbers and so So yeah, once the— after the 10 years, it would be some number higher than the 212 that would be added. Okay. Thank you. And Mr. Stickel, the final AVT rate of 42.4 cents, is that in perpetuity at that point, or is there a termination on that?

Representative Sharagi, through the Chair, so that would be in perpetuity under this This version of the bill, there's been previous versions of the bill where the AVT would sunset out in 2060. Under this Senate version of the bill, it would be the 42.4 cents as adjusted by inflation, and then the inflation adjustments would extend into perpetuity. Thank you, Mr. Stickell. Not seeing additional questions at this time, please continue. Alright, so slide 14 talks about the collection and allocation of the alternative volumetric tax.

And then in the appendix, we talk about how these different percentages were arrived at. So the House version of the bill had a series of formulas that had a little bit of complexity to them that walked through capital allocations by community, by project component, and came up with— ultimately you use those numbers to arrive at a share of alternative volumetric tax that was allocated to the state and to various communities. In the Senate version of the bill, they've simplified that calculation and put in set percentages of alternative volumetric tax that goes to each stakeholder. So the state would levy and collect the alternative volumetric tax allocated to the state. Municipalities would have an option.

They could either collect the tax themselves based on the— as the state, we would let the municipalities know how much tax they're due, or they could elect to have the state collect on their behalf and then share it back to them the same way that we do with other shared taxes, uh, such as we have certain shared fisheries taxes, uh, cruise ship taxes, things like that. So initially, when it's just the pipeline, uh, the alternative volumetric tax would be 6% to the North Slope Borough, uh, and 47% to impacted communities or the state, uh, based on pipeline mileage. Um, the state would retain the share of that 47% for pipeline in the unorganized borough, and then for pipeline in organized communities, it would go directly to the communities. And then the remaining 47% would go for community assistance payments and would be shared to all communities across the state based on population. Once the LNG plant commences operation, there would be another set of formulas with 48.4% to the Kenai Peninsula Borough, where the LNG export plant would be located, 27% to the North Slope Borough, where the gas treatment facility would be located, 5.6% would be retained by the state, and then 9.5% would be shared to communities and the Unorganized Borough based on pipeline mileage, and the remaining 9.5% would be shared with the community assistance program.

Now, 10 years after export operations begin, there's that first doubling of the tax rate, and that doubling of the tax rate is allocated entirely to community assistance payments. So you see a very significant increase in that community revenue sharing at that at that 10 years of export operations. And then in 2060, when the, when the AVT doubles again, that second doubling goes entirely to the state. So that 2060 increase would be a significant increase in revenue to the state of Alaska.

Not seeing any questions, please continue, Mr. Stickle. So moving on to slide 15, under our baseline modeling assumptions, um, we, we calculate $42 million of total AVT revenue in 2031. This would be after the, the first year after the end of the abatement period when we expect that export operations would begin with the first train of LNG, and that would increase to $132 million in $1.2 billion in 2033, which is when, when the modeling assumptions have full project capacity with the 3.5 billion cubic feet of gas into the pipeline and about 3 billion cubic feet of LNG being exported. When the alternative volumetric tax doubles, we model that in 2041 and there would be $322 million of total AVT revenue. And you see that's more than, that's more than just a doubling of the $132 million because we do have the inflation assumptions in there as well.

And then come 2060, with the second doubling, there would be about $1 billion per year of annual AVT revenue. Now the state share of that revenue varies across the years. So initially it's about 9% of the revenue in 2033. With the first doubling of revenue in— of the AVT rate in 2041, the state's share drops to 5%. But then with the second doubling in 2060, the state's share increases to 52%.

And so this changing state share is important to keep in mind when we're walking through detailed analysis of state revenue. And then, yeah, so that— we calculate out what that relates— what that translates to in terms of unrestricted general fund revenue to the state. So $4 million in 2031, increasing to $12 million in 2033, $15 million in 2041. And then come 2060, when we have that second doubling of the rate that goes entirely to the state, the state revenue just from the AVT would be over $500 million. $1 Million per year.

Okay. Please continue.

Slide 16 talks about some of the fund and revenue provisions of the bill. As we talked about earlier, creates the municipal impact grant fund in the Department of Commerce, Community and Economic Development, and that would be funded by the initial $40 million payment by the developer with FID of Phase 1 and then an additional $40 million with FID of Phase 2. And those funds could be distributed by the Department of Commerce to offset expected or realized costs related to supporting the gas pipeline for the impacted municipalities. The bill also creates the Alaska Affordable Heating Fuel Fund, which is funded from 20% of the gas royalties for gas going into the AK LNG project after the permanent fund. And this is in addition to the existing Affordable Energy Fund.

So a total of 40% of those gas-related royalties after the permanent fund calculation would would be set aside for these two affordable funds, the Affordable Heating Fuel and the Affordable Energy Fund.

Speaker Edgeman. Yes, thank you. I'm trying to get a handle on these different revenue streams and looking at the graduated scale on the AVT. I think that's pretty clear how that increases, and there's accompanying dollar amounts or projected dollar amounts. But in terms of the Alaska Affordable Energy Fund and the Home Heating Fund, those are all based on the royalty value at wellhead, which, what is it, $1 or $1.50 now per MCF or something like that.

That will be a— a flat rate in time, right? Mr. Stickle. Speaker, Adjutancy Chair, so you're correct, we assume a $1.50 wellhead purchase price for the gas in our baseline modeling. We do assume that that applies, that that increases over time with inflation. In terms of revenue impacts under our baseline modeling, which again I'll get into later on.

Come 2033, when we have full operations of the pipeline, the modeling assumption is about $35 million per year into each of these funds, into the Heating Fuel Fund and the Affordable Energy Fund. And then that number would increase slightly over time with inflation. And if I might, Mr. Yes, Speaker Edgeman. That's incumbent upon legislative appropriation too.

If I recall reading the language in the bill, it's may appropriate at least for the home heating fuel. I think it's also may for the affordability fund. So that's up to— again, based on flowage through the appropriation process where the AVT is not subject to appropriation process. Is that correct? Speaker Edmondson, the chair, yes.

That's correct. These would be designated general funds. And if I might, Mr. Follow-up, absolutely. Chairman, just to wrap things up, for anyone who expresses concern about the amount of money per se that might be going to the areas that aren't benefiting directly from the gas pipeline, that don't have the advantage of having a spur line, let's say, into the Waikay area or down in Bristow Bay where I live or up north in the western Alaska, the larger revenue stream is through the AVT tax.

And the way I read it, and please correct me, the considerably larger revenue stream. Mr. Stickle. Speaker, I just meant through the chair.

Yes, that's correct. The AVT tax is a larger revenue stream. Overall than the Affordable Energy Fund or the Affordable Heating Fuel Fund. However, for certain communities that are not impacted— for communities that are not receiving the direct AVT, so that would be communities outside the North Slope Borough, Fairbanks, Denali, Matsu, Kenai, the total community revenue sharing would actually be smaller than the deposits into each of these funds until we reach that first doubling of the tax rate. And then once we receive that doubling of the tax rate, if you'll recall, after 10 years of LNG exports, that first doubling goes entirely to community revenue sharing.

And then at that time, the community revenue sharing becomes a larger revenue stream than in the deposits to either of these funds. Okay. And Mr. Chairman—. Yes. —Thank you for the latitude and thank you for the distinction, Mr. Stickle.

Very good. Appreciate that dialogue. Additional questions at this time? Please continue, Mr. Stickle. All right.

So slide 17 just touches on some of the other provisions of the bill. So again, we have the— per— the per million BTU price cap for contracts.

And the RCA would not be able to approve contracts that require customers to assume construction cost overruns. So the price cap and the cost overrun are two protections that were— that have been inserted throughout the process for the price— for the rate that's ultimately paid by Alaska utility customers. We have the two semiannual required reports from AGDC and then a number of other governance and transparency provisions for AGDC that we heard about earlier.

Very good. Please continue. And so that set of information that we walked through so far was the version of the bill that came out of the Senate Finance Committee and was left largely the same in the version that passed, that passed out of the Senate floor. Slide 18 talks about the, the Senate floor amendments and the The biggest one of these was the— that directly impacts the Department of Revenue was the implementation of the pass-through entity tax for oil and gas companies. This is a significant policy decision that's before the committee and the legislature.

So under current law, only C corporations doing business in the state are subject to our existing corporate income tax. This bill would create a tax on pass-through entities that are doing business in the oil and gas industry, and I believe we have another presentation tomorrow that will go into more detail on the technical and implementation aspects. We'll have our tax director available to assist with presenting that information.

The pass-through entity tax that came out of the Senate floor applies beginning in 2028 tax year and applies only to oil and gas companies. So a company that's not directly involved in the oil and gas exploration, production, or pipeline transportation would continue to be exempt from state corporate income taxes. There would be a zero tax rate on taxable income up to $1 million per year. Then the top, there would be a series of marginal bracketed tax rates with the top bracket being 9.4% of taxable income over $5 million per year. We note that this would apply to all companies, all pass-through entity companies doing business in the state regardless of whether the AK LNG project moves forward or not and would have material state revenue impacts as well as material investment economic impacts for the impacted taxpayers regardless of what happens with the AK LNG project.

All right. Please continue. I'm sure we'll have more discussion on this at a later meeting. But please continue.

So moving on to slide 19, in terms of our revenue analysis, so we look at this two ways. We look at this under the existing spring 2026 revenue forecast and then under our AKLG modeling. So under our existing revenue forecast, about two-thirds of in-state oil and gas production currently comes from companies that are subject to the corporate income tax. We have estimated a, a range of annual impacts of between $0 and $100 million per year of incremental state revenue that would come from implementing this pass-through entity tax just on the existing oil and gas operations. Now, why do we have a range there?

Well, for in any given year with a limited number of taxpayers, you can have a loss situation, tax refunds. You could have a situation where there's zero net collections. At the high end of the range, if you have a year where there are none of those refund or loss situations, you could have close to $100 million per year. And we've heard, we've heard from some impacted taxpayers that the top end of the range may be an aggressive assumption. And so we continue to present this as a range.

In some of the coming slides, we, we present the midpoint of that range, which is $50 million per year. As an illustration.

Under the AKLNG project, this would also apply to incremental revenue from the project. So we assume that about two-thirds of the upstream oil and gas production associated with AKLNG would be subject to corporate income tax. Um, this pass-through entity tax would apply to that remaining one-third of production. We assume that the midstream operator is not subject to corporate income tax. And so this pass-through entity tax would also apply to the midstream operator under our modeling.

Continue, Mr.— excuse me, Mr. Stickel. Representative Ruffridge. Thank you, Chair Schraggi. And I— it sounds like we have the intention to work through this maybe in greater detail. And one of the details that I would like to try to understand from the Department of Revenue's perspective is how a pass-through entity tax would be implemented from the Department of Revenue, particularly since that's passed through usually to either one individual or multitude of individuals.

And then as you reference on this slide, there's multiple ways to sort of drive down what those profits are under those returns, especially when you have large-scale investment. How could you even come up with a very— it seems difficult to model. Is that the reason we have— I mean, zero seems like a funny number to have in there, but is there a possibility that given those large-scale investments that really zero could be a tax that's paid if we figure out a way to implement this? Sure. Representative Ruffridge, through the Chair, kind of two lines of questioning there.

One, the presentation that Department of Revenue will be bringing tomorrow goes into detail on the implementation and the technical details, and we'll have our tax director as well as our corporate manager available for that presentation. For the modeling For the modeling itself, we do have a baseline. It's a deterministic model, so it's a stack, a series of assumptions that we've run through. For a tax, for a corporate tax or a tax such as this, there will be many years of very significant expenditures. Those expenditures will generate net operating losses, and those net operating losses can carry forward and offset up to 80% of tax liability for many years until they're exhausted.

There's also depreciation expenses associated with the investment, and so we actually, we assume that for the midstream operator in particular, that there would not be any corporate, any pass-through entity tax paid until 2036. So they are able to use those losses for the first portion of the operations. Again, that's a modeling assumption. Representative Ruffridge. Yes, thank you, Mr.

Chair. You are taking those same assumptions then because this was for oil pass-through as well. Those assumptions are the same for that, I assume? We are using the word assume a lot, I am sorry. Sure.

Representative Rafferty, there are a lot of assumptions in here. Maybe if it is all right, I will move on to slide 20, which gets into that in a little bit more detail.

So this looks at— so on slide 19, I talked about our spring revenue forecast. Under our baseline revenue forecast, and we put that range of $0 to $100 million.

Out there for the spring revenue forecast. Under our baseline AKLNG modeling, we estimate incremental upstream revenues of $102 million in 2033, and then an average of a little over $90 million beyond that. And what this represents is the, the estimate of the increased corporate income tax on the producers that would be subject to the tax that would be contributing oil and gas specifically into the AK LNG project. And this is separate from that $0 to $100 million range in the baseline revenue forecast.

And then separately, we, we analyze the estimated impact on the midstream operator, and that's where we see significant losses and appreciation for building out the pipeline and the treatment facility and the export facility. So for that midstream operator, we're estimating $29 million in 2036. That's the first year of expected revenues. That increases to $65 million in 2041 and then up to $358 million in 2051. And what that shift from the 2041 to the 2051 represents is the exhaustion of those carryforward net operating losses.

Representative Ruffridge. Thank you, Mr. Chair.

So maybe to simplify this for me, if you have an entity who is consistently investing large-scale infrastructure dollars those large investments are always able to, or are usually able to offset any sort of revenue gain from the investment itself. Potentially if they continue to invest infrastructure dollars, you could perpetuate this sort of depre— or I guess lower value of tax paid in perpetuity.— is that an accurate assumption again? Representative Ruffridge, through the chair, yes. So a company that continues to make investments would— the capital investments would have a depreciation schedule and those would reduce the taxes owed. Okay.

Thank you. Very good. Please continue, Mr. Stickel. All right. 21 Is a chart of the state corporate income tax revenues by year.

The incremental state corporate income taxes by year from the pass-through entity provision, again, under our baseline modeling. So there's 3 numbers here. In the blue bar at the bottom, we include the midpoint of that $0 to $100 million range. So we were showing the $50 million per year. We increased that with inflation.

And so this shows the incremental expected corporate income tax just for the existing oil and gas production in the state revenue forecast. The orange bar on top of that represents incremental impact of of increased oil and gas upstream that's associated with the AK LNG project. And then the gray bar represents incremental corporate revenue associated with the midstream developer. And so you see during the first several years of the analysis, the The impact would essentially be that $50 million for the current oil and gas production, and then once full export operations begin in 2033, you'd start to see more revenue, just shy of $200 million a year total, but you'd start to see more revenue from the oil and gas production in the upstream, and then once you get out into the later years of the project and you start to see the significant potential revenues from the midstream developer that the corporate income tax impact could be over $600 million per year from this provision.

Please continue, Mr. Stickle.

Slide 22 is a similar slide. This shows our Phase 1 only. Analysis. And so when we get into the detailed project modeling, we have a few different Phase 1-only slides. And what this represents is a scenario that we've been asked to, to look at by various committees where there's an FID on the first phase of the pipeline, and the pipeline to South Central is built, but the gas treatment plant and export facility are never built.

And so under this scenario, we would still have the incremental impact to corporate income tax for existing oil and gas production, and we would still have some corporate income tax from the midstream operator later in project life. Not a significant increase in corporate income tax for the gas being put into the project from the upstream.

But once we get to the end of the project, under the Phase 1 only, still looking at potentially up to $300 million per year of pass-through entity tax income.

Representative Ruffridge. Thank you, Chair Shiragi. I just want to understand again slide 21 and 22 sort of in in combination with the question I asked previously about reinvesting dollars. If this assumption, let's say on slide 21, from 20— looks like '46 and moving onward, is that there is the assumed, I would say, increase in potential revenue from a corporate income tax, that is only if the entity in question here does not take some of those dollars and let's say they reinvest those things in an export facility expansion, maybe an additional gas line, other sort of areas, all of those potential revenue dollars would have— could disappear. Is that an accurate assumption?

Representative Ruffridge to the Chair, correct, yes. Okay, thank you. So the assumption is that there is significant capital expenditure for the Phase 2 and then kind of a steady-state operations beyond that. If the developer were to do a significant expansion, yes, that would reduce their corporate income tax liability.

Okay, okay, very good. Please continue.

All right, so Slide 23 just touches on some of the other provisions that were made in the Senate floor amendments. So there was some expansion of the project labor agreement requirements. There was prevailing wage and apprenticeship requirements that were added. There was an allowance for Commissioner of Revenue to extend project deadline dates in the event of a force majeure, and then some, some changes related to school funding and local contribution.

Moving on to slide 24, there were some additional amendments related to utility, AGDC, and governance provisions.

The $16 per million BTU price cap was tweaked in how the inflation adjustment applies to that and various other AGDC provisions as well.

Questions from committee members? Not seeing any. Let's go to the next section. And so, okay. This section walks into our detailed project modeling, and this is a fairly robust section of analysis.

We'll start with slide 26, which is the key assumptions. I know there have been— there's been— there was a request to talk a little bit about where these assumptions came from and kind of our process here. So maybe I'll start with a little bit of background on that. So we have been developing and maintaining an AKLNG model for multiple decades. A lot of modeling was done during the Palin, the Murkowski administration, then the Palin and Parnell administration, Walker administration, and now Dunleavy administration.

And so some of these, many of these assumptions were developed under the producer-led pipeline project under Parnell administration and then modified under the state-led pipeline project under the Walker administration. And so a lot of these— a lot of the assumptions were developed before Glenfarn came onto the scene. We have not received a lot of detailed information and details details on project plan from them, given confidentiality. And so we have carried forward many of these assumptions. There was a significant amount of work that was done in 2018 and 2019.

Department of Revenue worked in collaboration with Department of Natural Resources to come up with a baseline set of modeling assumptions to model potential pipeline proposals at that time based entirely on confidential information. So what we didn't want to do is draw back into the confidential— or excuse me, based on non-confidential information. We didn't want to draw back into the confidential details that we had from working on the producer-led pipeline project.

And so a lot of these assumptions, including importantly The production profiles for both oil— for both gas as well as oil losses, as well as associated lease expenditures that we estimated to be associated with upstream development. A lot of those assumptions were developed in that 2018-2019 timeframe with Department of Natural Resources. We have collaborated with AGDC, and they have agreed on the reasonableness of all of those assumptions. And we have generally a lot of those have been carried forward to the present based on inflation assumptions. And so we have— there has been a lot of information that has come out over the last several months of continuous legislative sessions, and it has become apparent that some of these assumptions are outdated if and when we have the opportunity to to step back and do a detailed revision, we look forward to revising our assumptions to incorporate the latest new information.

We haven't done that at this point in time due to time and resource constraints. We do provide various scenario analysis and sensitivity analysis. Another benefit of not making a change to all of our assumptions kind of mid-course is it does allow for an apples-to-apples comparison with all the iterations of the analysis that we have done throughout the various committee processes.

Mr. Stickle, how time-intensive or resource-demanding is it to update this model? I mean, I appreciate the apples-to-apples comparison in terms of being able to tell whether or not changes being considered, just being able to see over time how they may apply, but it doesn't really give us an accurate picture of what we know today and the information that we have today. What would be involved in updating that? Chair Straub, so there's a couple pieces of that. One is, you know, the act of just putting new assumptions into the model, that's fairly straightforward.

We've run numerous scenarios for the committees. The act of agreeing on a new set of baseline assumptions, ideally that would be a months-long process where we would collaborate, we would review all of the latest information in detail, spend some time with it. We would collaborate with stakeholders, partners and agencies, developer, AGDC, industry, and kind of synthesize all of that information. And come up with a new set of baseline assumptions. When you get into the production and lease expenditure information for the upstream in particular, that becomes extremely, extremely complex.

And someone like the Department of Natural Resources could shed some light on what the— or AOGCC potentially could shed some light on what the complexity of doing a a reservoir simulation to properly and completely model out what the oil impacts of gas production would be. So what we've presented on the Senate side in both the Resources and the Finance Committee is we've presented some scenarios around different prices and production scenarios. I think that's for the next week, that's probably a good way to approach this. Thank you. Representative Ruffridge.

Thank you, Chair Schroepke. Similar question to what, Mr. Chair, I think you were just asking. If there was— I really would like to know how much the construction cost, because it seems to me to be a large assumption, weighs into what we're going to see here later, particularly on breakeven prices and other areas of, I think, importance to us as we're making decisions. If the construction cost is higher than what this model has assumed, what main areas does that affect in these following slides?

Sure. Representative Ruffridge, through the Chair, so construction cost is a— it's a major assumption. We did have some information that was provided by the developer a couple weeks ago where they provided a range of kind of their view of what the range of potential capital costs could be. So we built our modeling based on a $46.2 billion real construction cost. The high end of their range would be about a 20% higher cost.

And then there's been some discussion in the finance— Senate Finance Committee of looking at potential for cost overrun. And if you assumed a cost overrun, that could get you to potentially a 40% cost increase. So when we were looking at kind of assumptions and uncertainties, we identified that construction cost as well as the gas purchase price as two of the key assumptions.. And so we've put together these so-called heat maps that are basically a matrix that looks at a range of upstream gas purchase prices and then a range of capital costs. And so I think just looking at that construction cost sensitivity in particular, looking at our baseline assumption and then that 20 to 40% range would be a kind of a good a good range of if we were to update our assumptions, we'd probably fall somewhere in that range.

Understood. Thank you. Uh-oh, Senator Steadman's got his book. Senator Steadman. So I think this is one of the challenging things.

If I could, when you integrate the upstream, the fields, the analysis gets very complex and bogs down considerably 'cause of the complexity. But we're looking at a gas line here in two different phases. I like to look at it a little simpler. What is Phase 1 gonna cost? And if we're giving up a concession, what are we getting for it?

And then Phase 2. And the range that they gave us, they gave us a low and a high. And on Phase 1, the mid-range of the low and the high went from $13 to almost $17 billion, is $15 billion. Then you could add the 15% contingency, that puts you at $17 billion. So you can use $17 or a common number is 20%, that'd be $18 billion.

So both $18— $17 and $18 pass the red face test for the gas line. $12 Billion doesn't. And when you're looking at 80% debt, it's a significant impact, or 70% debt. The entire project, if you took the mid-range and you added the 20% contingency, you're right at $60 billion. So you can use a little less than $60 billion or a little more, but that number does not take into account cost overruns.

Cost overruns start after the 15% contingency, or 20, whatever you want to pick.

So we have not been looking at the impact of the project if there's cost overruns. And there's probably likely going to be. And that would strain the economics even more. So I— I agree that when you have a base cost here of $46 billion and you change that number, it leads to confusion, especially when you have two bodies having dialogue at the same time. But when you move that $46 to $60 at 70% leverage, you're talking billions and billions of added debt service and interest costs.

So it moves the numbers, I think, significantly. Significantly, because the price that they can sell the gas for doesn't change.

So anyway, if that kind of clarifies a little bit. But we have yet, and hopefully tomorrow, we'll get a response to the operating cost of the gas line and the rates of return for whatever we're giving up in concession or we're moving the rate of return more positive, but how much positive? In the positive direction.

I think that will be some of the conversations.

It's too easy to get down into the weeds of the project.

Thank you, Senator Steadman. Speaker Edmond. Yes, following up on Senator Steadman's Senator Steadman's comments, it's really interesting, the intersection between slide 21 and slide 26 in terms of incremental revenue versus cost. Assumptions and thinking back to the information we had at hand in 2014 when we were discussing Senate Bill 138 and the majors were developing the, proposing to develop the project, certainly followed by TransCanada. And then where we are back here on Slide 26 in the information we have but also don't have at hand in terms of the current developer.

And it's really interesting for me to try to wrap my brain around any of these estimates without having sort of a more detailed picture.

And I suspect, Mr. Chairman, we will have Mr. Stickel before us again at another time, but I have a range of other questions that probably are too detailed for the moment.

Thank you, Speaker Edgeman. Yes, we will have Mr. Stickel before us again, and I expect a deeper dive into these issues tomorrow. Thank you for that. Additional comments or questions, uh, on this slide? All right, Mr. Stickel, please continue.

All right, and just to, um, just to reiterate on On slide 26. So we talked about the construction costs. So each of these assumptions are key to the analysis, and each of these assumptions are material to the developer as well as to the state economics. And each of these assumptions have a range of uncertainty around them. And if we had the time to take a step back and do a detailed update of these assumptions These would all change probably materially.

So we are assuming a 10% pretax rate of return for the developer, that that's what's being targeted. I underline pretax there because when we add the pass-through entity tax on top of it, that changes the dynamics for the developer.

We are assuming that $46.2 billion construction cost and the $1.50 per thousand cubic feet unprocessed gas price. We've heard— there's been some suggestion that for a Phase 2 operation, there could potentially be a higher price subject to negotiations. Those negotiations are underway. We are assuming that Prudhoe Bay and Point Thompson would anchor the gas project. The oil impact analysis is a significant assumption, so we are assuming no oil production impacts at Prudhoe Bay in our baseline assumptions.

We have heard information from AOGCC as well as producers that potentially oil losses would be likely at Prudhoe Bay. And then for Point Thompson, we're including 270 million barrels of additional production over life of project, and we've heard information from AO GCC that, that may be— based on the latest information, that that is likely an optimistic assumption. And so if we were to go and do a detailed reservoir our analysis, there would be less of a benefit of incremental oil and that would materially impact the economic analysis that we're showing for the project.

Senator Steadman. Dealing with a couple comments on the 10% pretax, we use, as I recall, dealing with the oil tax structure, 10% after tax.

In a lot of the analysis. I see the 10% pre-tax and they— but when you look at the, at least from what I can gather on the economics of the gas line, with their interest cost and their depreciation, there's gonna be no net income, taxable net income for 2 decades. Literally, 2 decades. So I don't know how that, I guess, will wind up into a tax conversation later on the next couple of days, but you don't pay taxes unless you have a net income. And the depreciation, my understanding is, could be 7 years on the gas infrastructure, but you can make it 20-year straight line and it doesn't make a difference.

'Cause they can't use it.

So we can have those conversations with them.

And I don't know if Mr. Stickel has encountered that, if they've isolated just the gas line and what depreciation schedule you're using in your models, or maybe you can just touch on that just for information. Mr. Stickel, would you like to comment on that? Sure, Senator Steadman, through the chair. So I believe we're using a 7-year depreciation schedule.

So you're correct that the depreciation offsets— when we're doing an analysis of potential midstream corporate income tax, the depreciation offsets a lot of that income for the first several years, which is why I think 2036 was the first year that we would project a positive corporate income tax from the developer under the project. They also earn— to the extent that they have losses during construction, they could earn a net operating loss that could be carried forward. That net operating loss can offset up to 80% of a tax liability. And so once we get to the 2036 timeframe, we assume that the developer would still have those net operating losses until sometime in the 2040s.

Additional discussion from committee members? Are we transitioning, Mr. Chairman, into the next phase of the report? I believe that's correct. Speaker Edmond? Yeah, could I squeeze in a quick question?

Please do. Speaker Edmond. And I don't have my thoughts fully collected here, but first impression, this is convenient. An incredible amount of work for your department, right, once this pipeline gets developed and full operation and so forth, which we all hope happens soon. But this is— your department is very large to begin with, but the additional workload this is going to impose on your agency is going to be quite significant, isn't it?

Mr. Stickel. Speaker, Adjutant Minister, the Chair, yes. And so in our fiscal note, we've requested, I think, 4 new positions before the accounting for the pass-through entity tax. So I think 5 positions total, as well as a capital appropriation. There's going to be a significant regulatory process that we'll need to do to implement the bill., as well as will be supporting equity investment decisions.

And Commissioner has the determination of whether and how to implement the alternative volumetric tax. So yes, significant workload for, for the department that will— as soon as this bill passes, we will jump right into that next phase of work. Then Mr. Speaker, Chairman, just looking down the road a ways, if the state were to become an equity investor, your department would be playing a lead role as well too, right? Mr. Stickle. Speaker Edmonds, through the Chair, probably.

So I know under the bill we are specifically required to do equity investment analysis and advise the legislature on whether to make that. That investment, and so we actually were requesting positions to support that. So I think we're envisioning a fairly robust role of kind of building up a position or two of specialized expertise, as well as bringing in an outside consultant to kind of build up that expertise, which would build on our existing expertise that we have within our commercial team in the Tax Division as well as our Treasury team within the Treasury Division. So we would kind of leverage those existing resources and then add some specialized expertise. Thank you.

Okay, very good. I think at this point I'd like to take a 5-minute at ease for general relief for committee members and just to check in related to the rest of today's schedule. So at this moment we're going to take an at ease. It's 4:05 PM.

4:15, Back on the record. We are wrapping up slide 26, about to jump into a meaty section. I prefer that we not go past 5:00 PM out of respect for our senators here. Mr. Stickle, you can take us away and we will see how far we can get. Maybe two of them.

Please continue, Mr. Stickle. Thank you. Again, for the record, I am Dan Stickle, Chief Economist with the Department of Revenue. I think we just Finish talking a little bit about the kind of the key assumptions, what we built into our baseline modeling, some of the uncertainties around those that have kind of come to light as we have gone through this process.

But that said, these are the assumptions that underlie the analysis that we are about to walk through. We do have some sensitivity analysis built into the presentation, and we are happy to run additional scenarios for the committee as we have for multiple committees going throughout this process. So slide 27, so for this slide— for this presentation we were asked to focus specifically on the Senate versions of the bill, specifically version S which came out of the Senate Finance Committee and then version S as amended which came off of the the floor. The material impact between S and S as amended from a modeling standpoint is the inclusion of the pass-through entity tax. In each of these scenarios, we show the impact if the full AKLNG project proceeds under each scenario.

Obviously, that is an uncertainty, more so under the current loss scenario in particular.

Okay. So slide 28 is a chart that we've been showing for all of these analysis. We show on the top a cash flow summary over 10, 20, and 30 years of full export operations. In nominal terms, what is the net cash flow to the various stakeholders? Important to note that for upstream and midstream Midstream, these are not profits, these are revenues, total cash flows.

Debt service gets paid out of these numbers for Midstream in particular. And then on the bottom, we show cost of supply and a breakout of the components of those. And what we're showing here is for the developer to earn the assumed 10% pretax rate of return under all of our baseline assumptions, what would they have to be able to sell the gas for into both the in-state and the global LNG market to, to break even on that investment? And so really kind of focus on that bottom right number, which is the LNG break-even price in 2033 under our current law tax analysis if the full project went forward with our baseline assumptions, that breakeven price under the global market would be just over $9 per, per 1,000 cubic feet. For comparison purposes, current futures market prices around that time frame are around $8 per 1,000 cubic feet.

And so just kind of demonstrates, even given all of our assumptions around capital costs and our other assumptions that the project is still quite marginal.

Slide 29 shows the similar analysis under Version S, which came out of the Senate Finance Committee.

The— with the alternative volumetric tax that reduces that breakeven price into the global market down to— from $9.05 down to $8.62 per 1,000 cubic feet. And then slide 30 is a similar chart. The breakeven prices between slide 29 and slide 30 are the same. The difference between slide 29 and slide 30— so slide 30 is the version as amended on the floor, including the past through entity tax. And so since we model the return to the developer on a pre-tax IRR basis, that didn't impact our break-even price analysis.

In actuality, they probably would require a little bit higher price to account for that tax burden. What we see between slides 29 and 30 is a shifting of cash across the table and that cash flow where we were shifting revenue away from the upstream and midstream and federal government and towards the state. And so the upstream and midstream would pay additional corporate income tax with the pass-through entity analysis. A portion of that would be an offset on federal tax because state taxes become a deduction against the federal tax. And then that would shift over life of project a little over— around $6 billion of cumulative revenue would shift from the companies and federal government to the state government.

Please continue.

Slide 31 is a chart of the annual revenues by major component. This is if the full project proceeds under current law with our baseline assumptions. And once the full project is in operation in 2033, we're looking at around $1 billion per year of total state revenue under current law between property tax, corporate tax royalties, and production tax. There's been a lot of focus on those first 3 years of revenue, so we are showing 2 years of negative or net reductions in revenue to the state in 2029 and 2030. What that represents is we've built into our, our modeling assumptions significant capital expenditures that would be associated with upstream developments at Point Thompson in particular to help bring on new gas production as well as additional oil production.

And those, those assumptions, as I mentioned earlier, those were developed in the late 2010s in collaboration with Department of Natural Resources. If we were to revisit the modeling, that is one assumption that we might revisit is the timing of those assumptions. Understand that potentially some of those development costs might happen a little later in the project than 2029 where we're showing them in our modeling.

Senator Steadman. A couple of our colleagues had some concerns over 2038. Could you please just touch on that a little more detail? Mr. Stickel. Sure.

Senator Steadman, through the chair, so 2038 again has to do with our assumption around upstream lease expenditures. So when we built out our modeling assumptions for Point Thompson in particular, we assumed two major increments of additional development expenditures, one that would happen in 2029 through 2031, and then a second one that would happen in 2038. So essentially that there would be, you know, they're drilling their first new well in in I think a decade this year up at Point Thompson, which is going to be a significant new well. We've— our modeling assumptions is that to bring on the amount of gas that we're expecting from Point Thompson, that they would have to go back and drill some additional wells in the near future, and then that there would also be another round of additional drilling that would happen in 2038. And those are just, again, just modeling assumptions that we built into the modeling that were developed before the current operator took over Point Thompson.

Representative Ruffridge. Thank you, Chair Schraggi. So it's interesting, we have these assumptions here and then we have ideas about what state revenue would be and municipal revenue under a proposed pipeline. But in having this discussion, it feels like we're also missing potentially— if we don't have natural gas coming from somewhere, we will have to import it. And I'm wondering if you have an idea of what state revenue or municipal revenue would be if we if we imported natural gas?

Mr. Spenny.

Representative Ruffridge, to the chair, so we have not looked at specific revenue analysis of gas imports. Certainly there wouldn't be revenue associated with the production of that gas if we were to import it the way that there is if we were to bring it down from the North Slope or to source it from within Cook Inlet.

Follow-up. Just a brief follow-up, Mr. Chair. Thank you. So it would be safe to say that the only real option for natural gas for a state revenue option is to produce it ourselves?

Representative Ruffridge, through the chair, Chair, in terms of getting the, the upstream revenue, yes, to produce it either, either on the North Slope or in Cook Inlet. Understood. Thank you. Okay, please proceed, Mr. Stickel.

All right, and so the, the real value in kind of this set of charts is a comparison, less so the absolute numbers presented and more so a comparison between the different versions of the bill to understand how they would impact state revenues. Slide 31 was the current law provisions. Slide 32 looks at the version, the version S that came out of the Senate. And we show here what state revenue would be. Important to note this is just the state revenue component, not the municipal revenue component.

But with the AVT tax reduction, that would reduce those revenues once the full operations begin from around that— from around $1 billion per year down to around $800 million per year. And then you see at the end of the line here in 2060, under the version that came out of the Senate, is where we had that second doubling of the AVT rate, with that second doubling going entirely to the state. And actually you end up with a situation where once we get to 2060, the state revenues are actually higher under— under the bill before the committee than under current law.

And then slide 33 is the version that came off of the Senate floor, which is the same— for modeling purposes, it's the same as the Senate Finance version, except that it adds that pass-through entity tax, and so that's where you see that orange orange bar, which is the corporate income tax, which was a fairly modest contribution on slide 32, becomes very significant on slide 33 as we expand that corporate income tax to apply to pass-through entities.

Not seeing any questions, please continue. Slide 34 and 35 are so-called heat maps. What these show is the breakeven— we have two axes here. So on the horizontal axis, we have a range of upstream gas purchase prices. Again, our baseline assumption is $1.50 per thousand cubic feet would be the price for the— in in real terms would be the price of gas produced— purchased from the producers into the project.

And we varied that on a range from $1 up to $5 per thousand cubic feet. And then on the vertical axis, we have our baseline capital expenditures, which again was the $46.2 billion. And we do a range of scenarios there, looking at higher capital expenditures with up to 100% higher capital expenditure.. And so as I, as I mentioned earlier, if you look at the information that was presented by Glenfarn and the high end of their range, that gets you to something closer to the plus 20% scenario on the slide here. And then if you look at the potential for a contingency allowance, when we were in the Senate Finance Committee, we were— there was some discussion of a 20% contingency, so that would get you to the plus 40%.

So I think this range of kind of base up to 40% is a good range for the capital expenditures. And then obviously those gas purchase prices are still under negotiation. So what slide 34 looks at is what the in-state price to utilities would be if the full project went to went forward. So utilities would benefit from the economies of scale of selling gas into the global market and would pay some relatively low gas prices under most of these scenarios. I'd like to focus on slide 35, which as far as the overall project economics is probably the more significant slide.

So this is the same set of heat map charts looking at that LNG breakeven price into the global market. And so you can see under current law with our baseline assumptions, we were forecasting or estimating $9.05 per thousand cubic feet as a breakeven price to achieve that 10% pre-tax rate of return. And then that that decreased to $8.62 per thousand cubic feet under the bill that came out of the Senate. And again, since we were modeling pretax rate of return and not post-tax rate of return, the two Senate versions of this— of the table are the same for this presentation.

And again, for reference, current futures market prices are around $8 per $8 per 1,000 cubic feet, maybe a little bit less than that once we get into the early 2030s timeframe. So even with the tax relief, still a marginal project.

Representative Ruffridge. Thank you, Chair Strzongi. I think, Mr. Stickel, you're being generous when you say marginal. If the futures market is $8— and we're assuming a $1.50 upstream gas price and we're probably looking at the plus 20% line or the plus 40% line at— in real terms, none of the items I'm looking at on that screen seem to be even in the definition of marginal. It seems like they don't work.

Am I wrong on that? Mr. Stickle. Representative Ruffridge, through the chair, so that would be a great question to ask the developer, but based on the baseline assumptions that we have and the— what is in the futures market, it does look like a challenging project even with the tax relief. Obviously, there are other benefits that Alaska gas brings. You know, one could be futures markets aren't always correct and buyers may be willing to pay a higher price than what's being indicated in the global market.

Another being some of the geopolitical concerns that we've seen with the recent conflict in the Middle East where there was a premium placed on availability of supply as opposed to strictly the price of supply. And Alaska has a benefit of having a direct route from Alaska to Asian markets that doesn't go through many of the choke points that other gas supply sources would. Just a follow-up, Mr. Chair. Yes, follow-up.

Thank you. It would be interesting to note, because I know there— was a heat map like this for the original House bill, what the number was at $1.50 at plus 40% of the original House Bill 381 as it left the House. Do you remember what that number was? Representative Ruffridge, through the Chair, I'm not sure if I have that.

We can provide that. I know I— I'm sure I have it somewhere in this stack of papers. Thank you. But broadly speaking, the various, you know, the various versions of the bill have kind of targeted that 50 cents or so reduction to that break-even cost of supply plus or minus 5 or 10 cents. Thank you.

Okay, please continue, Mr. Stickle.

Slide 36. So now we move on to some Phase 1 only analysis, and this was one of the pieces that Senate Finance in particular asked us to, to focus on in the analysis. So we start with a a similar set of baseline assumptions, assuming that the Phase 1 receives the FID and the Phase 2 does not happen.

For our Phase 1 modeling, we assumed a construction cost in real terms of $11.6 billion. It has been noted that the information around the Phase 1 cost that that was provided by the developer was quite a bit higher than that, actually, but the $11.6 million is what's based into our analysis. And again, provide the sensitivity analysis to look at potential for higher construction costs there. We assumed that a similar cost of gas treatment for Phase 1 as with the full project, and we developed a demand profile for Phase 1. We started— so we're assuming a 65 billion cubic feet per year initial demand, and what that represented is 15 billion cubic feet per year coming from in-state.

So we assumed in our Phase 1 modeling that the AKLNG The energy project would basically fill in the gap in demand that is not served by existing Cook Inlet production. Um, as Cook Inlet production declines, and so that starts out at about 15 billion cubic feet per year, and we have that increasing over time. Um, in discussion with AGDC, we've included an anchor customer with 50 billion cubic feet per year of demand.

Agrion Fertilizer Plant could be another anchor customer. We assume that the anchor customer will pay $6 per 1,000 cubic feet for gas and that the, that the in-state utilities will pay a higher price for the gas. So that gets you to the 65 billion cubic feet per year increasing over time. That's around 180 million million cubic feet per day. We have heard testimony from AGDC and the developer that they are looking at some other potential cases with a high side risk case that ponders the possibility of 500 million cubic feet per day for Phase 1.

But just to outline, that is not the case that we are modeling here. Starting with the 65 billion cubic feet, which is more like 180 million cubic feet per day.

Okay, Senator Steadman. Well, I think we take the $11 billion to $17 or $18 billion. And then the phase-in, could you talk a little bit about the phase-in, how many years you're looking at? And then the Donnellan Creek mine is looking at $230 BCF a year. I think we use about $200 now, a little less than $200.

So that gets you to $230. If you get Agrium, you're at $280.

I have trouble with the math to get to $500. Sure. Senator Sedman to the chair. So that's a great— that's a good question to pose to AGDC. Agency.

I know they've— they shared some information with us of how they get to the 500, which basically takes a component of in-state demand, layers on some additional South Central demand above and beyond what we're putting into our modeling, layers in some additional interior demand, as well as several potential industrial customers. Follow-up, Mr. Senator Steadman. One of the challenges too, I don't think the debt level is going to be phased in other than through construction. So those bills come immediately.

So I just, we're waiting, we're going to have, I think, some of this modeled hopefully to look at so we can gauge what we're dealing with, but I don't think the debt payments are going to come every 6 months if they need them or not.

Any comment, Mr. Stickell? Senator Sedman, through the Chair, that's correct. Debt will be due. We built that into our modeling that we are going to present in the coming slides.

I did want to make one note, that bottom bullet point there. So we assume that the tax relief continues through 2060 under the bill. There was some technical uncertainty around exactly how that provision would work, and I think happy to share that with the committee, but that is the is the assumption there.

Okay, thank you for noting that. Not seeing additional questions at this time, please continue. All right, so slide 7 is our, um, similar cash flow and cost of supply summary in our Phase 1 only analysis. So looking at a breakeven cost of supply under all of the assumptions that I just laid out including that, um, that lower $11.6 billion construction cost, um, breakeven 2033 cost of supply of $13.36, um, into the in-state market. That represents a weighted average breakeven price with some of the gas being sold at the $6 price to the industrial consumer and then some of the gas being sold at higher price to the in-state utilities.

All right, Senator Steppen. And the higher price you're using for in-state utilities, I know we have a cap of 16 cents, but what are you looking at? What's that? $16. Yeah, I keep thinking of hydro and pennies, but sorry for that.

$16. So can you help me with what you're using for the utility Please. Sure. Senator Steadman, through the Chair, so for this first slide, this is current law without the $16 cap. For the next 2 slides, we showed— it's really just for— it's almost really just for illustration purposes because, as you mentioned, the $16 cap cap would restrain the ability of the project to charge anything higher than $16.

So once we get into the next slides, we are basically looking at what is that in-state break-even price. Presumably, the project would have to— if our demand Demand— if our throughput assumptions were correct, they would have to get some higher, potentially higher than $6 price from the anchor customer to make the $16 cap work. And I think testimony that— the testimony that we had provided in some of the previous committees was with the $16 cap and the throughput assumptions that we've built into our modeling the phase and the potential for a higher capital cost, the Phase 1 only, that Phase 1 only scenario doesn't really work. So something in there has got to give, whether it's the lower capital cost or a higher price or as we have heard from AGDC and the developer that they are targeting a higher throughput assumption than what we are modeling.

Very good. Please continue, Mr. Stickle. All right. So slide 38 is the— that same break-even analysis and cash flow summary under the version of the bill that came out of the Finance Committee, again, under our baseline assumptions. And then slide 39 is with the pass-through entity tax.

Added, and again, we show no change in the break-even price between the two Senate versions because we are modeling on a pretax rate of return. But then in the cash flow summaries, there is a shift of revenue from the federal government and the upstream and midstream into the state government component of about $2.2 billion over life of project.

Slide 40 is the revenue by year chart under the Phase 1 scenario under current law, significant revenues from property tax of about $150 million per year, and then some smaller revenues from royalty and production tax if the project were to go forward. And that— burden of about $150 million per year on the Phase 1 only analysis would be a material burden on the project.

Senator Steadman. What are you— what's your assumption that you're using for operating cost dollars for Phase 1 to run the pipe? We got a— showing here $160 million coming in or impact for property tax. What's the of operating costs? Senator Sedman, through the Chair, I don't have that number in front of me.

We would be happy to provide it to the committee. I believe it is in a response to the Senate Finance Committee that we have working its way through the pipeline. We will provide that information. Great. We will look for that information.

Please continue, Mr. Stickell.

Slide 41 is the annual revenue chart with the version of the bill that came out of the Senate Finance Committee. In terms of state revenues, significantly less by removing that property tax, which was the main state revenue source, but there would still be some royalty and production tax revenue. So from a state revenue standpoint, the phase 1 only would be a positive to state revenues.

Not looking at a large amount of upstream lease expenditures associated with Phase 1, basically given the current amount of gas cycling and production that's already taking place on the slope, that that level of gas for the Phase 1 deliverable could be provided without significant significant additional lease expenditures that would impact production taxes is our assumption.

And then slide 42 is again the same chart with the version that passed out of the Senate floor that adds that pass-through entity tax, and that would be a significant increment and actually would be the— largest source of revenue from this bill in the Phase 2 scenario once we get out into the 2040s. Thank you, Mr. Stickle, please continue. Slide 43 and 44 are two heat maps. So we show this two ways. First, on slide 43, we are looking at the weighted average break-even price.

So this is looking at that break-even price from the developer's point of view of overall how much— what price would they have to sell the gas for to achieve that 10% pretax rate of return under all of our assumptions. Again, as has been mentioned, the capital costs for Phase 1 indicated by the developer are quite a bit higher than what we've modeled out. So if you went down into something more of a, you know, 60% or more scenario here, you would end up with a higher weighted average gas price that would be required for a break-even under Phase 1. Again, under our throughput assumptions. And what we look at And so under the baseline assumptions, the bill would reduce from $14.50 down to $12.68 per 1,000 cubic feet.

If you look at something like the 60% capital cost, it would reduce from $21.16 down to $18.19 per 1,000 cubic feet. And we also provide this looking another way on slide 44. Anchor. And what this looks like— looks at is what would that break-even price to the utilities have to be to achieve that weighted average— to achieve that 10% pretax rate of return if you assume the anchor customer is paying that $6 per 1,000 cubic feet. And what you see here is that even under our baseline assumptions that weighted average price of utilities would have to drop from $22.60 under current law down to $19.04 under the bill before committee.

Now, that price might work with the $16 cap because the $16 cap is in dollars per million BTU, which works out to a little bit more than $16 on a per MCF basis in 2026. Once we inflate that out to 2033, um, under our baseline capital cost assumptions, that probably fits under that $16 cap. If you were looking at, um, a significantly higher capital cost in that 40 to 60% range, um, that's where you get into a situation where, um, that price cap would be very challenging for the Phase 1 only analysis under the set of throughput assumptions that we have modeled here. And so you would need a higher— some higher level of throughput to make that work from an economic standpoint.

Okay, take us to the conclusions. Conclusion slide. So slide 45, Alaska LNG Project has the potential to provide significant amounts of revenue to the state, federal government, local governments, as well as enhancing energy security and creating jobs and economic development. So the version of the bill before the committee would materially decrease the cost of gas for Alaskans. It would materially improve the value of the project for the developer.

It would be a large tax decrease overall. We note the significant policy difference between the two versions of the bill is that pass-through entity tax that is in the version that came out of the Senate floor. That does create— that does add a level of uncertainty uncertainty and is a significant policy decision for the committee to consider.

And so that concludes the main part of the presentation. I do have a short appendix that walks through alternative volumetric tax calculation and allocations that was requested. I am happy to walk through that or leave it with the committee as a resource. Mr. Stickle, I know that there's some interest in asking questions around the appendix, and we are coming up on our 5:00 PM stop time.

I think my preference would be to push that to tomorrow. Are you available to add the appendix to the agenda tomorrow? Sounds excellent. And I'm going to look to the committee members that that works for them. All right, very good.

So I think we're going to have a clean stopping point there. I want to thank you, Mr. Stickell, for your presentation today and sticking with us here.

Our next meeting of the HB 381 Conference Committee will take place tomorrow, Saturday, June 27th, at 10:00 a.m. During that meeting, we will conclude this presentation as well as go over the amendments passed on the Senate floor to HB 381. Is there any other business or questions, comments from committee members today? Not seeing any, Senator Hoffman, do we have a motion? Mr. Chairman, I move the conference committee be adjourned. We are adjourned at 4:51 PM.

We're adjourned. Object, object.