SFIN-260529-0900

Call Senate Finance Committee to order. Today is May 29th. We're in Juneau, Alaska, State Capitol Senate Finance Room. It is 2 minutes after 9:00 a.m. Present today, Chairman Olson, Chairman Steadman, Senator Kiehl, Senator Merrick, Senator Cronk and Kaufman, myself, Senator Hoffman.

We have only one item on today's agenda, that is SB 201, Gas Line Volumetrics Tax, AGDC RCA. We have a presenter on this topic, Mr. Dan Stickel, the Chief Economist for the Division Department of Revenue. Good morning, Mr. Stickel. Please come forward to the finance table and introduce yourself and enlighten the committee.

Hi. For the record, Dan Stickel, Chief Economist with Department of Revenue. And today I am here to deliver a apparently fat presentation on Senate Bill 2001. So we've actually taken— we have— it's kind of the standard presentation that we've been delivering in the various committees for the various versions of the gas line bills. We've maintained that structure of the presentation.

We've added a couple of greatest hits content slides at the end, and then we've added some additional background at the beginning. Of the presentation to provide a little bit more of a 101 on some of the topics that we're talking about.

So—. Before we get started, I'd like to acknowledge we have 3 senators with us today. We have the Senate President Gary Stevens, Myers, and Jesse Bjorgman, Senator Bjorgman from the Peninsula. They've been with us the last— all week. So just to acknowledge that they've been present.

Please continue, Mr. Stickle. All right. Slide 2 is a list of acronyms and definitions. We include this at the beginning of the presentation as a reference to go back to, as there are many acronyms throughout the presentation.

So overview on slide 3. So we'll start with some background information. So I have some discussion of upstream and midstream, what those terms mean and what the fiscal system looks like in terms of state, local, and federal taxation for both of those. Some background information around the state and municipal property tax, which is the tax that's being addressed through the legislation. And some background information around a 2014 piece of legislation known as Senate Bill 138.

That was a piece of gas-related legislation for a prior iteration of the gas pipeline, and some of those provisions remain on the books today. Once I finish with the background, I'll walk through the proposed Senate Bill 2001 legislation and our revenue impacts per the fiscal note. I'll walk through our implementation costs per our fiscal note and then finally conclude with detailed project modeling and some of the assumptions and analysis that we've done around the project in particular.

So starting with some background, starting on slide 5. So oil and gas industry, we hear these terms upstream, midstream, downstream. What do those terms mean? So the oil and gas industry is basically broken up into 3 sectors. The upstream represents your exploration, your drilling, your production.

That's where the companies are actually going out and finding and developing and taking the oil and gas out of the ground. So some examples of upstream activity, these would be the producers on the slope, the companies like ConocoPhillips, Hillcorp, ExxonMobil, Santos, and some smaller producers. When we're talking about midstream, that's your transportation, storage, and processing infrastructure. So these— this is the the part of the industry that takes the oil from the field where it's produced and then brings it to market. So this is going to be your gas treatment, your pipelines, your LNG export facilities, your LNG ships to take the— to take— and pipe— other waterborne transportation.

So in terms of midstream in Alaska, what that means is primarily Alyeska and the Trans-Alaska Pipeline and feeder pipelines for oil. And then for gas, we're talking about the Glenfarm-developed project, including the gas treatment facility, the pipeline, and the LNG export facilities. And then finally, not going to talk too much about this in this presentation, but downstream is the third element of the, of the oil and gas industry, and this would be your local For gas, it would be your local gas utility that delivers into the residential network. For oil, it would be your refineries and then your final distribution out to the gas pump. So this would be your companies like Marathon, for instance, operates a refinery here, Instar, and other gas distribution companies.

Slide 6 lays out our fiscal system for the upstream. These are for the oil and gas production, and this was detailed, provided in detail in February 2026 to this committee when I provided a detailed production tax order of operations. But, but to recap, for the upstream, there are royalties, which represent an ownership interest in the oil or gas. These royalties can be state, federal, or privately owned. There is a property tax levied on upstream.

That's a 20 mills tax split between state and municipal. The state does levy a production tax, which is our severance tax on oil and gas. And then there's corporate income taxes at both the state and federal level. To note, our state corporate income tax only applies to C corporations, and that represents some but not all of the upstream companies working in Alaska.

Slide 7 shows a similar fiscal system for the midstream. That looks a little simpler when we lay it out on the slide here. So on the midstream, we have property taxes, both state and municipal, and then corporate income tax and federal— at both the state and federal level would apply as well.

Moving on to slide 8, this has a little bit of background on our existing property tax. So the current state property tax, which is 20, 20 mills or 2% of value, that was enacted back in 1973. It was actually enacted during a special session of the 8th legislature. And at the time in 1973, we were working through the oil boom from the development of Prudhoe Bay. And we wanted to generate revenue from the oil production.

We wanted to provide some benefits to the local communities that were— so that they shared in some of the benefits of oil production. And we also wanted to provide a funding source for those local communities to help support public services and development that was needed to support the rapidly expanding oil production and oil infrastructure in the state. In particular, communities along the Trans-Alaska Pipeline corridor that were experiencing impacts and increased costs associated with the oil development. And when that property tax was implemented, we implemented it that the state would manage the property tax in terms of doing the assessments and the evaluations. That was in one sense, it was to help the local government so that they didn't have to go out there and have all the local governments doing their own assessment and appraisal processes.

And also having the state manage the property tax for oil and gas ensured consistency and uniform treatment of all tax property. So you don't have different methodologies for different municipalities, we have one centralized methodology that the state administers. And so it's the 2— the 20 mils or 2% tax. Any local taxes are allowed as a credit against that tax. And so the 2% is what's paid by— 2% of assessed value is what's paid by the taxpayer regardless of which municipality or if the property is in a municipality.

And that basic structure of our property tax has not changed since 1973.

So slide 9 outlines that current law property tax. So again, we levy that property tax on the taxable value of exploration, production, and pipeline transportation property in the state. So that's what's subject to the oil and gas property tax that's managed by the state. Anything that falls outside of that definition of oil and gas property can be taxed by local governments, but the state doesn't play a role in property tax outside of the oil and gas piece.

Again, it's the 20— the 20 mils or 2% with the municipal taxes as a credit against the state tax. One thing to note is we draw a line in terms of where, where do we cut off the definition of what is taxable oil and gas property. And an LNG export plant is currently not subject to the state oil and gas property tax. And that becomes important as we're working through analysis related to the gas line proposal because the LNG export plant would be a significant portion of that project. And under current law, that would not be taxable by the state.

It would be taxable by the Kenai Peninsula Borough.

Senator Steadman. So just to be clear, the conditioning plant on the North Slope and the pipeline would be taxed? The liquefaction plant on the shore side would not come under the state property tax. I— Co-chair Steadman, that's correct.

Please proceed. So slide 10 is the last piece of background information we were asked to add to this presentation. So this discusses Senate Bill 138, which was enacted by the legislature in 2014, and this was a piece of gas commercialization language that was really targeted at a prior iteration of the gas pipeline project. And so Senate Bill 138 did a few different things. It expanded the AGDC mission to explicitly include and focus on a large diameter pipeline and treatment liquefaction facilities, which is essentially the, the nature of the current project.

Previously, there was some focus on an in-state only line. We authorized that the state could negotiate up to a 25% state equity share in the project, and when we were passing this legislation, it was, it was envisioned that there was a likelihood that the state would actually be a 25% partner in the entire project, potentially owning 25% of the project, and then taking title to the gas and actually going out and marketing 25% of the gas. And so we, in SB 138, we set up a framework to allow that. So there was an option for the state to take both royalty and gas in kind. And the way that would work is Department of Natural Resources would issue a determination that it's in the state's best interest to take to take state royalty in-kind.

That royalty would be in the 12 to 12.5% range. And then if that royalty election was chosen by Department of Natural Resources, the producer then has an election to also pay their tax in-kind. And with Senate Bill 138, we set a tax— a new tax rate was implemented on gas that would be a 13% gross tax. That had a 2022 effective date that we switched over to the 13% gross tax, with the idea being that that gross tax rate takes effect when LNG exports were expected to take effect under this. At the time in 2014, we were thinking gas would be exported in 2022.

But adding those two together, the 12% and the 13%, you get to about 25% of the gas that could potentially be taken in kind by the state. So instead of giving us cash into the state treasury, the producers would just hand over 25% of the gas at the wellhead and we would take it from there. That would allow the state— that would de— provide somewhat of a de-risking for the producers that instead of coming up with cash and doing a detailed or potentially complicated netback calculation to the wellhead of the value of that gas, they just hand Hand over 25% of the gas and we take it from there. And then from the state standpoint, we could potentially market that gas for increased value to the state. It would also give us the flexibility to use that gas to support in-state needs.

At the time when we were debating this legislation, we had just gone through a period of very high oil prices, over $100 per barrel. We had state surpluses, we had ample state savings, and so the state was in a much different overall financial picture where we did— we could afford to make these— to take the gas in-kind and make these 25% investments without having the structural budget deficit that we're facing today. The Senate Bill 138 also created the Affordable Energy Fund. So that's a fund whereby 20% of gas royalty revenues after the permanent fund contribution are designated to a specific fund that supports affordable energy in particular in rural Alaska. And then there was some additional regulatory and streamlining reforms through Department of Natural Resources and Department of Law that were really aimed at streamlining the process of approvals to get this project off the ground.

Such a wonderful idea.

Energy fund.

Questions on this page?

Please proceed. All right, so that concludes kind of the background slides that I had. The next section of the presentation walks through the, the proposed legislation and our revenue impact analysis per our fiscal note. And this is, as I mentioned earlier, it's— for folks that have seen my presentations previously, this is a very familiar format that we're walking through in terms of the content here.

So slide 12 is a disclaimer. So Analysis is based on preliminary interpretations of the bill. There are detailed modeling assumptions that underline the numbers that we're, that we're putting out.

We have a baseline spring 2026 revenue forecast that we use for upstream analysis and then a spring 2026 version of the, of the AKLNG model. Later, as we get into the detailed project analysis, I have a couple of slides that walk through some of our AKLNG assumptions in more detail.

And to just state on the record as I go through these, not an official statement on tax interpretation. I'm an economist, not an auditor. There will be a regulatory process to work through the gas bill as we implement it.

So slide 13, what does this bill do? So the core purpose of the legislation is to create a policy framework for replacing certain state and municipal property taxes with an alternative volumetric tax. And there are several DOR-specific impacts that I will walk through each of those in turn. But that is basically, in a nutshell, what the bill does is it provides an exemption from property taxes for portions of the project and replaces it with this AVT.

Slide 14, a note on— Fiscal note impacts. So the fiscal note itself that we provided to the committee is an indeterminate fiscal note. There is not certainty on whether the AKLNG project proceeds with or without tax changes.

And so in the fiscal note, we put indeterminate on the front of the fiscal note and then addressed some of the potential revenues in narrative. And in addition to the direct fiscal impacts, there are indirect impacts on state revenues outside of the, the property tax and the AVT. There's also significant municipal impacts and revenues and economic benefits and impacts for the state and municipalities beyond just revenue. And so when we do a fiscal note, we are focused narrowly on the revenue sources and revenues impacted by the piece of legislation itself. And so that's what we'll be talking about as we go through the fiscal note, and then we get into some of the, the broader impacts later on in the presentation and the detailed project modeling.

So Senate Bill 2001 has a conditional effect, so there's certain conditions that have to be met for this tax benefit to trigger. July 20— July 1st, 2060 is the cutoff for the tax benefits under this bill. And the bill takes effect if the Commissioner of Revenue makes a determination that the primary owner of the property that could be taxable has made various commitments. One of those is a $40 million deposit into a community impact fund that would be managed by Department of Department of Commerce, Community and Economic Development, as a grant program to support municipalities with costs related to pipeline construction. The owner has to commit to negotiate a project labor agreement for the pipeline, and they have to commit to a Fairbanks spur line with several additional details around that Fairbanks Spur Line commitment.

And those details are laid out on slide 16.

I have a question on the previous slide on the $40 million Designated Community Impact Fund. We currently have a program to disseminate community assistance funds. Does this $40 million have any process on how that amount of money would be disseminated? Sure, Co-chair Hoffman. That would be administered by—.

Later on? Is that later on the slide deck? Co-chair Hoffman, no, I don't go into a lot of detail on this. This would be managed by Department of of Commerce, Community and Economic Development. And so they would probably be the agency best apt to speak to the process of grants and dissemination.

And I know they have a fiscal note to go with the bill as well. I believe that this is a major component that affects communities throughout the state of Alaska. And I think it should be clear on how those dollars would be disseminated.

And is this a one-time program or is this an ongoing program? Sure. Co-chair Hoffman, so for the conditional— for the conditional effect of the alternative volumetric tax, this is a one-time payment. Of $40 million upfront prior to pipeline construction or pipeline coming into production that is required to trigger the property tax relief. And that would be a one-time payment, and then the grants would be managed through Department of Commerce, Community and Economic Development.

Separate from this, there is a provision for the legislature. There is an additional new fund that is created with kind of a waterfall of how that money— it is between $0 and $90 million per year that can be appropriated by the legislature. Then there is language around how that would flow out to various impacted communities. That's a— so this $40 million upfront, that's a commitment of a direct payment from the developer to the communities with the state working as an intermediary. The other community fund, which is up to $90 million per year, that's a fund that's created and that would be at the discretion of the legislature to choose whether to implement to appropriate any money to that fund from zero up to the full $90 million per year.

And the other question, it says a commitment to, is there any estimated timeline that this $40 million would transpire as it relates to First Gas? Sure. Coach Hoffman, I don't have an exact timeline. We can get that later. Senator Keogh.

Thank you, Mr. Chairman. So, Mr. Stickel, do I understand that July 1, 2060 date to be the deadline for a project to get a final investment decision? It's a— I think from memory, if my mental math is right, 34 years to get started. Sure, Senator, Senator Keel, through the chair. So the 2060 date is the deadline for the Commissioner of Revenue to make a determination that the developer has made all of these various commitments, and that may or may not coincide with the final investment decision.

Mr. Chairman, I'll just note, if I may, 34 years ago we weren't even talking about the Alaska Highway. Gas line project.

The gas industry is a pretty fast-changing critter. That's an awful long time to assume that anything we pass today would be the right deal should the project not go forward in the next couple of years. I'll be around to check on that in 2060. Further questions, Senator Kehl?

Please continue. All right. So slide 16 lays out some of the details of the Fairbanks spur line requirements, which is one of the conditional requirements to be eligible for the, the alternative volumetric tax and the property tax relief. So the project plans must include a spur line that serves the city of Fairbanks and the surrounding borough. Must have sufficient capacity to serve reasonably projected demand.

Must be scheduled to begin operations within 2 years after commencement of operations of a major component of the main project. Must connect with local distribution infrastructure. That last point, there was some concern that potentially a spur line could bypass Fairbanks and just go to a military base or some other industrial base, the bill does require that it connect with the local distribution infrastructure. Costs for the spur line may not be allocated solely to the interior of the state. So those would be— those costs would be shared system-wide within the in-state customers.

And under, with the conditional effect, the owner must begin the permit applications and regulatory process before completing the first phase of the gas pipeline construction. And then they must begin construction on the Fairbanks Spur within a year of receiving those permits and meeting regulatory requirements. And so basically, this lays out a process where the developer needs to commit to the Fairbanks spur line with certain parameters, but does leave some flexibility if there's some sort of a permitting, regulatory, or legal hiccup. So in the past, there also was included takeoff points at the Yukon. It's good to help Fairbanks, but there are are other areas outside of Fairbanks that even have higher costs of energy than Fairbanks.

And it's my understanding this current piece of legislation does not have that takeoff point on the Yukon to address even areas outside of Fairbanks that have higher costs, and I'm pretty sure that Senator Cronk would be interested in your comments in that regard. Sure, Co-Chair Hoffman. So this bill does not preclude a takeoff point other than South Central and Fairbanks, but it does not require it. I would think that it would— it should be included. Senator Cronk, what's your position?

Thanks, Mr. Yeah, absolutely. I, I want to make sure we have takeoff points wherever it's possible, you know, and if not on the Yukon, at least something around Nenana where they, they— that's where they barge everything from. I mean, so yes, I would definitely be interested in making sure that we have something there in place for when the time, you know, comes.

Further questions? Please continue.

All right. So slide 17 discusses the property tax changes that would take effect if those contingencies were met. So the bill would replace certain state and local property taxes with an alternative volumetric tax. There would be a temporary abatement period initially. So under, under current law, the project would be not subject to tax during the construction period as long as AGDC is involved in the project, which they are.

This bill would further provide for temporary abatement during the initial years of production. And so that would be either 5 years or until 500 million cubic feet per day of project throughput threshold is reached. That 500 million cubic feet per day effectively means exports of LNG. So basically, there's a tax— tax-free for the first 5 years of in-state production or until LNG exports begin, whichever comes first.

And then the Property— the property would be fully exempt from municipal and state property taxes. And there is a terminator here. If construction of the first phase of the project has not begun by 2032, then this— the tax relief would repeal.

Questions on this slide? Seeing none, please proceed. Mr. Chairman. Yes, Senator Kiel. Just to make sure I understand the interaction of the provisions, it repeals in 6 years if you don't at least start building the pipeline, and in 34 years if you don't do the things we require you to start to start the pipeline?

I'm confused. Yeah, Senator Kyl, through the Chair.

So the 2060— the 2060 provisions are relating to the deadline for the conditional effect of the DOR determination that the developer has met various provisions. The 2032 date is based on construction of— starting construction of the first phase of the gas pipeline. So putting those two dates together, you could envision a scenario where the developer could start production— start construction on the gas pipeline or construct the gas pipeline and then later on receive the determination that that pipeline is eligible for property tax relief. Practically speaking, it probably would work the other way around.

And, you know, potentially if there are some of these dates could get adjusted on down the road.

So Mr. Sickel, it does seem a little weird that you could get the determination and get your tax relief after you've done the thing for which you need tax relief. Is there a reason not to just make a match?

Senator Kiel, through the chair, I'm not thinking of a good reason.

I guess potentially you could have a situation where for whatever reason the Commissioner of Revenue hasn't made a determination that the conditions have been met to their satisfaction and it gives a little bit of flexibility on those. Thank you, Mr. Chairman. Thank you. Can you explain why we have on the fourth bullet the construction as a trigger and why not have FID as a trigger?

Co-chair Hoffman, that's a policy decision. I can't explain why we chose construction and not FID. Under what scenario would you see construction taking place without an FID? I don't think you would, Co-chair Hoffman. But what construction— I guess one benefit of using construction as a trigger is that you have to actually have work being done on the pipeline, as opposed to an investment decision where you make a decision to do construction at some point in the future.

So this— the way it's set up now is you would— the developer would actually have to be on the ground with people building a pipeline by 2032.

Further questions on this slide?

Please proceed, Mr. Stickle. All right, slide 18 continues with the property tax changes, looking in terms of our fiscal estimates. So our official spring revenue forecast conservatively does not include any revenue from the AK LNG project or related development. And so what we do here is we show If the project were to proceed without tax modifications under our baseline set of assumptions around the project, which include a $46.2 billion real 2026 capital cost and first gas in 2029 for in-state, first exports in 2031, full project capacity of 3.5 billion cubic feet per day of exports in 2033. So those are kind of the baseline assumptions.

If that project were to come forward without tax relief, state revenue from property tax is estimated at $25 million initially, ramping up to $244 million by 2033 in full operations. And then we lay out here the, the municipal revenues associated with the AK LNG project, which would total $50 million initially, ramping up to nearly $500 million in 2033. So in total, once the project is at full capacity operations in 2033, we're looking at around $750 million per year of property tax revenue from the project to the state and municipalities if it were to go forward under current law. Looked at it another way is almost $750 million of property tax burden for the project. And again, these are under our baseline cost assumptions around construction cost.

If the project were to have a higher cost than what we are using in our baseline assumptions, we would expect the property tax numbers to be higher as well.

Can we get that— those tax numbers broken down between the state and municipal totaling the nearly $500 million in 2033 for the committee at a later time? Sure. Co-chair Hoffman, so the, the $497 million in 2033, that is just the municipal portion. So do you have what the state's portion is? Yeah, so the, the state's portion is the $244 million.

And then the $497 is the municipal portion. And so you would— to get the total property tax burden, you would add those two numbers together. And the numbers, the total amount of tax relief under this bill that municipalities would have to forego, and what is the numbers for tax relief that the state would have to forego?

Sure, Co-Chair Hoffman. So I will get into that in the coming slides. Okay. Senator Stegman. Thank you, Mr. Chairman.

I think it would be helpful, because I think we're going to be spending quite a bit of time talking about the timing of the cash flows and working that in time to try to come up with something to help, uh, incentivize this project. Um, it would be nice to have this in more of a table format by year— 26, 27, 28, up to 33. And then, um, on the horizontal portion, you could have your municipal property tax, state portion, so we can see in each year what the burden is expected to be. And I think your baseline is you're using $46 billion or what? Can you help us with that?

Yeah, Co-chair, Co-chair Steadman, so the baseline assumption is $46.2 billion real capital cost. Okay, and thank you for that. And we'll get into that later in much further discussion. And then we're looking at 20 mils here. And then it was 7 for Kenai for the liquefaction plant?

Co-chair Steadman, I don't have the exact mil rate off the top of my head. I believe it was 9. Okay, 9. Well, we'll just use 9 for conversations if we could, Mr. Chairman. So that would be helpful for the committee so we can actually take a look at it annually because— and where they're coming from.

Obviously, the— looks like this pipeline would come first, right? And then at some point they would start the construction. But when they start the construction doesn't necessarily mean they finish the construction in one year. And the property tax calculation has to be made, and then there's a delay in collection. So I'd like to see the— see the table set up as when the you know, when they would pay it, which is critical when you write the check if it's in August or October or whatever, because we're going to definitely spend some time on the cash flow issue.

That's the crux of the bill is the incentives of property tax relief, so I would concur with Senator Steadman. The more detailed, the more transparency on this issue for the committee and for the general public, the better.

Sure. And to the questions, Co-Chair Steadman, we have some charts showing year-by-year revenue on slides 36 through 38 later in the presentation. We also have that in table form. Have a detailed spreadsheet that lays out all of the revenue sources to all of the municipalities for each year that we've modeled, and we'd be happy to provide that to the committee. Thank you.

Thanks, Senator Steadman. Mr. Stickel, please proceed.

All right, so, yeah, so the way we've laid out these slides is we first talk about the property tax what that could generate, um, and if the project proceeded under current law, and then we talk about the alternative volumetric tax that's being implemented in lieu of the property tax and what that could generate under this bill. So slide 19 talks about the alternative volumetric tax. And so this, again, there would be a temporary abatement for the first 5 years or until, uh, 500 million cubic feet per day of project throughput. Um, once that threshold is reached, the alternative volumetric tax would be implemented. Um, this version of the bill has a formula where the alternative volumetric tax is calculated based on the portion of capital expenditures, uh, that go into each component of the project and how much of those accrue to each of the municipalities in the project.

It's a $0.06 alternative volumetric tax for the pipeline, $0.12 per 1,000 cubic feet for the treatment plant and LNG plant. And then the way the, the way the bill works is it works through a formula that takes like a weighted average of the capital expenditures to each of those components.

But at the end of the day, that works out to about a 10 cents per 1,000 cubic feet alternative volumetric tax. So a kind of complicated way of getting at that 10 cents alternative volumetric tax. Practically speaking, by having the different weights, that would give a little bit more weight to the communities and the components for the North Slope Borough and the Kenai Peninsula Borough where the treatment plant and the LNG facility are. It would also allow for a lower alternative volumetric tax potentially early on in the project if there was a Phase 1 only scenario.

Senator Keogh. Mr. Chairman, Mr. Stickle, it might be helpful to, in a future presentation, run us through that weighting, especially for the benefit of the public who generally think, gee, if 1,000 cubic feet of gas go through the treatment plant, it's going to go through the pipe. And if it's going to go through the pipe, everything that doesn't get burned in Fairbanks and Anchorage goes to liquefaction plants. So it would be helpful to understand a little better how those stack, or I guess don't stack, and how we reach that 10 cents. When you say weighted average, 10 cents on everything through the LNG facility?

Senator Kyl, through the chair, so when I say 10 cents weighted average, that's for the project as a whole. And so, you know, the way it works is if you have— we take the capital expenditures And some sort of— however much capital expenditures were spent on the pipeline times 6 cents, and then however much capital expenditures were spent on the treatment plant times 12 cents, however much capital expenditures went to the LNG facility times 12 cents. We add all that up and divide by the total capital expenditures to get a weighted average tax rate. And under our baseline assumptions, that works out to about 10 cents per 1,000 cubic feet. And then there's a further weighted— a further calculation based on capital expenditures that goes for the pipeline and the various municipalities that that flows through.

Senator Keele. So it would be good to see that charted out, because I can I can run through that a couple of ways in my head, and it might be helpful to just have it laid out in front of us. Thank you, Mr. Chairman. Thank you, Senator Keehl. Mr. Stickle.

All right, and we will include a more detailed explanation of that calculation as a follow-up. And then the final point on this slide is beginning in January 1st of the— after the first year that the alternative volumetric tax applies, there is an inflation adjustment that would be based on CPI inflation, but with a minimum of 1% and a maximum of 2% annual increase. So in our modeling, effectively, we assume a 2% annual increase because our inflation projection is 2.5% annually. So what's the logic for the 2%?

Co-chair Hoffman, that's a policy decision. Having a 2% maximum increase limits the exposure to the developer from tax increase. What has been the inflation for the last 10 years average? Co-chair Hoffman, it has been higher than 2%. Substantial?

I'd be happy to get the exact number, but it has been higher than 2%. On average. Further questions on this slide? Seeing none, please proceed.

All right, so slide 20, a little bit more information around this alternative volumetric tax. So Department of Revenue would levy and collect the tax for the portion of the property in the unorganized borough. Municipalities would have the authority to levy and collect the alternative volumetric tax for the portion of the property located in their municipalities. So there's been different versions of the gas line legislation have done this differently. Some have had the state collect the entire alternative volumetric tax and then share that back to municipalities as a shared tax revenue.

This bill, the municipalities would collect their own tax, their own portion of the tax. We would basically do a calculation in Department of Revenue of how much tax each municipality is allowed to get, and we would give those numbers to the municipalities, and then they would, if they so choose, would go forth and levy and collect that tax for their municipalities.

And yeah, so again, we would handle all of these calculations, which can get a little bit on the complicated side for the municipal allocations, for the various weighted average tax rates. And the AVT would again terminate if construction of the first phase of the pipeline hasn't begun by 2032. And if that were to happen, we would just revert to current law.

Question on this slide? Seeing none, please proceed. Slide 21 has some more information around the alternative volumetric tax. So this looks at our fiscal— our revenue estimates, again, under that baseline scenario that I discussed earlier with the $46.2 billion real capital costs. So total state revenue from the alternative volumetric tax, this would be portion of the tax in— or the portion of the pipeline in the unorganized borough.

We estimate that that would be $4 million initially following the end of the tax abatement period. So this would be in 2031 when we have the first exports from the project, and then increasing to $15 million per year for the for the full project. Municipal AVT revenue would be separate. That would be collected by the, by the municipalities. But we estimate about $106 million to municipalities in that once the full operations are in 2033, the state would receive about 12% of the total revenue from the alternative volumetric tax.

That's based on the portion of the pipeline property located in the unorganized borough and that weighted average calculation that we talked about earlier. In our modeling, we're showing the alternative volumetric tax as unrestricted revenue to the state.

As I talked about earlier, the bill does create an AKLNG mitigation fund that the legislature may appropriate create between $0 and $90 million per year or two. We have not included that appropriation and fund in our modeling, given we don't know what the future legislatures will choose to do in terms of that appropriation. But just wanted to highlight that that's how we're showing— that's how we're showing the modeling, is that we're showing that as unrestricted revenue to the state.

Questions? Please proceed, Mr. Stickle. All right, so slide 22. This bill creates and adjusts different, different funds. So creates the Alaska Liquified Natural Gas Project Mitigation Fund that I was just talking about.

Each fiscal year, the legislature may appropriate up to $90 million to the mitigation fund from revenue received related to an AKLNG project. So the exact definitions of how we would define what revenue received related to AKLNG, there's some discretion there. Does that mean AVT directly? Does that mean including upstream activity associated with the project. But at the end of the day, the legislature has the ability to make an appropriation to this fund if they so choose.

And there's different— there's different waterfalls for the first $30, $60, and then up to $90 million of appropriations and how those flow out to impacted communities.

Senator Steadman. Yeah, thank you, Mr. Chairman. I'm just kind of curious on the— just a concept— or when we look at the mitigation fund in mitigating this, are we trying to mitigate some of the negative impacts during the construction of this project, or are we trying to mitigate well beyond that in the general operations of the facility? What do we— what's the goal here we're trying to do? Sure.

Co-Chair Steadman, so there's kind of two aspects of the funding. So we do have the required $40 million contribution from the developer that is, you know, that is directly for mitigation of expenses during construction. The, the $90, the up to $90 million through the mitigation fund. The legislation itself is silent on the, the purposes, except that there is a fund created and the legislature may appropriate up to $90 million of that. And then that would distribute to the communities potentially impacted by the legislation.

Senator Steadman. What impacts do the communities have when they got a pipeline running through it that's like taps, that is just sitting there running? We haven't had complaints about mitigating taps because it goes by somebody's— goes through somebody's borough. Sure, Co-Chair Steadman. So I would defer to the municipalities.

We've had testimony from the mayors in other committees. I'm not sure if they've been before this committee yet, but talking about direct impacts of facilities as well as indirect impacts of workforce, housing, roads, public safety, those type of impacts. So there are costs to the communities for supporting the workforce and the infrastructure associated with a pipeline. Mr. Chairman, I think there's a difference between mitigating construction and impacts to the construction process and demobilization of the 8,000 or 10,000-person workforce than there is after first gas and it's all up and running.

Unless you're sitting in Kenai and you're at the liquefaction plant, which is going to create a lot of employment, and then on the North Slope, possibly the conditioning plant and the added workers there. I fail to see the impact. Of this project after demobilization of the construction.

Yeah, I— Co-chair Steadman, so yeah, I mean, that's a good observation and obviously a policy decision on the— both the fund as well as the appropriation. So the legislation lays out the fund and the legislature may appropriate And it's very clearly up to $90 million. And so that would be a decision that would be made by future legislatures as looking at the need for those funds and making the determination of whether to make that appropriation and to what level to make that appropriation. Senator Steadman. Well, I look at it as just general fund money.

It comes into the pot. We can appropriate it anyway. If we have— issues in a particular community because there's some impact after— I'm talking about after construction and demobilization, right? We can address that. We don't need to have some separate bucket of money.

General funds are fungible.

Thank you, Senator Steadman. Senator Kaufman. Thank you. I'm wondering if maybe part of that was for decommissioning, of creating a future decommissioning fund in the— at the far-flung future when the pipeline is no longer needed to remediate it. So I don't know, but I just know that that's a consideration with any large infrastructure hydrocarbon project you put in is what's going to happen when it's done.

Senator Steadman. The industry is responsible for removing it, removing all the gravel pads, removing the roads, removing everything in Valdez and on the North Slope. Chances of that happening are zero. So they're not going to tear it out, but it's not the state's obligation. And I think that also includes the, the drill rigs in Cook Inlet.

Senator Kaufman. I was just saying we might find out in this case what mitigation means. So what are we mitigating? It could be all-inclusive or limited. I think it's good questions, but what's in, what's out?

Senator Keel. Thank you, Mr. Chairman. This would be a great conversation to have with the municipalities because I think there are some impacts on an ongoing basis. I'm a little surprised at the upside-down proportions. A $40 million fund for community impacts during construction, if we take an optimistic view and imagine that this thing gets built in 4 years, it's $10 million a year across 800 miles.

That's—. That doesn't go very far. And then once it's in place, as the senator to my right says, those impacts are likely to be somewhat less. To go up to potentially $90 million a year, we may have those numbers upside down.

Further questions on this slide? Seeing none, we'll take a 5-minute break. Back here. In 5 minutes, we're at ease.

I'll send the Finance Committee back to order.

We're on page— on slide number 23. Mr. Stickel, please proceed. All right, again, for the record, Dan Stickel, Chief Economist with Revenue. I did want I just want to clarify one statement about the mill rate in Kenai Peninsula Borough. So the current mill rate on property there is 9 mills.

I know the borough has been saying in various presentations that they are expecting 7 mills on the project. In our modeling, we're modeling based on 8 mills. So somewhere in that range. Obviously, there are future decisions to be made by the borough on what that tax rate would be absent this bill. But somewhere in that 7 to 9 mil rate is a good working assumption.

Thank you, Mr. Stickle. Please proceed. All right. I think we had finished up slide 22 and we are moving on to slide 23. 23.

So slide 23, this bill creates various provisions around AGDC and state investments. So AGDC is required to negotiate an option for a state interest if they negotiate any arrangements around the project. There's currently an option for a state ownership interest in the project, and this basically maintains that that will be the case if there's any further negotiations in the future.

The legislature has an approval process in those— in acquiring any interest in the project. And what this bill requires for Department of Revenue in particular is it requires that we assist the legislature in determining whether to acquire an interest in the project. So we would be doing an analysis of funding sources and an analysis of fiscal impacts and basically cooperating with both the administration and the legislature in making making a determination on those state equity investment decisions.

The bill also requires that there be an opportunity for municipalities to purchase into a portion of the existing AGDC right to exercise an ownership interest in the project. So if the state does not take the full 25 ownership interest that we're entitled to, then this bill would allow municipalities to buy into that remaining interest. That certainly doesn't, doesn't preclude municipalities from making a separate investment directly with the developer, but this basically guarantees that right between the state and municipalities to take up to a 25% ownership. And then—. Just when he's done with the slide, Mr. Chairman.

Sure. Yeah, the last slide here is that— or the last bullet point, AGDC and a subsidiary, if they issue bonds for more than $5 million, so any significant bond issuance to support a state investment that requires legislative approval under this bill.

Deadman. Couple issues. I've seen the bullet points reference the legislature, the legislature. But what about other entities wholly owned by the state? Could be the Permanent Fund, it could be the railroad, it could be Alaska Industrial Development Authority.

How do those interplay with that definition of legislature? Mr. Dickel? Sure. Co-chair Steadman, so these provisions are specific to AGDC or subsidiary of AGDC.

That is certainly a good question of how— what would happen if other state agencies like a railroad or an ADO were to take an interest. Senator Steadman? Yes, Mr. Chairman, I think we should have our legal team take a look at that and our staff doing legislative research for exposure. The other issue, and this is more of a concern, is the dilution issue.

Looking at some of these statutes, you would think that, you know, we can buy from 5 to 25% of the equity in one of the 3 subcompanies. You might go in and own a particular percentage today and tomorrow you get diluted because they need to do another tranche of equity raising. So there's concern there that you may get your— you may be exposed to equity dilution.

So we think we— need to consider that situation, and we'll get into that later on, I think, in this process with Glenfarm and AGDC is a thorough explanation of potential dilution.

Sure, and good, good, said, and those are good questions, and certainly as part of this third bullet point where Department of Revenue would be working in a support role, that's something that we would include in our analysis.

Senator Keele. Thank you, Mr. Chairman. Mr. Stickell, how much help will your department be able to give a future legislature in this scenario? Will you be able to see all the way down into the corporate structures, all the way into the —gas sales agreements, potential gas supply arrangements, the equity terms on which other investors are entering. What— will you, will the Department of Revenue be able to give us fully informed advice, or will you be modeling based on what we mostly think?

Senator Keele, through the Chair, I certainly hope that we'll have access to detailed data.

As far as our ability to do modeling and analysis, we're requesting multiple positions and consultant support. So we are— we've identified kind of the budgetary ask that would allow us to do the best job we possibly can and be fully available to assist the legislature with the decisions. I want to see the data. I hope we're able I'd love to see it. Mr. Chairman.

Senator Keehl. Thank you. Capacity is a good read on the question. Wasn't my intended question, so I'll clarify. Assuming the Department of Revenue and/or DNR's fiscal analyst, commercial analyst folks have the brainpower you need, legally and practically, will you have access to all of that information?

Senator Kiel, through the Chair, I don't know.

Mr. Chairman, I would just submit that hope is not the ideal strategy when it comes to analyzing investments. That issue is of utmost importance to this committee, and we are working with administration to see what, if any, information can be provided.

Please proceed. Any further questions on this slide?

Seeing none, slide 24. All right. So slide 24 just talks about some of the other provisions of the bill. So if all of the bill conditions are met, there would be a required report to the legislature from AGDC prior to a final investment decision on Phase 2. So once Phase 1 investment decision has been made, presumably construction has begun, that would kind of trigger another look at the, at the project and the tax structure to see if we're on track.

And we envision that Department of Revenue would be supporting AGDC in that report and role.

We, we mentioned earlier that the property tax relief and alternative volumetric tax provisions take effect after a DOR commissioner determination that various bill provisions have been met. Envisioned that our commercial team at DOR would be supporting our commissioner's office in that as well.

The bill would repeal some provisions preventing regulation of an— of LNG import facilities by the Regulatory Commission of Alaska. That was a provision originally in Senate Bill 180. And then we talked about some of the contingencies around the bill, but other than that, there's an immediate effective date. So we would be able to get to work once this bill is passed. Senator Steadman.

Could we get a little further definition on the import facility and dealing with the RCA in that it appears that regardless if this project goes forward or not, there will be an import facility built in Cook Inlet somewhere to facilitate gas supply apply to the rail belt?

Sure. Kutr Steadman. So this issue of the import facility RCA regulation, that's a little outside of my wheelhouse. I'd be happy to provide some more information to the committee on that or also, you know, recommend that RCA could be a potential presenter to the committee. Thank you, Senator Steadman.

Please proceed. All right, so that concludes the kind of the primary bill provisions that impact DOR and the fiscal impacts. The next section of the presentation talks about our implementation costs for the legislation. So on slide 26 is our staffing plan. We're requesting 4 new positions to implement this bill and related support work for AKLNG.

So we are requesting a tax auditor to administer the alternative volumetric tax. So it would be a small tax base, but would create some additional workload, both in actually levying and implementing the tax, but then also the various calculations and review that we need to do and audit. To determine the, the capital expenditures and the weightings of those to determine the tax. Ultimately, the tax rate on the project each year we determine, and then the portion of the tax that would be allowed to be collected by the municipalities. We're requesting an oil and gas revenue specialist in our production tax audit team to support audit and valuation evaluation work related to major gas sales as well as associated new regulations.

Our existing regulations package was developed around a different iteration of the gas project, and so there are some material new regulations that we'll need to implement regardless of this bill to support gas commercialization. And then we're requesting two commercial analysts and in our research group. That would assist with the project certification and reports, and also with the required commercial analysis of state equity investment decisions for the administration and legislature, as well as generally relating to gas commercialization.

Expect that there will be further review of gas commercialization after this special session. So we will be staffed up to support that.

Next slide, please. Slide 27 is our capital request. So putting in a $500,000 request for upgrading our— upgrading, updating our tax revenue management system in a short period of time to implement the new alternative volumetric tax and the property tax exemptions. So that would be a new tax type within Department of Revenue that would be created there. We think we can do the, the regulations work using existing resources as well as the new positions added in this bill and existing support agreements with Department of Law.

We are putting in a $200 $250,000 capital request for outside expertise to assist with state purchase options and fiscal analysis. So we have the internal expertise to do modeling and investment analysis. Where we really could benefit from some external support is bringing in that global perspective of, you know, firms that are out there in the market and dealing with major projects like this on a global stage and doing various international comparisons and international best practices. Senator Steadman. Just kind of a broader question.

So if we look around all other basins in the lower 48, might as well throw in Alberta or wherever also, is there other entities that use this volumetric tax for their calculations? Or how popular is this concept? Senator Co-Chair Steadman, so based on some of the testimony I've heard in other committees, it's not an extremely common approach. Some manners of property tax relief is fairly common. There are some examples where an alternative volumetric tax has been used.

I think there was an oil pipeline in Europe that was cited as an example.

Thank you, Senator Steadman. Please proceed.

Slide 28 is— just puts our fiscal note expenditures on a slide. This comes straight from the fiscal notes. So looking at a little over $1 million per year of additional costs for adding those 4 positions and related costs, and then the $750,000 capital request.

And then the next part of the presentation is probably the part that everyone is really excited for, is our detailed project modeling. So here we take our— not just the impacts of this bill directly, complexly, but we lay out a series of assumptions around the AKLNG project and then look at kind of the holistic view of state revenue and state impacts under— if the project were to proceed under current law, or we look at both the original version of the legislation, which was Senate Bill 280 as introduced by the governor, and then Senate Bill 2001, which is the special bill. Mr. Steadman. If we could just take a couple minutes and kind of set the stage here because we could get off on rabbit trails and misinformation and so on and so forth. But if we back up to a previous gas line project under a previous governor, there was a proposal to build a gas line and with AGDC under different manager, executive director, whatever you wanna title them.

And they had a project. And the LB&A committee at the time was chairing, Mr. Chairman, and we thought that it was time that we sat down and looked at the project. So we contacted Department of Revenue, Department of Natural Resources, Department of Law, and LB&A, and we set up a meeting 'cause all entities that were just listed had no idea what kind of project AGDC had on the table. And we had that closed-door meeting to set the stage and find out the process and the analysis. Come to find out, AGDC didn't even bother to do any cash flow analysis and impacts on the state.

And the meeting was an absolute meltdown. Um, the tempers got way out of hand from some of the members of the administration because of the lack of understanding of the state's fiscal and basin positions. As an example, there wasn't a realization that there was an agreement with Exxon on Point Thompson, which is a huge gas supply. Anyway, that meeting went south. It was frankly the worst meeting, Mr. Chairman, in my entire life in the legislature here dealing with finance.

So we concluded after that meeting that the Department of Revenue and Natural Resources on the state level needs to put together an integrated financial model. And we had— we being LB&A had dialogue with administration and consultation with how the model works. And there was a lot of discussion between the consultants that the administration had at the time and our consultants.

And that model was put together. And that model, to the best of my understanding, is a good model. It's the model that is used today, if that's not correct. And that's the model we're going to talk about here for the next several minutes or probably hour or 45 minutes. And the reason I bring this up is because a model is no better than the inputs.

And I don't want to have the conversation today at the table to negatively reflect on the Department of Revenue or their employees. Because it is not the model that's the question or the operators of it. It's the inputs. Inputs and the lack of inputs where the discussion is, needs to be put on the table. So in the next several slides, Mr. Chairman, the department here will show us the model output given the inputs.

The question is the inputs. And Senator Hoffman and myself had a meeting with the Governor yesterday and expressed an interest in having accurate numbers for the modeling so we can make financial decisions. 'Cause you can't make good financial decisions without having the information. So we've started that conversation and expressed an interest for the Finance Committee to have that data so we can have more realistic, expectations of cost and cash flows for various reasons, one of which is their— the Glenfarm is asking for some concessions from us, the state, to help facilitate the cash flow demands to get the project built. And we're working through that process now.

So anyway, I just thought I would put that on the table, Mr. Chairman, because it's I think it's very important. We do have an integrated model now so we can get an idea of the impact, not just on the pipeline itself, but the impact on our oil basin and the treasury and the impact on the industry, because we're all in this together. So with that, Mr. Chairman, I just thought I'd take that moment to put that on the table because there are new members here that weren't present when we went through the last fiasco of dealing with AGDC and the lack of integrated modeling and calculations.

Thank you, Senator Steadman. Please proceed, Mr. Stickel. All right. And I wasn't part of the meeting that didn't go so well, but I would generally agree with that characterization. So the model itself has been— it's the latest iteration of a model that we've been developing for over a decade.

It's been widely reviewed. We've had consultant testimony that this is a reasonable model to use as the open book economic model for the state. And we have developed a series of assumptions in collaboration collaboration with AGDC that set a baseline scenario. We are certainly open to running any scenarios that the committee would like to see with additional or different assumptions, and we are always welcome to any input or further clarification on assumptions from industry that they would like to provide. Thank you.

Please proceed, Mr. Stickle. Slide 30. Does lay out those key assumptions that we've built into our model baseline. So we're modeling a 32-year of gas sales, of LNG sales time horizon. So the model models the, the from, from current point through 2062.

So that captures 30 years of full capacity export operations. We're assuming an initial debt service and return on investment period for the developer of 20 years. So we're modeling those 20 years of full capacity sales and then an additional 10 years beyond that. We are assuming that the developer is targeting a 10% pre-tax return on investment through that 20-year of full capacity operations period. We're assuming a 70/30 debt-to-equity ratio with a 5% interest rate on debt issued for the project.

We are assuming a $46.2 billion real 2026 terms construction cost for the project. That was based on an assumption that was developed, an estimate that was developed before Glenfarm came into the project and has been simply scaled up to 2026 based on an inflation. We are assuming a gas purchase price in 2026 dollars of $1.50 per thousand cubic feet. That's the purchase price paid to the producers from the midstream. We're assuming that the gas will be transferred prior to the inlet of the gas treatment plant.

So the producers will sell the gas for $1.50 per thousand cubic feet at the inlet to the gas treatment plant, and then the entire midstream operation, the gas is owned and marketed by the developer. In terms of production, we're assuming initial production from some to-be-determined field on the slope that requires some level of gas treatment. We're assuming an initial in-state production, level of 65 billion cubic feet per year, which is a combination of— we're assuming a 50 billion cubic feet per year industrial baseload consumer and then an additional 15 billion cubic feet per year of local residential and commercial demand. We do assume that that demand will increase over time. The assumption here is that gas supplied by the AK LNG project will not supplant Cook Inlet production, but will instead kind of fill in the gap in, in, in in-state demand as Cook Inlet production declines over time.

For phase 2, the full export project, we're assuming that Prudhoe Bay and Point Thompson will anchor the field.

An important assumption there is what happens with oil production. So oil and gas come out of the same well, and so that interaction is an important assumption. The baseline model assumption, which was developed in collaboration with AGDC, is that there will be no net impacts on Prudhoe Bay oil production. And there are reasons that there could be potentially a temporary positive impact to Prudhoe Bay oil production. There are reasons that there could be a negative impact over time.

That's a very complex reservoir dynamics situation. But for simplicity purposes, the model assumes zero impact. Over at Point Thompson, the modeling assumes an increase to liquids production of 270 million barrels over the life of the project. There was some, some material new information that was provided by the Oil and Gas Conservation Commission earlier this session that suggested that that may be an optimistic number based on some of the newest information information around reservoir dynamics and production around the reservoir. So what does that mean is potentially fewer liquids barrels incremental at Point Thompson and potentially more wells and higher development costs required to bring that gas online.

For now, the assumption in our baseline is the 270 million barrels of incremental to oil production, and we have the ability to run scenarios on these oil impacts. We actually provided some of those to the Resources Committee back during the regular session on like the second to last day or third to last day. Happy to do similar analysis for this committee as we get to that stage of the process. Questions on this slide? Senator Mr. Steadman.

Just a couple points, you know, and I know we're gonna go through these slides, but at the end of, I assume there's 20-year debt being used. Is that correct? Co-chair Steadman, that's correct. We're assuming 20 years of debt through 20 years of full capacity. And then when we show some of the charts of revenue, You'll see that those last 10 years there's higher cash flows to distribute as the debt is paid off.

Senator Steadman. Yes, so, and we're trying to, we at the committee, we're trying to get some information on the government-backed, I think there's 3 different debt programs. We're trying to get that information, but I know one of them is government bond rate plus 3/8, so 20-year government bond 3/8 is about 5.5%, and half a percent is a significant numeric when you're dealing with billions of dollars. The construction cost, Mr. Chairman, is highly— well, I think— Speculative. Speculative is a polite way of putting it.

I could use other words, but speculative. We're trying to get that more narrowed down to a realistic expectation. The gas price of $1.50, I don't know what the gas price is, but we have a net tax system. I don't think that's gonna change.

Possible, but unlikely. And then when they do their, help me a little bit, Mr. Stickle, when they do the reporting after the gas line is up and functioning, they would have to report the revenue off of the gas from their fields for production tax or BTU or oil equivalents so we could back out and know the gas volume that's being sold. And then we only have 3 producers, maybe 4 producers of gas. Who knows, it won't be that hard to figure out the gas price. So, can you help me a little bit about how the gas price is set in the tax scenario?

If there's 4 producers and they all independently negotiate a gas price, assuming that they're probably not the same price, how does the department deal with that? And then how are you going to relay that information to the Finance Committee? And then I got a couple other points. Mr. Stickle. Setting the stage.

Sure. Co-chair Steadman, so in terms of the gas valuation, so when we're valuing oil and gas, we work off of a prevailing value concept in statute. And there's kind of an open question of exactly how prevailing value would be calculated with these gas sales. So we do publish a prevailing value for North Slope gas sold to utilities on the North Slope. It's a little over $3 per thousand cubic feet presently.

But that's for a very small quantity of gas. And so when I talked earlier about our need to develop regulations, this is an un— this is kind of an open question that we will need to address through regulations is exactly how we're going to set up that, that valuation methodology for the North Slope gas. So will we use the contracts? Will we do some sort of an average of the contracts? Will we incorporate some sort of a pro forma netback to the North Slope?

Will we look at those utility sales? That is an open question. In terms of our modeling, assumption. AGDC has stated that they're talking about gas purchase prices in the $1 to $1.50 per 1,000 cubic feet range, and that's why we chose $1.50 as our assumed purchase price for modeling purposes. Couple things.

$1 To $1.50 is a huge spread. Senator Steadman. Yeah, thank you. $1 To $1.50 is a huge spread. And if they're as far off as they are on their construction cost as their gas price, that is a concern, to say the least, trying to use a model to make policy decisions.

Then we'll have to wait until there's gas, first sale of gas, to know the price, or when do you— when does the department think they may know the price of this? Gas. Mr. Stickle. Co-chair Steadman, I can't answer that question. I don't know.

Okay. And if I could, Mr. Chairman, go to the next bullet.

My understanding is the arrangement that Hilcorp and Exxon has in their proposal, they'll sell gas basically at the wellhead or the tailgate, depending on how you want to define it. Basically Glennfarm's gonna have to build a line over to Point Thompson and up to the other one that Hilcorp has, and that name slipped my mind here for a minute, but my understanding of that one is— Yeah, Northstar. It's time to take the gas off, so that's not a concern as much as the highlighted point you just made with Point Thompson. There's reservoir issues, reservoir challenges unforeseen in Point Thompson that may be of concern dealing with the value and the gas offtake. And we can ask Exxon when they come here if they have any public information they want to talk about that and give us a highlight.

But that is a concern. So there's some extension construction extension. And I— is it safe for us to assume then that the feeder lines going over to Point Thompson and up to Northstar, they are not going to be deductible against the severance tax? Mr. Stickle.

Co-chair Steadman, so we When we're modeling out the Point Thompson, and obviously the exact details of the commercial arrangement remain to be seen, we are assuming that the purchase of the gas takes place at the inlet to the gas treatment facility, and that there is a feeder pipeline tariff to Point Thompson, and so the taxable value of the gas is net of a feeder pipeline tariff to Point Thompson. So it's not the full $1.50. Okay. And that is a modeling assumption. Okay.

Mr.

David. The impact on loss of oil, it's always been a concern. And when I think back when I was just getting out of high school, they built the taps and we were told that the gas line's coming. They're putting the hangars under the bridges and they're building a gas line. It wasn't until I got here to this table I found out there's no way in the world that gas line would ever be built for decades after Point Thompson was open, because you gotta get the oil out and oil's more valuable than the gas.

So now it appears that we're fairly close to the point of taking gas out of Point Thompson, but there is significant concern of of potential oil loss and how that is dealt with both on the state's perspective and then the producers at Point Thompson. Can you help me with that? Are they pricing that into their potential gas or are they not even— let me back up. My understanding is they're not even to the point of discussing taking off gas at Point Thompson Point Thompson yet. That would be under what we call Phase 2, after the pipeline's built and we do the conditioning plant at grander scale and the liquefaction plant for export.

So can you help me with the loss of oil at Point Thompson? Because my concern is we could be possibly in a net negative scenario where we turn a gas line on and we actually make less money. Reduction of oil production. Yes, Co-chair Steadman, so we ran some scenarios looking at the— for the Resources Committee looking at a potential range of impacts. So for Point Thompson, we're in our baseline modeling, we were assuming that we are assuming the 270 million total barrels of additional production.

Some of the testimony from AOGCC just earlier this month suggests that it could— the incremental oil production would still be positive, but potentially a lot less than that. And so we ran scenarios ranging from zero up to the 270 million incremental barrels of production. We ran scenarios for Prudhoe Bay looking at the zero oil impacts up to a 500 million barrel net reduction to oil production. And those scenarios, you know, they still show a positive impact to the state under our spring 2026 revenue forecast. If you were to assume higher oil prices, then yes, there are potential scenarios where the gas pipeline would be a net negative to state revenue.

Senator Steadman. And help me on the spring forecast. Well, I know the number, but I want you to talk about it. And then it appears that a lot of the comments that I see in the press and looking at the research is there's expectations where oil oil after we get the issue settled and sorted out in the Middle East. Most of the forecasts are bringing oil down into the $60s or thereabouts.

So could you help me with where your spring forecast is to where some of the forecasts are showing long-term oil prices? Mr. Stickle. Sure, Co-Chair Steadman. So our spring revenue forecast, which feels like we came out with that more than 2 months ago. But we do follow the futures market, and we're anticipating an oil price in the, I think, $75 per barrel range for the next fiscal year, and we are expecting that that price will decrease into the future to around $70 per barrel in real terms over the long term.

And under that oil price scenario is what we've incorporated into our primary modeling here.

And what I was referring to earlier is if you were to assume a higher oil price long-term, so if you assume that current prices would remain into the foreseeable future, then that would significantly alter the economics of a situation where you have oil losses due to gas production? Senator Steadman. So just, so if oil's $100 versus $75 versus $60, define those steps. It'll be easier for me to follow. If it's $100, are we going forward or backwards in your, in your forecast?

Sure, first of all, sure, uh, Co-Chair Steadman, so compared to our spring revenue forecast, if you have a higher oil price assumption, then you have increased benefits to the state from an add to oil production, which is what we have in our baseline revenue modeling. You would have a less benefits to the state if you had an oil losses situation. And then at a lower oil price, obviously the impacts of additional oil production would be less and the impacts of oil losses would also be less. And so it has to do with the value of oil versus gas and at higher oil prices, the impact of added or reduced oil production is magnified, essentially. Senator Steadman?

That's fine, Mark. Thank you, Senator Steadman. Please proceed, Mr. Stickell.

All right. So I think that highlighted— that completed slide 30. And again, these are just some of the key assumptions. There are dozens of other minor assumptions that go into the modeling. We have run some sensitivity analysis later on in the slides that show what happens if we change some of these assumptions, and we are certainly happy to run sensitivity analysis and alternative scenarios on any assumptions the committee would like to see.

So slide 31 is another set of assumptions, so we have, in addition to our main scenario, which is that the full project proceeds. So this has an FID on Phase 1 in the near future, and then actually has an FID on Phase 2 prior to Phase 1 production coming online. And so that is the baseline assumption, is the full project. We've also run a Phase 1-only assumption. And this is what happens if only the pipeline to South Central is built and there is never the full export project.

So here we're assuming actually a lower construction cost for the pipeline because it would only be the portion of the pipeline to South Central, not all the way to Nakiski, of $11.6 billion in 2026 $1.6 million. We are assuming that some level of gas treatment would be needed with a similar per 1,000 cubic feet cost for that treatment as for the full project. Initially, when Phase 1 was being considered, they were looking at Great Bear Pantheon as a potential source of gas into the project. That would be an outstanding Phase 1 gas source because because it's really high-quality gas that would not need to be treated to be used in utilities. So that could go straight— for Phase 1, that could go straight into the pipeline and straight to the burner tip without treatment.

There's been some delays and potential uncertainties around that gas source, and so we're now assuming that the Phase 1 gas source will require require treatment of some sort. That could be a smaller treatment plant, it could be an initial version of the main gas treatment plant, it could be some sort of modular treatment facility. For our Phase 1 only scenario, we're assuming that total demand starts at 50— 65 billion cubic feet per year in 2029, and again, that's a 50 billion cubic feet per year anchor industrial customer. We modeled that on a restart of the Agrium fertilizer plant. That could also be some other customers such as a major mine, a data center, some other industrial consumer, or some combination of those.

The key here is that we're assuming the anchor customer is incentivized with a low cost of gas at $6 per thousand cubic feet. And then the remainder of the demand is the in-state gas, so we're assuming 15 billion cubic feet per year initially for in-state, and that that will grow over time based on a DNR study that looks at anticipated shortfalls as Cook Inlet production declines.

Senator Kaufman. Thank you. Yes, this and maybe the earlier slide regarding the model. So if we have a place to put gas if we produce it, has there been any thought about how that may incentivize activity? It seems like, you know, if you drill and you hit gas instead of oil, right now that's not much fun.

But if you've got a place that you can put that gas and hopefully monetize it. Has there been any conversations about the economic impact of kind of de-risking drilling because, hey, we found gas, but at least, you know, we can do something with it once we have the line? Sure. Senator Kaufman, to the chair. So not— we haven't quantified that.

Qualitatively, absolutely, that's true. Right now, if a producer goes out and finds a marginal amount of oil that has associated gas or finds a gas field that doesn't really have much value to them on the North Slope. With a gas line, it would provide a potential way of monetizing that. And we have in the past seen exploration wells that have encountered significant quantities of gas and then those have been abandoned. Because there's no way to commercialize that gas.

Senator Kaufman. I don't know how we can capture that, but I think the positive impact of creating a healthier, more robust transmission system for oil and gas, as we think about all this, we should think about the net positive that it could have on oil production as well as gas if you're maybe getting more activity because the ability ability to monetize gas, de-risk the drilling a little bit. Thank you, Senator Kaufman. Senator Kiel. Thank you, Mr. Chairman.

I know this has sort of come up a little bit, but I just keep looking at that construction cost for the pipe. And I'll just— I did a little poking around. I think if you look at what the oil pipeline cost 49 years ago or so, And you take out the marine terminal, you just do the pipe, that was $6.6 billion. Of course, those were 1974 to '77 dollars. So construction cost inflation, that's about a $35 billion cost today.

I know this one won't have to go down out of the steep mountains into Valdez. I'm sure everyone's 10 times as smart as they were then, but if you cut it in half, that's still an $18 billion pipe, not $11.5 billion.

Thank you, Senator Kiel. Further questions on this slide? Senator Steadman. Yeah, I just don't want to be here like I'm bitching about everything, but I got a couple sniffles here. You know, for quite some time we were told that Great Barron Pantheon was going to be the gas supply, and some of us thought that was nothing but hot air, because they're not bankable.

They don't have any gas. You can't go to the bank and borrow, or go to the— and borrow $8 billion and put down— who's going to put down the $3 billion in cash when there's nobody on the other end to put any gas in it? You know, it's It's just ridiculous. So I'm glad that the conversations the last couple months have moved off of that and are centered around where we do have gas, Point Thompson and Northstar. So they are deliverable.

So that's a positive. But it doesn't build confidence in the proposal when we get bamboozled like on such a, fantasy for gas supply. So I'm— and I'm not directing it at— I'm looking at you, but I'm not directing it at the department. It's to Glenfarm and AGDC.

So I'm glad we moved beyond that. And then I'm a little concerned on the modeling if we're stuck with an in-state gas line. And I'm no gas guy, but talking to a few of the gas guys, spent their whole career building gas lines. One of the— they're always concerned about cost overruns. And the other one was sizing the pipe.

Too big, you can go broke. Too small, it's not efficient. And they get— they're concerned about building the correct size pipe. And the guys I talked to, they spent their whole life building them in Texas and New Mexico. But this pipe at 42-inch would be somewhere around 8 or 10% capacity.

How could we get at some point, hopefully we get a more accurate cost estimate, but the actual, just a high-level cash flow model, how much does the debt cost per year?

Total that can be generated out of selling to the rail belt, the gas, and what their debt coverage ratio would be. Some of the— just the real high-level underwriting numbers. I'd like to see those because I just have a hard time getting comfortable if we're stuck with a 42-inch line at 8 or 10% capacity and the folks even though I don't live there, the folks in the rail belt are stuck with the bill. Somebody's going to have to pay that debt service.

So anyway, could maybe you could help with that, Stickle, at rough ideas and just use the 20-year government bond rate plus 3/8. You'd be in the ballpark. We've been told what the debt would be. And then construction cost and we got annual debt service payments, and, and it's going to cost some money to run the pipe and just see how close it is. Sure.

Just tickle. Yeah, Coach or statement, and we'll be happy to include our anticipated debt service payments under our Phase 1 modeling assumptions as part of our follow-ups. The way that we've approached this modeling is we've taken our baseline assumptions and we have looked at what is the break-even cost of supply that the developer Glenfarm would need in order to achieve a 10% rate of return, baking all of this in. And then we've also looked at, given the uncertainty around construction costs, we've looked at sensitivities around that variable in particular, of up to 100% higher construction cost. And I do have those sensitivity slides coming up in the presentation.

And we have been told that the— while AGDC and Glenfarm are not sharing the updated cost assumptions, we are told that they are within the range of our sensitivity analysis for construction of between $46 billion and 100% cost increase to that. Senator Steadman. I'd like to see the lender lend on those numbers. Excuse me. And keep his job.

So further questions on slide 31?

Seeing none, we'll take a brief at ease.

Call the Senate Finance Committee to order. We don't want to rush through these slides. There are several slides yet to go, so we are going to pick up and continue with this presentation on Monday at 9:00 AM. AM. Any additional items to come before the committee at this time?

Anything else? 10 AM. Oh, it's 10 AM? I've been corrected. It's 10 AM.

With that, we are adjourned until 10 AM Monday morning.