Alaska Legislature: Senate Finance — June 1, 2026 10:00am

Sam.

Sa.

Call Senate's Finance committee to order 6-1-2026. We're in Senate's Finance Room in the State Capitol. Present today are Chairman Olson, Chairman Steadman, Senator Keel, Senator Merrick, Senator Coffman, Senator Cronkin, myself Senator Hoffman.

Today we will be finishing up our presentation from Friday regarding the volumetric tax. I invite Dan Stickle, the chief economist for the Tax Division from the Department of Revenue. Then we will hear a sectional analysis on Senate Bill 2001 from the Alaska Gas Line Development Corporation, AGDC. I would like to note that that we will also be hearing more from AGDC on Thursday and this morning's presentation is just to gear get geared toward the sectional analysis of the bill. Mr. Stickle, please identify yourself and continue with your Friday's presentation.

All right, for the record, Dan Stickle Chief Economist with Depression Department of Revenue so on Friday we had begun a lengthy presentation, walked through some history of history of property taxes, walked through what Senate Bill 2001 would do at a very high level, walked through our fiscal note for both revenues and expenditures. And then when we had left off with we were about to get into the detailed modeling.

So I think before this I'll just maybe flash the last two slides up real quick that we had walked through to refresh the committee and any folks at home who are tuning in. So we've developed a model for the Alaska Natural Gas project. And so the model has been something that we have maintained for over a decade, have a lot of confidence in the model itself. We've developed a set of assumptions to put into that model and some of those assumptions are have some questions around them. I know there's been a lot of discussion around that.

But so we started by laying out what are the key assumptions that we're putting into the modeling for our baseline. And we do have the ability to run scenarios around any of those. And so slide 30 just highlights some of those key assumptions. To recap, we're modeling 32 years of LNG sales. That's 30 years of full capacity operation.

So our model goes through 2062. We're assuming a 10% pre tax return on investment for the developer and a 20 year period that they're aiming to recap that investment. We're assuming a 5% interest rate on debt with a 70:30 debt to equity ratio. We're assuming a $46.2 billion construction cost in $2026. That construction cost is, is based on some information that was developed before Glenfarn came into the project.

So there is some uncertainty around that exact number. We're assuming $1.50 per thousand cubic feet purchase price for the unprocessed gas on the north slope from the producers. And we are assuming that the primary gas source for the project for phase two is Prudhoe Bay and Point Thompson. And we have some assumptions in there around associated lease expenditures as well as oil impacts. The baseline assumption is that there will be no impact on oil production at Prudhoeh Bay from off taking the gas and that there will be a net increase of 270 million barrels of liquids from Point Thompson.

And we had talked a little bit on Friday about how those those numbers have some uncertainty around them as well. And we've been running some scenario analysis in particular for the Resources Committee. We shared some of that information.

Senator STEADMAN thank you, Mr. Chairman. I guess a grain of caution here we don't have we have a good model. I think people are comfortable with the model. It's the assumptions that it's questionable. So I'd take, take everything that's going to come.

At least I am with a grain of salt. But in your modeling, are you looking at it as the state will hold a 25% interest in it or are you looking at the gas line ventures standalone with the state having no equity position in it? Sure. Co Chair Steadman, in our baseline modeling, we're assuming that the state will not take an equity position interest. And then we've run sensitivity analysis showing.

I don't think we have those slides in this presentation, but we'd be happy to, happy to provide those. We've provided them to several other committees looking at what ownership interest of 5 or 25, between 5 and 25% would look like for each of the components of the project. And then on property tax, do you have any assumptions regarding property tax?

CHAIR HOFFMAN so our base, so we what we're doing is we've run this, run this three ways. We've run a current law scenario where we look at what if the project were to proceed under current law with the existing 20 mils property tax. And then we look at the governor's, Governor's bill is introduced, which would have been Senate Bill 280 which had the 6 cent alternative volumetric tax, 6 cents per thousand cubic feet. And then we look at the Senate Bill 2001 proposal for the alternative volumetric tax. We assume that the current law property tax will continue to apply on everything not directly impacted by this bill.

And then later on, if we want additional tax scenarios and construction Cost scenarios, those can also be provided, such as a $60 billion construction line and a deferred property tax for 10 years that would be recouped the following 10 years. And what about if we were able to able to achieve.

A holiday of 21% at the federal tax rate for 10 years? Those are all can be accomplished in your model? Yes, Co Chair Hoffman. So we have the ability to run whatever scenarios the committee would like to see in terms of assumptions and tax parameters. Thank you.

Any questions on key assumptions? Seeing none, Mr. Stickle, please proceed. All right, so moving to slide 31 and this was the other slide that I presented on Friday, which just walked through. So our main, our main model and our kind of our baseline project scenario is that the full AKLNG project proceeds. So we get a FID on phase one in the very near future later this year, and then that's followed shortly by an FID on phase two.

And so the assumption here is that by the time the gas comes online for the end state for the phase one, that phase two is already underway in terms of construction.

We've developed this alternative scenario, which is a phase one only scenario, which is that there's an FID on phase one later this year and that phase two never happens. So that's kind of a worst case scenario of sorts. And so this slide 31 lays out our modeling assumptions for that phase one only scenario. So it is a somewhat lower construction cost for the pipeline. We're assuming $11.6 billion in real 20, $26.

And that compares to a little over $15 billion for the pipeline portion of the main project. Because in this phase one only scenario, the pipeline would only go to South Central and not all the way to Nikiski. We are assuming that there would be some gas treatment costs required. In the phase one only scenario, we assume a similar per thousand cubic feet cost of that treatment as what we're assuming in the full project. It would be a slightly.

A lesser level of treatment would be needed in the phase one only scenario. But then you would also miss out on some of the economies of scale of running three and a half billion cubic feet of day through the treatment plant. So for modeling purposes, we assume a similar treatment cost. And the folks at AGDSC have told us that that's within the realm of reasonable. For our demand assumption, we are assuming that Demand starts at 65 billion cubic feet per year in 2029.

This represents 50 billion cubic feet per year for an assumed anchor customer. This could be something like the AGRIUM fertilizer plant. It could also be data centers, large mining operation, some combination of of those industrial customers. And we're assuming that that anchor customer is incentivized with a $6 per thousand cubic feet price, so they get a reduced price to encourage the economic viability of their project. And then we assume that in state utility demand will start at 15 billion cubic feet per year in 2029 and increase over time, basically filling in the gap from Cook Inlet production as it declines rather than supplanting.

Senator keel. Thank you, Mr. Chairman. That last comment kind of went to my question about gas demand in 2029, assuming that the pipe can get built that fast. So, so I know that some Cook Inlet gas is under firm contract and some is under interruptible contracts they could replace with this. Is that the proportion in 2029 there's about 50 billion cubic feet a year under firm and 15 not.

Or can you lay that out for us? Yeah. Senator Kiel, through the chair and we do have AGDC folks here if they may be able to shed a little bit more light that. The 15 billion cubic feet per year was based on a DNR study in 2022. That's what we incorporated into our modeling.

My understanding is that there are some potentially some slightly updated numbers that that number might be a little bit lower now if we were to update it, but kind of in that ballpark. Senator Kiel, and so just the reason. I'm looking for clarity is that you talked about the Cook Inlet decline, which is not exactly the same thing as gas under contract, but are they close enough for government work or what? Help me understand. Sure.

Senator Kiel, through the chair so I guess the basic assumption here is that Cook Inlet will fill the needs of South Central. And we're not getting into the details of what's under contract, what prices those contracts are at. We're just looking at how much incremental gas would there be from phase one. And what you'll see is in this phase one only scenario that's likely going to be more expensive gas than what's supplied by the inlet. And so the presumption would be that utilities would only purchase as much of the gas line gas as they have to.

Senator kiel. Thank you, Mr. Stickler. I think that's probably a pretty fair assumption. I'm not an RCA expert, but usually they require you to buy the cheaper thing for your customers rather than the more expensive thing. Can you then help me with the anchor customer?

There's a piece of my head when I hear that these analyses Assume somebody new is coming on, they're going to burn 50 billion cubic feet a year. Roughly that. I think about some of our history of production forecasts where we assume that new field is coming on soon and there are a couple of fields that we saw in the out years of that production forecast for a long, long time.

I don't have the agrium knowledge to know are they reopening? Is there something else out there? Senator Keel through the chair so that's not something we know with certainty. It could be agrium. Like I said, there's some other options out there.

It could be some combination of those with the anchor industrial customer. Even at the $6 per thousand cubic feet, having that customer does bring down the cost for utilities from what it would otherwise be. And you know, certainly it's a possibility that that customer doesn't materialize in which case the average delivered cost of gas would need to be higher to recoup the investment than what we're going to show in upcoming slides. Clarification on that. You anchor industrial customer in South Central because that's where this line is going.

To be going to Co Chair Hoffman that's kind of the baseline assumption. It wouldn't necessarily have to be in South Central. Does it have to be where the line ends? So it could be an anchor customer in the interior off of a Fairbanks spur line. It could be.

There's been talk of a additional line from South Central over to Donlin Mine for example. But most likely the assumption here is most likely it would be a South Central Agrium data center or something like that. To consume 65 billion square feet a year in 2029 seems like a high task. And just to get me clarified,.

Who. Would finance such a line for $12 billion on a 42 inch line assuming $6 per metric cubic feet in $2026. I'm clawing my mind to find out what type of investment entity would even contemplate such risk. Sure. Co Chair Hoffman so I don't know if that's a rhetorical question.

If so we'll let it lie. If not, I would defer that to AGDC or Glenn Farn.

Further questions Senator STEDMAN thank you Mr. Chairman.

I've heard the issue of a Graham several times as an anchor tenant. But my understanding for agrium that style of business they need low cost gas, not high cost gas. So I would be a little cautious with that one because this doesn't look like low cost gas.

And then if the line is rounded off 12 billion, you're looking at 700 million or whatever in debt service and you know, your coverage ratios, things like that that I mentioned the other day. I'd like to see when we get into it further I'd like to see a more detailed first till first gas or the first couple years after first gas breakdown where this sales are coming from and what the costs are because I'm not quite sure. You know we have gas under contract in the Rail belt now and we've had some meetings on that previous and so they've got to deal with that, that issue and then purchase other gas either through LNG imports or through this gas line. So I think this is a. I look at this process here today as just an exercise on how the model works but it would be nice to have more detail and particularly pay attention to the cost to the consumer in the Rail Belt under these scenarios. Sure.

And co Chair Steadman so I think we've agreed to provide some year by year detail on the numbers in the model and we'll certainly provide that both for the full aklng project as well as for the phase one only scenario. I do have some slides coming up later on that look at cost to the customer in the Rail belt based on these Phase one based on this set of assumptions. And then for the discussion of actual contracts and what is contracted and who are those contracts going with I would defer those to AGDC and Glen Farm. We haven't been involved in the those. Discussions at DOR as your comments relating to Donlin Creek.

We've had an extensive hearing on that project and if my memory is correct their consumption would be about 10% of what Anchorage is consuming. But in their presentation they plan on starting construction in 2027 not waiting for this project.

By 2029 they will be in full mode extraction of gold. So I don't think that unless they will have already signed contracts for for their gas because they're not going to wait around for speculation on this project. I wouldn't, I would sign those contracts and they would be secured and be very difficult to break because that is 25 year life expectancy on that project. So I would, if I were a betting man I wouldn't bet on Donlin Creek using gas from the North Slope for the questions on phase one.

Senator Steadman, just a brief comment. A year or so ago we had conversations and were asked to sit tight on this particular project because it agram was going to potentially be an anchor tenant and they did their corporate analysis is my understanding. And then the issue Just went away.

So some of us concluded that it wasn't economic for Agrarium to continue to be at the table. That was I think a year ago.

Thank you, Senator Steadman, Senator keel. Thank you, Mr. Chairman. Just Mr. Stickles, so that I know which numbers I'm running for the cost of the South Central consumer. That initial 15 billion cubic feet a year in state pipe only. No export is what price of gas to the consumer.

Sure. Senator Kiel threw the chair and we actually, I think we actually added some slides if we want to hold that till a few slides later or I can jump to those slides now. We can wait till we get to. That's been a common question that we've received in these committee processes. And so for this particular presentation we've actually added those slides proactively.

So another question that I've been asked, why have phase one and phase two? Why not have one project? What's the logic of building phase one and splitting it into two phases? Sure. Co Chair Hoffman.

So I think the developer and AGDC are probably better apt. Better equipped to answer that in terms of the rationale for splitting that and how that relates to improving the financability of the project. Just thought you might have some insight. Further questions on phase one modeling assumptions with no LNG export. Please proceed.

All right, Stickle. So slide 32. And again, this is where we had left off on Friday. Friday. This outlines the scenarios that we modeled.

So we've looked at what happens if the full AKLNG project proceeds under three different tax scenarios. Obviously there's uncertainty around whether that full project would happen, especially under the current law scenario. But we do model the current law for the counterfactual. And then we model two versions of the bill as introduced by the governor. The original bill introduced in mid March, which was Senate Bill 280, and then Senate Bill 2001 which was introduced a couple weeks ago for the special session.

So slide 33. So this is a table of information that you'll see a few versions of this table. And what this does is we show total cash flows. Now these are revenues for the government entities. For the upstream and midstream entities, these are revenues, not profits.

So costs will have to be paid out costs and debt service will have to be paid out of these cash flows. But we do show total cash flow to each of the five entities over 10, 20 and 30 years of full export production. And so you see under, under current tax law, with our existing property tax and our baseline assumptions, state revenue from the project, including Both upstream and midstream components would be just shy of 30, 30 billion dollars over life of project and a little over 17 billion dollars to municipalities. And those are the two key, those are the two key metrics that we're changing by adjusting the property tax are those state and municipal revenues. And then on the bottom here we have two separate tables for cost of supply.

And what this shows is one, what is the cost of delivered gas to utilities that would be needed for the project to generate a 10% pre tax return on investment to the investor. And so our 2033 break even cost of supply given all of our baseline assumptions and current tax law would be $4.86 into the in state market and $9.07 per thousand cubic feet into the global market.

And a little bit later on in the presentation we've added a new slide that shows what futures market prices for delivered LNG look like as kind of a comparison to put these numbers into perspective. The bottom line is that that at $9.07 delivered this is a marginal project.

Senator Stedman and just to reiterate, this is under the 40 mid 40 range capital cost. Senator Steadman Couture Steadman yes, this is with the $46.2 billion capital cost. And we do have some sensitivity slides coming coming up looking at higher capital costs. And then If I could Mr. Chairman, roughly the operating cost of the line per year.

Just.

Sure. Co Chair Steadman, I don't have that number. You can get back to us. We can get back to you. I may have a lifeline that may have it handy, but we'll provide that in our response document.

Further questions on this slide, please proceed.

So slide 34 is the similar summary of cash flows and cost of supply for Senate Bill 280 as introduced by the Governor back in March. And so you can see here that that bill would have reduced total state revenues over life of project from 29.7 down to $22.5 billion and would have reduced municipal revenues over life of project from 17.3 billion down to just under $4 billion. And the result of those significant tax reductions to the state and municipalities is a reduction in the cost of supply for instate from $4.86 down to $4.43 per thousand cubic feet. And then for delivered LNG into the market from $9.07 down to $8.48. So almost a 60 cent reduction in the delivered cost of LNG into the global market.

And then slide 35 is the similar slide for the Bill in front of the committee. Senate Bill 2001. This bill would reduce total state revenues over life of project from 29.7 down to $22.8 billion, would reduce municipal revenues from 17.3 down to $6.2 billion, would reduce the in state cost of supply from the four. $4.86 Down to $4.47 per thousand cubic feet, and then would reduce The Global delivered LNG price in 2033 from $9.07 down to $8.55 per thousand cubic feet. So still a significant tax reduction and improvement to the competitiveness of that L and D price, but not quite as significant as the original version that the Governor introduced in March.

Questions on this slide, please proceed. All right, so slide 36 we have another set of another trifecta of charts. And this next three charts shows just a bar graph of annual state revenues. And these are state only, not including municipal revenues, but show total state revenues from the project and associated development. So this is both the direct midstream revenues from the project and property tax or alternative volumetric tax, as well as associated upstream revenues which would be increased production tax, royalties and corporate tax from the producers from both gas and and oil produced.

And so you can See in Slide 36 There's a brief period of a couple years where there's a net reduction to revenues. This represents primarily offsets against the oil and gas production tax from lease expenditures that we're forecasting associated with additional development at Prudhoe Bay and Point Thompson to bring on the gas as well as associated associated liquids at those fields. And then as soon as Exports begin in 2031, the project is a positive to state revenue under our baseline modeling assumptions. And once the full Exports begin in 2033, under current law it would be about a billion dollars per year of state revenue.

And should mention this is at our spring revenue forecast for for oil prices and baseline oil production which has long term oil prices in the $70 range.

Slide 37 is the similar chart for Senate Bill 280 as introduced by the Governor. And the major difference between slide 36 and 37 is the replacement of that state property tax with a much lower purple bar for the alternative volumetric tax. And this effectively reduces the annual revenues to the state from around a billion dollars per year to around $800 million per year. So even with that, giving up, if you will, of the property tax revenue still is a significant positive positive in terms of state revenue due to royalties production tax and corporate tax from the oil and gas production and then slide 38 is the similar chart for the bill before the committee. 37 And 38 look quite similar, somewhat higher state revenue under Senate Bill 2001.

It's so the weighted average alternative volumetric tax rate under the bill before the committee works out to about 10 cents per thousand cubic feet compared to 6 cents in the governor's original bill, but still looking at around $800 million per year of state revenue once full exports come online. Senator Steadman, again, Mr. Chairman, I'd take all these charts with a grain of salt. The.

To have anything materialize, you gotta have cost estimates and you've gotta deliver on those cost estimates. And it's when you could be off 50% or bit or larger on the capital cost completely changes the scenario that we're looking at. And As I recall, Mr. Chairman, years ago we did some projections dealing with our oil taxes probably over 15 years ago, and they used a variable price range for us with all good intentions, both our consultants, the administration and the industry, but they didn't vary the capital cost in reaction at the time. So when the value of the or when oil prices went up in the middle and the revenue didn't materialize, the building was aghast and that created a whole backlash and we came in and changed the tax structure. And that was just because we held our variables constant and moved just the price.

So the so I just put that on the table to remind some of the committee members that in the public that when you look at these and you expect this revenue, this is just a test of the model mechanics. There's no validity into the project, as far as I'm concerned, of what's on the table. Until we have an idea of costs and other financing ramifications, including the government assistance in debt and for the cost of debt and the capital cost. And later on in future meetings we'll get into that. But my understanding is that costs have been submitted for the project several months ago, and those costs are most likely coming to contractual termination, possibly even today or sometime this month, but relatively soon.

And the conversations I've had with some of the industry folks, both big and small, there's been significant cost escalations since January, dealing with equipment, fuel, manpower, what have you. And some of the rough impacts I've been given is 10%, and that's just since January.

So I would just again take this as a good presentation from the department on showing us the model. Now it works and it's a good model, but we need good inputs and that'll be the concern I think from some of the committee member here, members here. And we can't Mr. Stickle, expect you to have good inputs unless you're giving them.

Sure. And Coacher Steadman so I would generally agree with that. One thing to point out on this slide is the cost of the project itself. When we're locking in the alternative volumetric tax, there would not be a direct impact to this particular chart of a change in project costs. But certainly we have the ability also to run sensitivities around the upstream inputs because this chart is based on the price and production for the oil and the gas is the primary revenue sources.

Once we switch to the alternative volumetric. Tacks if the line is built. Senator Stedman, if I can just add a little bit.

So my current understanding, if we do an in state phase one, the industry will sell the gas at the basically the wellhead or at Point Thompson or at Northstar that construction cost from the treatment plant to those fields, I need to get clear on the deductibility of that against our severance tax. When there's severability of the ownership of the gas at the field basically or at the lease. I think that's a critical component. Yeah. Co chair Steadman and again this chart represents the full AKLNG project.

Regardless, the assumption is that the gas is transferred from the producers to the project at the inlet to the gas treatment plant. And so any development costs in the field, drilling of new wells, installation of new infrastructure, that those would be allowable upstream lease expenditures for the oil and gas production tax and that any transportation costs from fields other than Prudhoe Bay to the gas treatment plant that those would be allowed as a netback cost. So for instance, one of the fields that we include in the model as a major source of supply is the Point Thompson field. And so we assume, when we assume our $1.50 per thousand cubic feet purchase price that's at the inlet to the gas treatment facility. And so we are assuming that there's a feeder pipeline tariff to get from from Point Thompson to the gas treatment plant.

I think I understand that when you look at the entire project, my concern is and the point of transfer of the gas treatment plant, assuming that the industry doesn't decide they're going to retain ownership and deliver gas to Tokyo. That's a whole other issue that we need to deal with or at least be aware of. But in the event that we just get an in state gas line and we don't get the phase two and the gas is sold at the, at Point Thompson and at Northstar. And those feeder lines in the treatment plant has to be built to that.

The question is how is the deductibility of that calculated? Because my understanding is if the title is transferred at say the edge of Point Thompson, then all the lease hold expenditures from the owners of that lease would be applicable. But once title is transferred, transferred, it's a different structure, tax structure. So I need clarification on that. Sure.

Co Chair Steadman so, you know, as I mentioned, our modeling assumption is that the title is transferred at the inlet to the gas treatment facility. Certainly if the title was transferred at Point Thompson, that would be a different, a different arrangement for modeling purposes. It would probably look fairly similar if the line from Point Thompson to the gas treatment facility was part of the main project versus a feeder pipeline tariff. Either way, you would have a situation where the expenditures in the field itself would be allowable costs for the oil and gas production tax and then any cost of getting to the project or to the main project from the field would be a transportation cost. There's certainly a number of different scenarios we would establish.

We need to do a regulations project regardless for this. And so we'll be working through some of those issues once we know more about the, the actual project. So understood. I don't want to get too far into details, but my understanding is a proposal on the table now is Exxon's going to sell at Point Thompson. Hill Corp is going to sell at Northstar.

Somebody's got to build those feeder lines and that is, you know, so it would be nice if we have the ability to model that, that we don't go into phase two. We're stuck with phase one and the full ramifications of that.

So regarding the feeder lines, the number that you're using in here includes the construction of those feeder lines or does not include the construction of those feeder lines.

Co Chair Hoffman so to be honest, I'm not entirely prepared to get into all of the nitty gritty details on the feeder lines and our assumptions there. So that might be a good one to follow up with some more detail. I see this line of questioning is just getting into a little bit more detail than I was prepared to speak to today. That's fine, Senator kiel. Thank you, Mr. Chairman.

I had similar questions as well about, about whether that $50 price at the inlet to the GTP meant that the producer was going to pay off the cost of building and operating the feeder line from within the $1.50 or whether that was an additional cost to the project or cost to the gas consumer. Do you know that one off the top of your head? Yeah. Senator Keel through the chair and again, you know, defer to AGDC and Glenn Farn on the specifics of exactly what's being negotiated presently. And the most current information there, the way that we have modeled it is that the $1.50 represents the price at the inlet to the GTP and that the net back to Point Thompson is actually somewhat less.

And so that there's a feeder pipeline tariff and so that the tax and royalty are paid on the $1.50 less a feeder pipeline tariff. And I believe that's in the 20 to 30 cent range. 20 To 30 cents. Senator Keel, thank you, that's helpful. The other question, along comparable lines, I think I understood you to say that costs within the boundaries of a lease to lift and separate the gas, get it into a feeder pipeline are deductible lease expenditures, but that a feeder pipeline outside the boundaries of the lease needs to be covered as a transportation tariff.

First question is did I understand that right? Senator Kiel, through the chair in general, yes. Thank you. And then if I may, Mr. Chairman. So when I look at the bar graphs here.

Yes. Interested in the initial early years of state revenues in the negative zone on production tax, can you talk to us about the mix of.

First of all, I had understood this to be gas only at one point you said the production tax impacts our oil and gas. Which are we charting here? Sure. Senator Keel through the chair so this chart shows all state revenues. There is one production tax for oil and gas as I presented on, I believe it was February 16th.

There's a very detailed and nuanced calculation of how that works between different segments.

For the gas production tax there is a gross tax of 13% of gross value. For the oil side of things, there is a net profits tax. And any lease expenditures for on the north slope for co located oil and gas are allowed as deductions against the oil production tax. And so what those negative numbers represent is that we are assuming some significant capital expenditures are made in Point Thompson in particular as well as Prudhoe Bay to bring on additional facilities, drill additional wells to deliver gas into the project, as well as there would be additional oil development or oil production associated with that gas. And so in the years that those expenditures are incurred, there is a net reduction to production tax on the oil side as those are allowable lease expenditures.

And then once the field, once the project is in full operation in 2033 there is a net increase to production tax as we're reaping the benefits of those investments that were made. So for the committee's information we have three, three people online for questions. We have Ryan Farnsworth, Assistant Attorney General with the Department of Law. David Hubert, the Commercial Analyst for the Tax division with the Department of Revenue and Frank Richards, President of the Alaska Gas Line Development Corporation. Senator keel.

Thank you Mr. Chairman. So that's helpful. The incremental changes owed to the project, we shouldn't understand that the state will only get will go negative on all of our production tax for all of our oil fields.

At one point there was conversation in this project about a gas supplier who was not yet a producer. Does the negative impact to the production tax, would that be something that was subject to the. I'm going to get the name wrong. But the loss carry forward in the event that we had a non oil producer supplying gas, incurring expenditures? Senator Keel, through the chair.

Yes. So if you had a new company, a new entrant, any lease expenditures incurred would be allowed as a loss carry forward that potentially could be used to reduce future production tax liabilities for that company. Thank you. Thank you Senator Kiel. Senator Kaufman, thank you.

As I look at these models, I'm reminded that to me there's a model missing and that's the model if we don't somehow have a gas line. And I think it would be interesting if the baseline assumption that we were comparing these two was not variations within the gas line prospect, but the reality of bringing liquefied LNG in, regasifying it and putting it through the limited system that we have. Limited compared to the scope of what this would be. So you know, with that there's no revenue in all cost at least unless we're going to tax it just for showing up. And so I think we need to bear in mind as we look at these, that even though this is a, at the beginning, it's kind of a very low volume, you know, low benefit project in terms of profits and flow and all of that.

What it's really up against is bringing in gas, re liquefying it and the cost that all of that will bear once we, we start to bring in those barges, it's going to disincentivize any production in Cook Inlet and any idea of a gas line. So I think that's the baseline that I'd like to see. The what's the revenue impact of that if and what's the cost impact of that and then we can start to look at what we might be able to do if this prospect could be brought to realization. Thank you. Sure.

To Senator Coffman through the Chair. We do have some rough estimates of what the cost of imported LNG would be. We looked at a study that was done by BRG Group for importance instar a few years back, and we've inflated that up to the 2033 for a comparison to these breakeven prices that we're talking about. That comes out to the range of about $17 per thousand cubic feet. And what you'll see in the upcoming slides is under the full project, with the full aklng project, the delivered cost from the project would be significantly less than that.

And what you'll see is that under the phase one only scenario, the cost to consumers would actually be a little bit more than what we're showing for imports. Senator Coffman,.

Does that factor in Cook Inlet production? So one of the things I've been wondering with all of this is the transition of how. How we manage Cook Inlet. It's an asset. I don't want it to be a stranded resource that we underutilize.

And so how can that be utilized, even though we're looking at these other options? Sure. Senator Coffman, through the chair. So we have assumed. We've assumed that Cook Inlet is basically a constant in terms of there's an established decline curve and an established need for additional demand in South Central.

We assume that gas from the project fills in that demand. In a situation where you have a higher cost of service or a phase one only scenario, that is a very likely case. Certainly, if you have a situation where you have sub$5 gas coming in from the Aklng project, that would challenge the economics of Cook Inlet production. That's not something that we've analyzed in detail.

Thank you, Senator Coffman. Further question. Senator cronk. Thank you, Mr. Chair.

And kind of following up on what Senator Coffman said. So. We have projections of all this about the gas line, but what's our projections if we don't do anything? What's our projections for a state if we. For the next 20 years, if we don't build this gas line, or the next 50 years, if we don't build this gas line, what's the projections of the economy of Fairbanks per se, or the economy of Anchorage, if this cost goes up to $17 for importing gas?

Like, what is that projection of the damage that it's going to do to our state for not doing something? So I think we look at all. I mean, obviously this is important. We got to look at the. But what's the projections of not doing anything?

So that's kind of where I'm going. But I have one more question that's more of a statement. So when we look at the break even price for lng, let's just, you know, I'm just looking back at some of these things. It's $8.48. How do we know that countries like Japan, Taiwan, Korea aren't willing to actually pay more than that for the stability of having constant gas versus watching what's happening, you know, in a straight or shamir zone?

We don't know that because we're not the ones negotiating that. We don't know how much they're willing to actually say, hey, we're willing to spend more because we know this is going to be a constant. We don't have to worry about any instability in the world.

Further questions? Comments? Please proceed, Mr. Stickle.

All right, so slide 39 then. So this is the first of a couple of these sensitivity matrices, or I've heard them colloquially referred to as the heat map charts. And what we do here is we show, we start running some of our sensitivities. And so we picked out two of what we see as the most significant uncertainties. And certainly we can run sensitivity for any of the other variables in the modeling.

And so we show this for three different, the three different versions of the bill. Current law 280 is introduced and then 2001 as introduced. And what we do here is we on the horizontal axis, we show a range of upstream purchase prices for the gas. This would be the gas price price paid to the producers on the slope. And we range that from $1 up to $5 per thousand cubic feet, again with $1.50 being our baseline assumption.

And then for capital costs, we start with our baseline capital cost on the, and this is on the vertical, which was the $46.2 billion real. And we run that in increments up to 100% higher capital cost, which would be, what's that, $92 billion or so. And what we've heard from, what we've heard from the developer and AGDC is that the updated capital cost does fall somewhere in this range. And so what this allows you to do is under current law, this first chart shows the in state weighted average prices. Given that the full project proceeds, under current law, we would be estimating the forecast $4.86 per thousand cubic feet with $1.50 in the baseline capital cost as the break even end state cost of supply.

And you can see how that would increase or decrease with different capital cost and gas purchase price assumptions. And then again under the bill before the committee that drops down to $4.47 per thousand cubic feet for the delivered in state breakeven price.

Senator Stedman, just a quick point. You know there's a big difference between 46 billion and 100% increase when you look at the debt service costs, right? So these are not small numbers. The other point at like to bring up just as a reminder is I think the industry gives you a five year forecast every six months or at least once a year on the slope of capital cost going forward. And then you guys work diligently with the industry to get expectations of capital cost over the next couple of years before you put the revenue source book together.

And that doesn't seem to be a big secret. We don't know what companies are doing what, but you give us an aggregate number and an aggregate volume of oil and a price forecast so we can get a fairly reasonable expectation of our revenue stream. And those issues then are not on the table. We talk about budget scenarios, but we work with your numbers. So I just wanted to point that out that these capital costs certainly aren't secret when we're dealing with our upstream.

Further questions, please proceed. All right, slide 40 is the similar sensitivity matrix, but probably the more important one in terms of project economics. This is the sensitivity for the delivered break even price into the global market.

And again at the baseline assumptions of $1.5 gas purchase price and the $46.2 billion capital cost, we're assuming $9.07 per thousand cubic feet in 2033 under current law with that reduced to $8.55 per thousand cubic feet under Senate Bill 2001.

The next couple of charts look at in state only phase one. So this is that other scenario that we've presented where we're looking at what happens if the 42 inch pipeline goes forward but then the full export project does not proceed. And in this scenario we would have under current law with the baseline assumptions we'd have a $14.55 per thousand cubic feet weighted average price into the Alaska market and that would drop to $12.47 per thousand cubic feet under the bill as introduced by the governor again with a range of range of potential sensitivities around those numbers. So on this slide as introduced, there's an impact fund of $40 million.

Can you provide us with a scenario of $400 million at a later time, what that would look like with a more realistic, in my viewpoint of the impacts to the community's effect, the impact funds are probably going to even be higher than that. But $40 million is even low if it was an annualized cost. So can you provide that to the committee, Senator kiel? Thank you, Mr. Chairman. Mr. Stickel, can you make sure.

Sometimes I struggle to keep up. Can you make sure I understand why. Weighted average, what exactly are we averaging? Are we averaging in current Cook Inlet gas price with delivered in state? Help me.

Sure. Senator Kiel. So when we say weighted average, what we're referring to here is the fact that in our phase one only scenario, a portion of the gas is assumed to be sold at a discounted rate to the baseload industrial consumer and then a portion of the gas, gas is assumed to be sold to utilities. And so what slide 41 does is it looks at the break even, the total break even, regardless of who the gas is going to from kind of the project's viewpoint, what do they need to sell the gas for on average in order to achieve their 10% return on investment? And then what we do on the next slide on 42 is we actually show assuming that there's a 50 billion cubic feet per year to the base load at $6 per thousand cubic feet, what does that work out to for the delivered price to utilities?

So 41 is the average of the six in the utilities. And then 42 is going to be just the utilities. So Senator Kiel, so there is no Cook Inlet gas in this weighted average slide. This is only gas down the 42. Inch pipe, Senator Kiel?

Through the chair? That's correct. Senator Kiel. Might ask on the next slide. We'll hold off.

Please proceed, Mr. Stinkel. All right. And so as I mentioned, slide 42, what this does is it backs out that $6 per thousand cubic feet to the baseload customer and says what would you know to achieve this 10% return on investment, Given all our other assumptions, what would the price to utilities have to be for the developer to earn the 10% rate of return? And that price to utilities would be under current law, $22.7 per thousand cubic feet. And under 2001 is introduced would be about $18.63 per thousand cubic feet.

Feet. And I think what I mentioned earlier is that some analysis from a few years ago, scaled up with inflation, suggests that imports might be in the $17 range. Given the uncertainties, I would, you know, characterize the baseline here with the Bill implemented as being on roughly on par with imports in terms of prices.

In terms of what people are actually going to pay on the burner tip, you need to add a little over $4. So 1863 is going to be, you know, more like $23 delivered to the burner tip.

Senator Keel. Mr. Chairman, that assumes $11.6 billion for the pipe and no cost overruns of any substance at all, correct? Senator Keel, through the chair, that's correct. And what this sensitivity analysis does is it allows you to pick a higher price if you want and see what that works out to up to the 100% capital overrun. Mr. Chairman, I don't want.

I just think reality might have to intrude on the phase one only notion. Those prices would look pretty good if they were in Bethel.

Please proceed.

All right, so we have a couple of additional sensitivity charts and again we're just laying out several different ways of looking at these sensitivities to give kind of an example of the modeling. And we're happy to run a additional numbers as the committee requests. Slide 43 is a tornado chart that shows in state cost of gas varyings of a few different metrics given the full AKLNG project goes forward. And what I might do is focus on on slide 44 which is a very similar chart showing the delivered LNG export price into the global market. And what we've done here is we've shown starting with our little over $9 per thousand cubic feet delivered cost of supply into the global market.

How do some select assumptions sensitivities impact that cost of supply? And you can see that the replacing the property tax with the alternative volumetric tax decreases that cost of supply by about $0.50 per thousand cubic feet. If capital costs were to come in 10% below our assumption, it would have a similar impact. And we can see here that if capital costs were to come in significantly higher than what we're assuming, that would have really the largest impact of any of these variables on the economics of the project and what the delivered cost of supply would be. So that is a very important assumption.

If the developer were to target a large lower or higher return on investment than the 10% pre tax that we're assuming, that would also impact the cost that they would need to sell that gas for in order to have an economic project and then purchase price of gas from the producers is significant. So if you pay $0.50 less for the gas on the slide slope, then that ends up flowing through to the price that you have to sell the gas for at the market. And actually the delivered impact ends up being a little bit more than the 50 cents because some of that gas gets used as fuel gas along the way. And then finally cost of debt. I know there's been some talk around potential, potentially some options for reduced cost of debt.

And so we show, you know, we're assuming a 5% cost of debt and a 70, 30 equity split. If debt was lower or higher than that 5%, that would also be a material impact on the economics.

Senator steadman. Thank you, Mr. Chairman. We've seen these type of charts before dealing with our oil tax structure. And it kind of gives us a heads up on where to look for the sensitivity issue. So I appreciate you putting it in this format.

But if we look at the capex cost 50% increase roughly on 46, it puts it up at 69 or right at about 70 billion.

Some of us expect the price to be somewhere in that 60 range, not the 46. And under that scenario, this blue bar would basically be on the horizontal line and any cost overruns would be in excess of that. So it would definitely distort this process.

And just pointing out the, the when we use a 45, 46 billion as a base and if it turns out it's more, the base number is more like 60, all this analysis goes off the table. Just an exercise to exercise the mathematical model.

Thank you, Senator Stedman, please proceed. All right, so slide 45. There's been a lot of we've had some questions as we go through all of these slides and throw around all these numbers about cost of supply. Like what does that actually mean an $8 or a $9 or a $10 cost of supply. And so I chose one particular option for looking at global LNG prices.

There's a publicly traded price for delivered lng. It's called the Japan Korea marker. It has a spot market and a futures market just like a WTI or a Brent crude does. So you can see what is the futures market saying and what can people buy and sell future LNG for in the global market for Asia delivery? And presently those prices are very high.

With what's been happening in the Middle east, we're looking at LNG prices near $18 per thousand cubic feet. This year the futures market is projecting that those prices will drop as conflict in the Middle east resolves and new supplies come online. And so, so in 2031, when AKLNG project is expected to begin exports, that futures market price is a little over $8. And by 2033 it's in that 8:50 to $9 range. And what we've done here is we've shown current law and then current current law and then SB 280 is introduced as kind of the two goalposts in terms of what those prices would be into the market under all of our baseline assumptions.

2001 Would come in between those two lines, closer to the SB 280 line. And so you can see under our baseline assumptions, it would line up competitively with delivered LNG when the project would be coming online in the early 2000 and 30s. We also plotted two lines here showing a 20% capital cost increase above what we're assuming. And with a 20% capital cost increase above that $46.2 billion, this would be more expensive than what the futures market is saying. Certainly there's other reasons that folks may want to lock in supplies from Alaska as opposed to other sources.

This is just one possible indication of price, but it kind of demonstrates where these break even cost of supplies that we're showing kind of fit fit in with what the futures market is saying. And it also demonstrates that there's not a lot of give here in the project in terms of competitiveness.

Please proceed. And then the final slide I had is just some general conclusions. So Alaska LNG project, it's a significant project, has the potential to provide tens of billions of dollars for the state government, federal government, local governments, and also boost Alaska's energy security and the nation's energy security and that of our allies create thousands of jobs in the state. The version of the bill originally introduced by the governor would materially cost, decrease the cost of gas provided and make the project more attractive to investors. Senate Bill 2001 is a slightly, slightly less of a tax decrease, but it would still be a significant tax decrease that would materially impact the economics of the project.

So that's what I have for this presentation. Senator Coffman, thank you. It's not really in your wheelhouse, but just a thought. As I think about gas supply for Alaska, one of the things I recall is when I was working overseas in Asia and a lot of folks were driving around in cars that had natural gas proponents. They, you'd pull up to a filling station and they'd hook up that high pressure hose and they would replenish a tank in their trunk basically with natural gas and they'd buzz around using that.

So if we can get an efficient, you know, low cost gas supply, it's possible that some of the mobility problems that people are dealing with Right now we don't have low cost gasoline, but we could actually have vehicles that could utilize this gas supply. And so it could change, you know, perhaps some of the cost of transportation in the state. I know China has used buses and I don't know now, but in the past that had big gas bladders on the top of the bus. And so a full bus would have this basically this big mushroom bag of gas and it would drive around with that until it was depleted, and then it would go in and tank back up. And so you could have, you know, like a lower emissions.

It's not nearly as bad to breathe that as it is what comes out of a diesel bus. I'm reminded of that I took a walk this morning and one of the tourist buses pulled past me and parked right in front of me as I was walking. And that. And that was special. So there's.

I think there's opportunities here that we may not be. We can't always put on the table. But the big picture of what an efficient and cost effective gas supply for Alaska, I think it really changed a lot of things. I just want to be sure we keep those higher. You know, that shining city on the hill concept.

There's opportunity here, I think if we can just figure it out.

Thank you, Senator Coffman. Senator keel. Thank you, Mr. Chairman. The appeal of the big project, I think Senator Coffman has made some good points about. I keep trying to figure out this phase one concept, and I look at slide 42, and it seems to me that if every single thing goes right and nothing goes wrong, you could equal the cost of importing gas.

But if anything goes wrong, the numbers don't work. The contrast is I look at your slide 39 chart and assume the worst case scenario on that and then take from slide 43, the higher impact of the higher cost of debt and the impact of a higher margin demanded by the pipeline company. And Alaskans are still doing better than imported lng.

With the acknowledgement that the math is a little bit different for folks in Fairbanks. Is there a reason we would keep looking at a phase one project other than that, or should we just focus on the prospects of the export line,. Which. There's almost no losing, for the price of gas that Alaskans would pay for in state use?

Sure. Senator. Senator Keel, through the chair. So the policy decision on which projects you should look at, I mean, I would defer that. Certainly, you know, as was mentioned, there are benefits to gas supply beyond just the price of gas.

Although the, the numbers around price of gas and associated revenues are kind of our wheelhouse in Department of Revenue. The full project with the full export facility that would across the board deliver lower cost gas to Alaskans. And so that under any of these scenarios. That's true. Yes.

In the phase one only scenario that there is potential for competitive price, a potential for higher cost to Alaskans, but the phase one only would not necessarily provide lower cost gas without having the full project. And I think the plan. The plan and the hope is that phase one will be as its namesake, just phase one of the full project. Senator Kiel. Thank you, Mr. Chairman.

I heard it described as de. Risking the big project and I understand that as long as somebody takes the risk and, and where that price tag would go. We talked about at a previous meeting.

That's awfully risky to Alaska's fiscal future. But I think focusing our effort. We got 18 days left focusing our effort on what we may or may not be able to do toward the full project. That I think is a good use of our time and effort. Thank you, Senator Kiel.

Further questions of Mr. Stickle. Thank you. The committee's obviously going to be coming forward with additional scenarios. The committee can contact my staff, Pete Eklund, and we could have some scenarios run for committee members and we'll decide what to do with those at that time. Again, thank you for bringing this forward on behalf of the committee.

With that, we'll take a brief. At ease.

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Finance Committee back to order. The second item on today's agenda is a sectional analysis of Senate Bill 201. AGDC. We have the Matt Kissinger, the commercial director for AGDC. Please come forward, introduce yourself and proceed with your section.

Good morning. My name is Matt Kissinger. I'm the commercial director for AGDC and here to just provide the sectional analysis. So if you'd like to Chair Huffman, I can just carry on, please. All right,.

Just as a reminder. So I'm with Alaska Gas Line Development Corporation, an independent public corporation owned by the state, created obviously by the state legislature. And our mission is to maximize the benefit of Alaska's vast North Slope natural gas resources through the development of environment structure necessary to move the gas to local and international markets. This bill obviously is to help enable the gas line and the Alaska LNG project and as a result of identifying property tax really more than a decade ago as one of the major barriers to the project's economics. Section 1 legislative findings and intent.

This, this really just sets out that the project maximizes the benefit to the state, providing direct Affordable access to natural gas and in that it protects communities from the negative impacts going on to section 2. Section 2 modifies local contribution language such that when the facility falls under the alternative volumetric tax, it's no longer taken into account account for some of the local contribution requirements with respect to education funding.

Section three also removes project from property calculations related to the municipal taxing of oil and gas property. The sort of top up taxing that is allowed with the municipalities.

Section four adds just a small amount of language making AGDC a fiduciary of the state or ensuring that AGDC acts with fiduciary duty to the state. Not a lot of difference between how already we're acting with respect to our requirements to maximize the benefit to the state, work with DNR and DOR commissioners, et cetera. There is some unknown impacts on board members, etc. Whether there are liabilities that we're still looking into with respect to that language. A point of clarification on your presentation.

This section on analysis applies to both phases of the project. Is that correct? That is correct. Thank you.

On the slide here it mentions AGDC can only be wound down once AGDC and a subsidiary owners have paid off their debts, et cetera. That's actually existing language, so that's not a change from this bill.

Section 5 changes AGDC's procurement processes and basically creates it such that AGDC would have to comply with the Administrative Procedures act with respect to procurement.

Section 6 sets out new boundaries on AGDC's ability to enter into JV agreements or dispose of interest. And this goes with section 10 that we'll talk about later. Basically it provides a legislature be notified and have a certain amount of time to decline any transaction.

Section 7 provides a way for municipalities to invest in AGDC options. So you'll see later there's a section on new revenue generating projects and that's a way to capture what we call the subsidiaries of HSTAR as we go through certain financial investment decisions at each of those subsidiaries. AGDC, AGGDC has a 25, well between a 5 and 25% option to directly invest in each of those. And this section would provide for AGDC giving any remaining option that's not exercised by AGDC to the municipalities to exercise and they would be exercising it through an entity that AGDC manages. So it would not be a direct investment not involved directly in governance of the subsidiaries, but rather through agdc.

Section 8 puts a limitation on entering into confidentiality. And this goes with Section nine. Section nine really outlining what that Limitation is. So section eight is quite a simple one. Just saying that subject to these limitations.

And then section 9 allows for release of confidential information with a waiver from any parties to the cas. It disallows any CA that it disallows AGDC from entering into any confidentiality agreement CA that would place a significant liability on the state requiring appropriation from the state. And then it also disallows any confidentiality agreement around a state interest option.

Section 10 is this legislative notification that I mentioned before on Section 6 and it just requires if AGDC is going to transfer or transfer or dispose of any of its ownership in any of The HStar subsidiaries, for example, or any other ownership that first the legislature would need to be notified and then be allowed 90 days to respond with any sort of disallowal of that.

Section 11 is regarding the investigation involvement in revenue generating project. So anytime there is a revenue generating project that we negotiate for a state option will be required. And then section 12 again just goes back to section 5 where we said procurement to be pursuant to the Administrative Procedures act. And it makes just a slight change to enforce that. Section 13 requires that any of the revenue coming into AGDC in the future from the project goes directly to the general Fund rather than sitting residing with agdc.

As we read it, this would have a knock on effect with respect to our bonding authority, in which case we would require then appropriation to service any revenue bonds rather than having access to the revenue ahead of it going to the general Fund.

Section 14 is a change of ownership notification requirement. So any of the projects that we're involved in, if there's a change of ownership of 10% or more, we would have to notify the legislator legislature. This is actually some somewhat in line with Department of Energy requirements. Under the export authorizations they have a change of control requirement that they be notified anytime there's a change of control of 10% or more in the entity holding the export authorizations.

Section 15 just defines subsidiary in that it's any subsidiary that's controlled by AGDC.

Section 16 removes the project from oil and gas property tax if it's going to be instead taxed under the alternative volumetric tax.

Section 17 cleans up the oil and gas property tax language, especially with respect to some of the earlier exemptions AGDC had as a JV partner in not paying property tax during construction.

Section 18 is really where the tax, the alternative volumetric tax comes in as well as a temporary tax abatement. So it starts with a temporary tax abatement that would expire once the project achieves either 500 million standard cubic feet per day of throughput or five years from commencing commercial operations, whichever is first. It also sets out an alternative volumetric tax, which is $0.06 per thousand standard cubic feet flowing through the pipeline and $0.12 for gas flowing through the GTP and $0.12 for Gas flowing through the LNG facility. However, that is then weighted by the total proportion of capital that each of those segments it constitutes of the total project capital. So, for example, if the LNG plant is 40% of the project capital, that it would be 40% times the 0.12 in the alternative volumetric tax.

So the alternative is that who makes that decision, whether they want to use this form of taxation or the property. Tax method under this, my understanding is that it's the project sponsor applying to be a qualified project under this act, and then it would be the revenue commissioner that determines if the entity qualifies and there's certain qualification requirements, such as building a spur line to Fairbanks, having that spur line's rates be kind of rolled in with total state rates, etc. So that ultimately would be the responsibility. Of the commissioner of revenue to determine whether the entity qualified. That's correct.

Yep.

Please proceed.

Section 19 creates a mitigation fund of up to $90 million per year. And then it sets up how that that gets allocated between the different impacted municipalities and the state, depending on how much is allocated. So if 30 million or less is allocated, it's shared equally. If it's between 30 and 60 million, 5 million go to each of the North Slope Borough, Fairbanks, North Starborough, Denali, Matissitna, Municipality of Anchorage, and Kenai Peninsula Borough.

And then the remainder is shared equally between the North Slope Borough and the Kenai Peninsula Borough. And then if it's over, if it's 60 million, then it's 5 million to each of those, plus 15 each to the North Slope Borough and Kenai Peninsula Borough, and then the remainder to all municipalities in the state. Has the administration received any input on this provision as to is it adequate?

Chair Hoffman, when you say is it adequate, is it adequate to incentivize the project, or is it adequate for the. Municipalities to address the need to address. The need for the project?

It's very difficult to say exactly what level of property tax is perfect. Obviously the project is marginal and we need to do do everything that we can to improve it. On the other hand, there are impacts to the communities, and so it's really trying to find the right balance between Those I would hope that this does meet that balance.

Please proceed.

Section 20 is related to the import facilities. LNG import facilities and that puts it under the RCA regulation.

Section 21, uncodified law requires AGDC to report to the legislature on the effectiveness of the act prior to having a phase two fid.

Section 22, again uncodified. It sets out that the project will pay 40 million. And that is one of the qualifiers that I mentioned earlier that the Department of Revenue would be assessing. That would be for impact funding and would be then distributed to the municipalities and boroughs on the basis of demonstrated impacts. Is that an annual fee?

That is just an upfront fee.

Section 22, again uncodified. Sorry, that was section 22. Apologies. Section 23 refers to the effectiveness of the act and it picks apart different elements. That would be on a go forward basis acknowledging that there's already contracts in place that were negotiated last year.

Section 24. This gives the state 180 days to consider one of these options under a revenue generating project or any of the ownership options that AGDC negotiates. And that's in line with the current agreement with glenfarn that after FID the state would be offered this 180 day preemption. Right where we can back into the project directly by taking 5 to 25% of the equity being offered.

Section 25 is basically the conditional effect of this. And this is where the DoR commissioner makes the determination that the developers committed to deposit the 40 million into the community impact fund. Developers committed to negotiate the project labor agreement. Developers committed to pursue the Fairbanks spur line and have those rates spread out amongst all customers. And then developer has to demonstrate this by beginning the permitting and regulatory process before finishing phase one construction.

So I'm looking at that Fairbank spur line and going back to your mission which is to maximize the benefit of North Slope gas for Alaska. If you're going to really do this, why aren't you contemplating a takeoff point on the Yukon that would basically assist areas particularly in Senator Cronk's district that has some of the highest energy costs in the state. Chair Hoffman. I wouldn't say that we have that we are not looking into an offtake point at the Yukon River. I think you know that's something that still needs to be explored with respect to perhaps it could be liquefied at that point with existing facilities that are in the state sent down the river.

I think we just need to look into it further. Senator Coffman, thank you. I'm just curious if you know the concept of it. So the, I guess the mission statement that AGDC had was getting slope gas from the slope down to Tidewater. Basically, I guess if you summarize the mission statement, is there consideration of since this line crosses all the way, you know, it bisects Alaska, it goes from point to point pretty much of taps into it.

So I mean hot tapping a gas line is done all the time by gas line companies and those kind of hot tap provisions. Even if there's not a spur built into it, you can always do a hot tap and connect a branch off of it and that can be for input output. So if there's a new source of gas going in, you could do the taps you need to do and put more gas in from some other source or you could take it out and go somewhere. So is there anything that you know of in this, as it's written, that would prevent that other sources of supply or other points of use? Senator Coffin through the chair.

No, absolutely not. In fact, that's, you know, that's obviously a goal is to maximize the in state demand, especially during phase one.

Thank you. Which having those additional offtake points would do. Senator Coffman. So in state demand, but then what about other in state sources? Should they be discovered?

Yep. Senator Coffman, through the chair. Absolutely. We're in discussions already with Great Bear Pantheon. For example, they are south of the gas treatment plant and we've been in conversations with them being able to access it from that point and across Alaska.

All the way from point to point. Okay, thank you. Thank you, Senator Coffman. Senator steadman. Thank you, Mr. Chairman.

I got a couple basic questions. Maybe remind me if you could, how the board is structured and the members of it, because it's been a while since we've had the discussion with agdc. Senator Steadman through the chair. So we have a five member board. Two of those members are commissioners and they can't be either the Commissioner of the Department of Natural Resources or the Department of Revenue.

And the others are appointed by the governor.

And the current layout of the governor's appointees are who, who do they represent? So you have the chairman, Warren Christian, you have Doug Tansey, you have. Who else do we.

Then you have as the commissioners. You have Ryan Anderson, Commissioner of Transportation. You have Sandy as the Commissioner of Department of Commerce, Commercial Development. So in this five member board, does it take a simple majority on all decisions to take action by the board. As far as aware?

Yes, it does, Senator Steadman. So they're I was referring to the governing board over this project. So Glenn Farm has no representation on the board. There's no. I think we're talking about the wrong board here.

Yep. Senator Steadman, through the chair. Apologies, I thought you were referring to AGDC's board. The eight star board has two members appointed by Glenn Farnborough, one member appointed by AGDC, and then one member at large that's required to be an Alaskan resident. Okay.

And then if I could, how many? There's four. So how, how many members make up a quorum and how many members create a prevailing vote on an issue? Representative Steadman through the chair. Senator Steadman.

Sorry, Senator Stedman, through the chair. There are certain decisions that are unanimous consent decisions. There are certain decisions that require majority, and then there are certain decisions that AGDC as the minority member, just has a blocking right to. So it varies. And Mr. Chairman, can we get that delineated?

That's too broad of an answer. Can you provide the delineation on those categories that you prescribed? Senator Stedman, through the chair. That would be subject to confidentiality. And so we'd have to check with our partner on how much more detail we can provide around that and be happy to do that.

I would suggest that.

And then the model being used. What model do you guys use? Is it the same one that Department of Revenue has that they've testified numerous times with? Or how do you review your economics? Senator Steadman, through the chair.

So AGDC maintains our own model. That model is roughly in line with the Department of Revenue's model. Certain of the same people developed it. Our model was peer reviewed by Gas Strategies, by Exxon and BP and by Goldman Sachs through the years. And we just continue to maintain that model for our own view.

And again, it's roughly in line with the Department of Revenues mechanically. Any information that this committee needs that including the composition of this board,.

We. Need to know that we are exercising and not abrogating our fiduciary responsibilities. And what you're telling me is that we may. That may be requested here. So I would really like to see the response and what you think is confidential and not confidential, and what we may feel is necessary in order to exercise our fiduciary responsibility.

So that information that is being requested is very important to this committee. Senator Steadman? Yes. My understanding is there's four people on the board. Takes two for a majority.

The at large person has basically no authority. Glenn Farm has two positions and two votes prevail. So if you can get back to us on the breakdown of that and the authority, because it is of a significance issue here, the model used, I guess we'll have to have that conversation.

We have the previous testifier, the Department of Revenue. That model has been flushed out over the years, starting with, as we mentioned at the last meeting, a collapse of the last AGDC venture with Mark Meyer and no modeling being done north of Wellhead. And this model is that Mr. Stickle here, representing the Department of Revenues put forward has been, like I said, as you said, peer reviewed. It's been worked on with and looked at by not only the Department of Revenue, but Natural Resources, our consultants, industry. So we don't given particular set of inputs, we don't sit and argue about the outputs.

So when we ask in this case, Mr. Stickle, to change a particular factoid in that model or assumption, we're going to argue about, you know, some, maybe some assumptions, but we're not going to argue about the model.

So what I'm hearing you say that there was a new model created by AGDC that was, as you said, peer reviewed. Did that include the Department of Revenue and Legislative Budget and Audit? Senator Steadman, through the chair. So our model, I would not describe it as new. It's been around since 2017, 2018 timeframe.

It was constructed by people from the Department of Revenue that were seconded into AGDC or loaned into agdc, the same ones that have built the existing DOR model. And they're very similar. So we have a lot of confidence in the DOR model and both these models, generally with the same inputs, result in the same outputs. The difference between our model and the Department of Revenue model is the upstream impacts. Our model looks, is a cost of supply model that looks specifically at the midstream cost of supply on the basis of just an upstream input price.

Whereas the Department of Revenue model, as I understand it, goes into the fiscal impacts of the upstream as well. While we're on this, if I could just clarify one question that I think you had earlier about the transit lines. The transit lines are part of our project. We include them as part of the pipeline scope, but they are actually included in there. They're permitted as part of our project as well.

And so when we are buying gas from the North Slope producers, it is not into the input of the, of the gtp. That's one way of describing it. But in fact it first goes through a transit line of about one mile from Prudhoe Bay and about 40 miles from Point Thompson. Senator Steadman. Yeah, just back on that model concern that was a concern we had several years ago under a particular different management lead at AGDC that there wasn't any recognition of what was going on above or into the upstream above pump station one where our revenue resides, which is sitting in oil and oil and gas as we all know is integrated in the calculation of our expenditures and our net revenue.

And it is a concern and has been a concern of the legislature for years that we look at the entire, the aggregation of all of the capital infrastructure and how it's, how it affects our revenue stream and our deductibility. So you may conclude from AGDC's point that it is a, you know, marginal project to go forward. My concern is Department of Revenue may conclude like has been referenced here at the previous meeting. It could go negative, net negative revenue against the state. So that is a significant concern at the table.

And we don't know the impacts of oil loss on Prudhoe Bay. We're hearing concern and we'll get into that with AOGCC coming up. I think have some discussions. There's concern brought up about Point Thompson and the expectations that we all had and hoped for at Point Thompson for oil recovery or liquids recovery may not be as luxury lucrative as for both the state and the industry as we anticipated and that they may need to incur substantial capital cost in Point Thompson for additional drilling. So I just want to point that out Mr. Chairman, that we got to look at the whole enchilada or we can have our head handed to us.

And one last comment. What is the cost of this cost estimate that was put in my understanding in late November December cost estimates and how long are they good for to construct phase one, the pipeline?

Representative Senator Steadman, through the chairman I don't know the answer to how long each of the, you know, cost offers or estimates are valid for under the new Class 2 cost estimate.

But we can get that estimate. We can get that information. Yeah, we can seek that information.

My understanding it might expire this month or maybe even today, the 1st of June or somewhere thereabouts. Clearly Mr. Chairman, it wouldn't, I don't think contractors would give an open ended price anymore and they'd give you an open ended price on building a house. Just take your pick when you want to build it and I'll come build it. I don't think it works like that. So if there's escalators or whatever, but because there is concern about the time element and the escalatory pricing Since I had mentioned earlier, since even January of this year.

And it's hard, it's hard for the Department of Revenue which I think prides themselves on giving the Finance committee accurate information. When we sit in to have our discussion on capital expenditures in oil basin, you know, with a five year look forward to the last couple years they have a six month update or so from the industry and that's all held confidential but they give us the numbers, aggregate numbers in the revenue source book every fall, late fall in December and then they normally update the price but on rare occasions they'll even update capital costs in the spring revenue forecast. Yet we're being told here at the table it may cost 45 billion or it may cost 90 billion. It's not an acceptable answer, just not an acceptable answer.

Thank you Mr. Chairman. Time for lunch. Further questions. Mr. Kissinger, we look forward to the main question I think that this committee has is we are responding responsible to do our due diligence and if we need information hopefully we get that. We've had the chairman Steadman and I have met with the governor and been assured that we will get the answers that we have.

So looking forward to working with you and making things as transparent as possible so that the people of Alaska know that their gas, it's their gas that is being receiving the fair market value for the gas that belongs to all Alaskans. Any additional comments or questions by committee members?

Seeing none. That concludes this morning's meeting. Our next meeting will be tomorrow morning at 9am June 2. Anything else to come before the committee? Seeing none.

We are adjourned.