SRES-260511-1530

I call Senate Resources Committee meeting to order. Today is Monday, May 11th, 2026, and the time is 3:30 PM. Please turn off your cell phones. Committee members present today: Senator Rauscher, Senator Kawasaki, Senator Dunbar, Senator Myers, Senator Clayman, Vice Chair Senator Wilkowski, and I'm Senator Giesel. We have a quorum to conduct business.

Thank you to Heather and Kyla, who are here every meeting to help us keep track of the minutes and keep the audio going. Today we're hearing Senate Bill 280, Supporting a Gas Line for Alaskans Act. This is hearing number 26 since March 13th on this policy. So we're going to start out today hearing from the Department of Natural Resources. Ryan Fitzpatrick is online with us.

He is a commercial manager of the Division of Oil and Gas. In the Department of Natural Resources, and the question that we have for him today relates to where the gas ownership is transferred. So we're talking gas pipeline, and in the bill, the proposal is that the gas will be taxed at the point of production. So what is that? So the term that we've been hearing is— that's being used is tailgate, uh, this indicating the location where the gas is transferred from the well itself into a transmission pipeline that removes it from the lease.

So we would like clarification of that. Um, Mr. Fitzpatrick has attributed expertise in this area. So, Mr. Fitzpatrick, welcome to the committee, and we would welcome your remarks on the point of production and what the term tailgate might mean.

Good afternoon, Chair Giesel and members of the committee. For the record, my name is Ryan Fitzpatrick. I'm the commercial manager at the Alaska Department of Natural Resources. With the Division of Oil and Gas. I think maybe to start with the term "point of production," I think it's important to denote that "point of production" can mean different things in different contexts.

I understand from the Chair's opening remarks that some of this discussion touches on tax policy, like maybe the Alaska Oil and Gas Production Tax. At the Department of Natural Resources—. [Speaker:CHAIR YELLEN] Mr. Fitzpatrick? Mr.

Fitzpatrick, pardon me for interrupting, but you're coming through really fuzzy. Are you using a speakerphone? Sometimes that's the problem. I am on a headset. Let me, let me move to my phone and see if that helps the problem.

All right. Hold on just a second. Sorry.

Hello, is this any better? Well, it's really great. Yes, this is wonderful. Okay, apologies for that. So as I was saying, point of production is different depending on the context.

I believe the chair touched on questions regarding tax policy, and there's a definition of point of production currently within the Alaska Oil and Gas Production Tax. For DNR, our point of production is defined by our leases, and so that may or may not be the same as the point of production for the purposes of production tax. For the purposes of royalty, when DNR takes royalty, it does take it at the point of production for the purposes of our leases, That's defined as the point in which the oil or gas is severed from the lease or unit. And so typically we see, you know, leases, especially talking in the North Slope, are aggregated into units. There may be processing that occurs within the units, but once the oil and gas is removed from the unit, that's the point at which it is considered produced for the purposes of leases.

And that's the point at which royalty is paid on the, the oil and gas.

I believe there's a question regarding the term tailgate or tailgating. That can mean different things in different contexts within natural gas. Sometimes it refers to gas at the outlet of a gas treatment plant after natural gas liquids, things like propane and butane, are stripped out of the gas stream. That gas processing sometimes takes place within the units, and so the, the gas would pass through the gas processing plant. That tailgate gas would be the dry gas after those NGLs are stripped out.

That gas would then be severed from the unit subsequently, and royalty would be paid on that gas, and then the NGLs would potentially be sold separately and accrue their own royalty. On the other hand, it is also possible that, that gas processing takes place out of the unit and that the gas is sold from the unit in a wet condition. That's where the NGLs remain in the gas stream. And then at that point, the gas is valued at the point where it's severed from the unit, both with the dry gas and the NGLs, kind of as a combined stream at that point. It's also, I think, important to note that when we talk about NGLs, we're talking about the propane and butane.

That's different from the condensate that occurs in gas stream. That condensate falls out of the gas during the production process and is sold as oil. So when we think about Point Thompson, that's the process that occurs there where most of— well, where the oil that's produced from Point Thompson is the condensate that falls out from the gas and that's sold as, as oil that's sold separately and again bears its on royalty. Um, just for clarification, uh, we were talking about the term tailgating. I think it's important to note that in the LNG industry, tailgating may also refer to, um, a pricing point for LNG where the LNG is priced after the LNG is transported to its ultimate market and then regasified.

And so the gas that comes out of the regasification facility is sometimes referred to as tailgate gas. It doesn't sound like that's the term that's being referred to here. But for point of clarification, I wanted to raise that as well.

Thank you, Mr. Fitzpatrick. Questions? Senator Wielechowski. Thank you. I just want to make sure I understand this correctly.

So our laws say that the gas would be taxed at the point of production. Is that your understanding? Taxed and royalties assessed?

Uh, Senator Wielekowski, through the chair, uh, yes, as I indicated, typically the, uh, the royalty is accrued at the point of production, the gas or the tax is accrued at the point of production, but depending on the specifics of the tax system or the lease language, point of production may mean different things in those two different contexts. Follow-up, Senator Wielekowski. Well, I guess I'm asking you under the terms of the leases that we have in the state of Alaska, particularly the ones that will be providing gas for this project, predominantly Prudhoe Bay, Point Thompson, Kuparuk. I'm sure there are several others. Do you know the terms of those leases and how they define where the point of production is?

Senator Wielekowski, through the chair. Point of production for the purposes of the leases is when the gas is severed from the lease or unit. So when it leaves the unit boundary at, you know, for instance, Prudhoe or Point Thompson or Kapark, when it's severed from the unit, when it is removed from the unit, that's what's referred to as the point of production for the purposes of leases. And that's the point at where the royalties become due.

Follow-up. So assuming gas is sold to the developer or the pipeline owner for $1.50, is there a scenario that you can envision where the producer of the gas is allowed to say the point of production occurs somewhere else other than when it leaves the unit?

Senator Wieleckowski, through the chair, it becomes a somewhat complicated topic. When we say severed from the lease or units, it doesn't always mean severed from the physical confines of the leases. Remember, the leases themselves are subsurface leases. They don't actually denote a sort of surface interest. And so the surface facilities that are included within the unit facilities are all on separate leases or easements or other rights of occupancy.

And so there are times where unit facilities are located outside of the physical bounds of the subsurface leases. But those unit facilities are always included within the definition of the unit agreements that are executed. Associated with DMR. And so those facilities may not be located physically on the same leases, but they are considered part of the unit. They're unit facilities that are defined within that unit agreement.

And so when they're severed from that sort of unit system of processing and move on to the next step, when they leave those unit facilities, that is the point of production. [FOREIGN LANGUAGE] Further questions? Senator Clayman. Follow-up on the same. I'll try to make this more specific to what we're looking at.

So you've got gas from one of the oil companies that's currently operating on the slope, and they're separating the gas from the oil, and they're sending the gas down the pipeline to a treatment plant, and in the treatment plant they're separating gas from some of the materials and some of those other materials, liquid and other things, get sent back to where they came from, where is the point of production for purposes of either royalties or taxes in that scenario?

Senator Clayman, through the chair. It— again, it's going to depend on whether that processing facility, the hypothetical processing facility that you referenced, is considered a unit facility or not. I believe within the context of the AK LNG project, there's a discussion about gas processing that would be kind of a central processing facility that processed gas from streams from potentially multiple units. That would unlikely to be a unit facility until the point of production would likely be upstream from that facility. But again, until the project gets to a point where, you know, the unit operators submit those plans to the department, I don't want to necessarily prejudge that.

But typically, if you have a single facility that serves multiple units, unless there's, you know, some form of, you facility sharing agreements in place, and there is, I think, at least one instance of that. Typically, those facilities are not considered unit facilities.

Senator, did you have a follow-up? Senator Klimas? Senator Wielechowski?

Speaking for myself, what I would like to see happen is if the price of gas on the North Slope is $1.50, I would like to see a tax based on $1.50 and a royalty based on $1.50. Is there language that you would suggest that we propose to ensure that that's the case, and so that there are no other lease expenditures or other gas treatment plants or, or anything else that could be deducted or cause a netback of less than $1.50? Is there any other language that you would suggest we add to the current tax law?

Senator Wielechowski, through the chair, again, just want to make clear, with the Department of Natural Resources, we deal with administration of royalties through the lease terms. And so I don't want to necessarily speak on tax policy per se. Within the ambit of the royalties that DNR collects, I think there's— I think it's important to keep in mind that many of these issues are already separately addressed within the leases that DNR has let over time. And so I understand there's discussion about kind of the pricing for gas. Many of our leases, well, all of our leases have different different value terms within the lease.

And so those components of value do include the price at which the oil or gas is sold. But depending on the lease, and some of the leases have different value terms, but there are typically comparison prices included in that lease language as well. So for instance, the price that's actually received may also be compared against the prices that other operators receive in the field or in the field or area. It may look at a weighted average that may be referenced to posted prices for oil and gas in the area. So there are kind of comparison terms already built into the lease.

And so if DNR sees a price that would indicate that it's a below market price, there are other higher-up provisions. And that is part of the audit process that the department undertakes. I think you also referenced field costs. Field costs are an issue that are kind of— it's kind of specific to DL-1 leases. Those are the original leases that were issued by the State of Alaska early in the oil and gas development on the North Slope.

They do include leases that are included in many of the larger legacy units. There was litigation that went on for, I think, in excess of 12 years over whether or not it was proper to deduct certain field costs under those DL-1 leases. Those were all resolved, and field costs are now governed by royalty settlement agreements, the settlements that resulted from that litigation. But ever since the DL-1 leases once the state moved to issuing new forms of leases, all of those leases, both within the lease language and within existing statutory framework, require that there is no deduction of field costs for any of the new leases. So the field cost issue is a legacy issue specific to the DL-1 leases.

Follow-up? Would it matter where custody of the gas is transferred to Glenfarm when calculating what the royalties or production taxes are?

Uh, Senator Wieleckowski, through the chair, um, again, speaking only to, uh, to royalties, I'll let the Department of Revenue speak to tax, but the— even if there were a commercial arrangement regarding the transfer of custody of the oil or gas, again, what governs the royalties are the lease terms. And so when the oil or gas is severed from the unit, at that point royalties are due. And so you could have a— you could have a situation where, you know, Glenfarm or any other, you know, potential purchaser of oil or gas doesn't take custody of that oil or gas until, you know, much further down the, down the stream of value. We see that, for instance, you know, in the oil context, in a lot of cases the oil is produced, it's shipped down the pipeline, it's, you know, sometimes sold in Valdez or sold on the West Coast. The, you know, sale sometimes occurs, you know, weeks, sometimes many weeks later.

But the royalty is due at the point where that oil is severed from the units. And so in many cases, the royalty is due sometime before the ultimate sale of that oil and gas. And so it is the severance from the unit that's included in the lease terms that govern when the royalty is due for the gas. Follow-up. I don't know if this is for you, Mr. Fitzpatrick, or for Department of Revenue, but would it be possible for us to get a short synopsis of where under the lease terms that Glenfarm is expected to take gas, the gas is considered to be severed?

Um, Senator Wilkowski, through the chair, certainly we can follow up with something that looks at kind of And I think it may— perhaps it would be helpful to the committee if we looked at kind of the two major forms of leases, the DL-1 leases and the new form leases.

But we can prepare a summary that describes the point of production and where royalties become due during the normal course of oil and gas operations. The department hasn't received sales contracts. For gas yet for the proposed AKLNG project. And so I don't know that we have the information yet to determine where Glenfarn would necessarily take custody of the oil or gas, or of the gas in this particular proposed project. But again, for royalty purposes, where they take custody doesn't matter for where the royalties become due.

The royalties are due from the producer regardless of when the custody of the gas is transferred, whether that's earlier or later from the point of production. But when the gas is severed from the lease or unit, that's when royalty becomes due. Follow-up. Is it possible that, let's say, a gas treatment plant were built at Prudhoe Bay or at Point Thompson, that you could have a company saying that the point of production is after the gas treatment plant so that they would be able to write off the cost of the gas treatment plant against the cost of the production tax or royalty?

Um, Senator Wielekowski, through the chair, um, again, I'll defer questions regarding, uh, production tax to the Department of Revenue. For the purposes of royalty, as I indicated before, it is possible that gas treatment could be something that occurs within the units or could occur outside of the unit. Um, with regard to— if gas treatment were to occur inside the unit, then the gas that leaves that treatment plant would likely be the dry gas with the NGLs and then, you know, anything else kind of stripped out of it. In that case, the gas stream would be valued as dry gas, and then any other NGLs would be accounted for separately. If the— if the gas processing plant were to be located outside of the unit, then the the gas that was sold into the stream.

The gas that was severed from the unit on which royalties would be the wet gas that included those NGL components typically has a higher BTU content, and so it was likely to be, you know, somewhat more valuable.

As far as the cost of the facility, if it's included in the unit, Gas processing is not a cost that's deductible against royalty value. Um, uh, the royalty value is, um, uh, based on the downstream cost, the cost of transportation, the cost of, um, uh, potential things like quality bank, uh, you know, line losses, uh, that sort of thing. Um, but typically not the cost of gas processing when it's included within the unit. As I indicated, the settlement agreements around DL-1 leases do allow for some amount of field costs, but those field costs are on a fixed basis. They're not impacted by additional capital spend.

Follow-up, Senator Wielekowski. So under TAPS, the producers are allowed to write off the transportation costs off their royalties. So I presume the same would be the— would that be the case for the royalties on the gas? Would they be able to write off the cost of the shipping the gas to market down the 800-mile pipeline?

Senator Wielekowski, through the chair, it depends on where the sale has occurred that we're attempting to netback from. So the same thing with, with oil. When oil is sold on the West Coast, the costs of transportation are deducted. And so the cost of marine transportation, it's deducted from the value of oil. The cost of the pipeline transportation is deducted to get back to what the value is at the, the field.

Our understanding of the proposal for this particular project is is that the project developer would be purchasing the gas on the North Slope. So in that instance, any cost of transportation within the North Slope in order to get that gas to the ultimate endpoint would be deductible. And so if you had, let's say, a pipeline between Point Thompson and Prudhoe Bay, that was not considered a unit facility, if it's a publicly regulated pipeline that had a tariff associated with the gas transportation between Point Thompson and Prudhoe, then that tariff would be deductible. But again, if the purchase of the gas, if the transfer, if the sale is on the North Slope, then the cost of transportation isn't— the cost of further transportation isn't deducted. So In that instance, the cost of transportation down the pipeline, the marine transportation to take it to market in, hypothetically, in Asia, would not be deducted against that royalty if it were sold on the slope.

Further questions?

So, Mr. Fitzpatrick, the term that we're hearing Tailgate, you had said earlier, most commonly refers to the gas coming out of an LNG manufacturing process. Is—. Did I understand that correctly?

Um, Chair Giesel, uh, I think the term tailgating can mean different things in different contexts. It typically refers to— essentially, it's the gas at the, the tail end of a processing facility. And so if we think about gas processing on the North Slope, if you have a gas processing facility that's stripping off NGLs, the dry gas at the end of that facility, at the end of that process, the dry gas would be kind of tailgate gas. It would be the gas that's that's coming out after the processing. But again, as I indicated, and I think it's important to keep in mind that, you know, some of these terms mean different things in different contexts, even within the natural gas industry.

Um, tailgating or tailgate gas can also refer to gas that is, uh, at the, the end, the tailgate of an LNG regasification facility. And so the same term, different contexts, wildly different commercial realities when you're talking about tailgate gas on the North Slope versus tailgate gas, you know, in a regasification plant in, you know, Japan or Korea or, you know, somewhere else in Asia. And so yeah, it can mean, you know, those different things. And so, you know, when talking about it, I just When we're using informal terminology like that, I always want to be a little bit careful about, you know, what it means within context and, you know, that it's being used correctly. Thank you for that.

It was a new term of art that was being bantered around, and I wanted to get a definition of it, and you've helped a lot by saying it depends on how the person's using it. And where it's being applied. So, um, so thank you for that. Uh, any further questions for Mr. Fitzpatrick? Seeing none, thank you very much for joining us today.

All right, uh, so back to our main subject today, and that was the Department of Revenue, who will be presenting, um, an updated fiscal note and some analysis of version H of SB 280. So with that, I will invite Mr. Dan Stickel to the table, the chief economist who will guide us through this. Welcome. Thank you, Madam Chair. For the record, Dan Stickel, chief economist with Department of Revenue.

So we have a pretty robust slide deck, but it's a lot of the same material that we've presented in the past, just updated for the most recent committee substitute. Very good. So again, slide 2 is our list of acronyms and definition.

Slide 3, so once again, we will work through the proposed legislation and the revenue impacts of the current CS before the committee. We will discuss our updated estimates of implementation costs. Walk through the detailed project modeling.

So once again, on slide 5, the disclaimer. We're dealing with some very complex topics here. We have one of the most complex oil and gas systems in the world. And all of the analysis here is our preliminary interpretation of our understanding of the bill provisions and how those relate to our spring revenue forecast. And as I'll talk about later on, there's some provisions that will need to be addressed through regulations as we go through the implementation process.

So once again, on slide 6, 3 broad categories of, of changes in the bill: the increased oversight and disclosure requirements for AGDC, as well as related support from Department of Revenue in commercial analysis for AGDC and the legislature, in particular on equity investment decisions, firmer language around prevailing value and receiving fair value for oil and gas, and then changes to taxes related to gas and LNG.

So slide 7 lays out the specific impacts of this version of the bill on Department of Revenue, and then we'll walk through each of these in turn.

Slide 8, note on the revenue impacts. Once again, it's an indeterminate fiscal note, so we can't say with certainty whether the The natural gas project will receive a final investment decision and proceed with or without this bill. And so when we do our fiscal analysis in the fiscal note itself, it's an indeterminate fiscal note and we provide kind of a range of estimates in there. And then when we're doing the detailed analysis in the presentation, we're working on if the project were to proceed under each of these different tax regimes, what would the What would the impacts be there?

So starting with the, the provisions of this bill, so it would impact— it would exempt the AK LNG project from state and local property taxes, and there would be a time frame around that where if the project does not begin construction by 2028 and does not commence operations by 2032, those exemptions would repeal and revert to current law. We do not— once again, we do not include the gas line in our official revenue forecast. So this would be revenue above and beyond the official revenue forecast. And we do mention what those numbers would be: $24 million initially in 2029, ramping up to $244 million in 2033. Those would be the current law property tax revenues just to the state if the project were to proceed without a tax change.

Slide 10 talks about the levy of the Alternative Volumetric Tax. So this would be in lieu of the property tax, and it would begin with the start of commercial operations for each component of the project, so there wouldn't be Wouldn't be any volume threshold or ramp-up period, and the volumetric tax would be 15 cents per 1,000 cubic feet for the treatment plant, 15 cents per 1,000 cubic feet for the pipeline, and then 25 cents per 1,000 cubic feet for the LNG export facility. And then after a decade of operations, those, those rates would be adjusted by inflation.

Go ahead and finish the slide before we take questions. Sure. Yeah. And then the final bullet point here just talks about where that revenue would go. So the state would share about 81% of that revenue with municipalities.

Half of the revenue would be distributed, would be distributed on a per capita basis to communities across the state. And then the other half of the revenue would be distributed to communities that the pipeline runs through directly, with the state retaining the portion of that revenue— the portion of that 50% for the unorganized borough portion of the line. Very good. Questions on this slide? Senator Wilkowski.

Thank you. Out of the 8 operating and 20 FERC-approved LNG export facilities in the United States, how many are taxed on a volumetric basis? Senator Wielechowski, through the chair, I don't know the answer to that question.

Follow-up? For purposes of this bill, how are fugitive emissions, leaks, fuels, and flaring treated in a volumetric property tax scenario? Senator Wielechowski, through the chair, I don't know the answer to that question. I'd be happy to follow up in writing. Follow-up?

The Fed— the inflation rate is expected to be greater than 2%, and I'm just curious what the governor's rationale was in choosing such a low inflationary rate, and what's the rationale for the state municipalities accepting steady and compounding decline in real purchasing power of tax revenues? Senator Wilkowski, through the Chair, I, I can't speak to the rationale of the 1%.

That might be something that AGDC folks will have some insight into, potentially. Follow-up? Any other questions on slide 10? Seeing none, I'll let you proceed. All right, moving on to slide 11, provides some estimates for the revenue from the alternative volumetric tax under the bill as before the committee.

So if the project proceeds, this would be an increase in revenue a little under $10 million in 2029 with first production— that would be just production for in-state consumption— and then ramping up to $620 million of tax revenue once full export operations are ongoing in 2033. And as I mentioned earlier, 81% of that gets shared to municipalities. And so we show the unrestricted general fund portion to the state would be $1.85 million, ramping up to $255 million in 2033, with the remainder of that being distributed to the municipalities. Follow-up, or excuse me, question, Senator Wilkowski. In your model, how much of the production tax and royalty revenue derives from increased liquids production versus gas production?

Senator Wilkowski through the chair. So the answer to that is a— it's a nuanced answer. And the reason for that is that we have a combined severance tax. There's interactions between the oil and gas components of that. In general, the majority of the incremental revenue is from the gas production tax.

And we could provide a detailed breakout of the oil versus gas over the life of the project, again, With that nuance that there is interactions between the two. Follow-up. And can you break out separately the 45Q revenues that accrue to the gas treatment plant? And also, if the state takes gas in kind, would it be eligible for revenues associated with its share of the CO2? Senator Wielechowski, through the chair, yes, we can break out our assumptions around the 45Q tax credits.

And we can provide some further clarification on how that relates to gas in kind.

Other questions on Slide 11? Seeing none, we can go on to Slide 12. All right, Slide 12. So Slide 12, this, this version of the bill has a community impact fee. In version H, the community impact fee would be the $1 million for each mile of gas pipeline installed during the previous calendar year.

As I mentioned in a previous presentation, there is some uncertainty around exactly how that definition of installed would work and how the, the application of the fee would work in the year in which the pipeline construction is completed and gas begins to flow. For modeling purposes, we are assuming that about $739 miles or $739 million of community impact fee would be generated based on the Phase 1 portion of the gas pipeline. Thank you. Senator Myers. Thank you, Madam Chair.

So, Mr. Stickel, This is supposed to go out to grants. First comes the state and goes out as grants. So if not all of the community impact fee is used up in the grants, where would the rest of the money end up? Senator Myers, through the chair, I am not positive on the answer to that question. I would be happy to respond to that in writing.

Okay. Thank you. Any other questions on slide 12? All right, seeing none. All right, slide 13 is the infrastructure maintenance surcharge.

This is a surcharge of 30 cents per barrel of oil produced anywhere in the state, and it's modeled under our existing hazardous release surcharge, which is levied alongside the oil and gas production tax. Credits and deductions cannot offset this surcharge, and the surcharge would be dedicated towards a pipeline corridor maintenance fund, basically the Dalton Highway and related infrastructure.

And we have some revenue estimates for, for that expected to range from about $51 to $62 million annually over the time horizon of the fiscal note, and entirely dependent on our oil production forecasts. So we're, we're having oil production a little under 500,000 barrels per day presently. We're expecting that to increase to well over 600,000 barrels per day in the early 2030s before declining in the later years. The additional liquids production associated with the AKLNG development would add about $4 million of additional infrastructure maintenance surcharge each year. Gotcha.

Senator Dunbar. Thank you, Madam Chair. Thank you for this, uh, Director Stickel. And this is higher than— I think it's a little bit proportionally higher than the estimate in the governor's proposal in 227. And, um, perhaps something has changed since then, but also in SB 227, um, the fiscal note did not estimate that DOR required any additional staff to administer the surcharge.

Is that still the position of the department? Yeah, Senator Dunbar, through the chair, so we are not requesting additional resources for the surcharge aside from one-time programming costs to implement it in our tax system. Very good. Thank you, Madam Chair. Further questions on slide 13?

Yeah, Senator Rauscher. Thank you, Madam Chair. So bullet number 4 establishes a pipeline corridor maintenance fund in the general fund. However, it doesn't create a dedicated fund. Just, just can you explain that for us?

Sure, Senator Rauscher, through the chair. So, um, there's several of these provisions in, in state statute. So the state constitution prohibits a dedicated, uh, a dedicated fund. So typically the way that this has worked around is there's what's known as a designated fund where there's language in the budget that, in the budget and statutes that the legislature may appropriate for a specific purpose. We have several of these for various, so for our existing hazardous release surcharge, that may be appropriated for spill and hazardous release prevention and response purposes.

We have several other shared taxes. For instance, we share a portion of fisheries taxes back with municipalities. And so it's kind of modeled on that same language where the legislative intent is there, but we're not mandating that dedication or binding the hands of a future legislature. Thank you. Very good.

I don't see any other questions on this slide, so on to 14. Alright, and slide 14 is the pass-through entity tax. So, uh, so we've mentioned previously, under current law, only C corporations doing business in the state are subject to corporate income tax. Uh, in the oil and gas industry, that's about two-thirds of the oil and gas companies doing business in the state. And our modeling assumes that the midstream entity developing the AK LNG project would not be subject corporate income tax either.

And so this, this provision of the bill would create a pass-through entity tax to tax that— all of those remaining oil and gas companies that are not currently subject to corporate tax, at beginning at a rate of 5% of taxable income between $1 and $2 million, and then ranging up to 9.4% taxable income over $5 million, which is the current maximum marginal tax rate for corporate income tax in the state.

Senator Myers. Thank you, Madam Chair. So, Mr. Stickel, I've heard some speculation over the last few weeks that as the developer of the project, Glenfarn is likely going to have to register as a C corp in in order to get access to all the capital markets that they're going to need access to in order to build the project. Do you have any, um, any insight on that? Uh, Senator Myers, through the chair, I don't have any specific insight as to their, their plans.

I would defer those to the developer. If they were to transfer into a C-Corp, then they would become subject to our oil and gas Well, to our corporate income taxes generally, like any other C-Corp. Follow-up, Senator Myers? Yeah, I wasn't asking you to opine on what their plans are. I know you can't do that, but just looking at the oil and gas market and the size of the project that they're looking at, whether that appears to be more or less likely, I guess.

Senator Myers, through the chair, so I would That's not really my area of expertise. That might be a good question for the legislative consultants. I know we do have some large oil and gas corporations that are not C corporations, and, you know, they are able to invest major sums of money into the state, into major projects. So I can't say with certainty whether that would be a tremendous benefit to them or not. To change to a C-Corp.

Okay. Any other questions? All right, seeing none, slide 15.

So continuing on, on the pass-through entity tax, as I've mentioned previously, for the oil and gas pass-through entity tax generally, before the AK LNG project, we've developed a range of up to $100 million per year for that tax type. The high end of that range, the $100 million, is based on taking our existing forecast for corporate income tax for the companies that are subject to that tax and basically scaling that based on expected production. The low end of the range is a reflection of the fact that in any given year, a company may have losses for whatever reason. They could have lost carryforwards. There could be a low price, a low price scenario, some major investments.

And given the concentration of this pass-through entity tax on a small number of companies, there is a potential that in any given year the pass-through entity tax could yield close to zero revenue. And over a broad time horizon, we think that the annual revenue would fall within that $0 to $100 million per year range. With the AKLNG project, there would be incremental revenue. And so we're— from the incremental production associated with the project for companies that would be subject to the pass-through entity tax on the upstream as well as the revenue expected on the midstream. And we are assuming about $60 million annually as the incremental revenue in the late 2030s, and then that increases substantially into the 2040s in our modeling.

So slide 15. Senator Dunbar, question? Yeah, um, more comment, Madam Chair. I will just say very quickly, the way that this slide relates to slides 30 and 31, I sort of don't want the public to get the wrong understanding that $60 million in 2030s, but in the years out— and we've had this conversation before— in the 2040s and 2050s, we're looking at the hundreds of millions of dollars. And I believe at one point Mr. Stickel had said $466 million was the number in the incremental change.

And so very large numbers after the 2040s. That's all my—. Thank you, Senator Dunbar. We'll be getting to those slides, of course, later. Any further questions on slide 15?

Seeing none. All right, slide 16. So utility rate provisions. This is a new slide that we, that we added for this version of the, of the, of the slide deck. So this version prohibits the recovery of cost overruns being passed on to Alaskans' utility rates and also limits the gas purchase price charged to utilities.

So that, that limit would be $12 per 1,000 cubic feet after pipeline completion and before LNG delivery operations. And then $5 per thousand cubic feet after LNG export facility operations begin. And as I presented in a previous hearing, the— these would represent the maximum charges to utilities for the cost of gas, and you add on a little over $4 to get the final delivered cost to the, to the end consumer. Would note that this $12 and $5 would not be inflation adjusted, so going to the end of our model time horizon, it would still be a $12 or $5 per 1,000 cubic feet ceiling. Very good.

I'll just comment that the company itself, Glenfarm, has indicated that they would not be pushing the over— any cost overruns onto the rates paid by Alaska Utilities. And the governor had quoted the $5 and $12, so we simply put it into the bill. Any other comments, Senator Wielekowski? Just on the language in this, in the statute as it's currently written about cost overruns, do you have any suggestions for us about how we might write that so that there's no dispute you later on about what the initial estimated cost would be. Should we just put in $46.2 billion, which is what the cost estimate we're all working under?

Sure, Senator Wielechowski, through the chair. So I'd have to think on that and consult with the team and get back to the committee on suggested language. Thank you. That would be helpful. Thank you.

Any other questions? All right, moving on then to slide 17, I think. All right, so slide 17. So this provision would make some changes to how oil and gas is valued. So currently we may require tax to be paid on oil or gas that's sold at no cost or below prevailing value.

This bill would change that to a shall. We don't believe that this would have a material impact on state revenue. There are some limited situations where there's a de minimis amount of oil or gas that is sold at a de minimis value, and it's really not worth it for us to go after a company for that de minimis amount of tax revenue. Under this language, we would be required to make sure that we get the full value of oil and gas for any oil and gas sold. And then add some language around how oil and gas must be based on a fair market value for production tax purposes.

This version of the bill allows us to publish some aggregated information related to prevailing value and valuation of oil and gas. There was a previous version of the bill that required us to publish some detailed information. So the language in this current version would be much easier for us to work through and and administer.

Senator Wilkowski. We heard from DNR about where the point of production would be, and I'm curious what your perspective is. You heard the testimony from Department of Revenue. Where, where will the wellhead or point of production be for the producers in this project? Sure, Senator Wilkowski, through the chair.

So I was listening to To that back and forth, uh, that ends up being a fairly technical explanation. So I can respond in general terms from the perspective of an economist. If we would like, you know, some more technical explanation, I'd be happy to get back to the committee with that. In general, for tax purposes, the point of production is at the lease boundary. In our modeling, we assume that the transfer of the gas into the AKLNG project would be at the inlet to the gas treatment plant, or in the case— or in the pipeline in a Phase 1 case.

For Point Thompson gas, we assume that the value— the point of production would be at the lease boundary, and then there would be a feeder pipeline from the Point Thompson field to the gas treatment plant, which would be located at Prudhoe Bay.

And as a general comment, we will need to develop regulations around the AK LNG project generally if this project goes forward. And so this is one of the, one of the points that we may put a finer point on through the regulatory process. Follow-up, Senator Wilkowski. Are we correct in assuming that this is an important issue that we should be trying to discuss, or is this something that you think the regulatory process should work out? And let me just tell you where my, my big concern is, is that the point of production is somehow occurring after the gas treatment plant, and that there's— that's going to be an enormously expensive project, and, and the state value would be diminished tremendously.

Sure, Senator Bullockowski, through the chair. So I think generally allowing the department some flexibility with the, the regulations is helpful. That will allow us to, to adapt to any future unforeseen changes in the process. The question of where— of, of the —gas treatment plant and if that is before or after the point of production. That's a good question.

Um, so our understanding of the current project is that, uh, the gas treatment plant would be wholly owned by the midstream developer and the sale of gas would take place prior to that. In concept, you could have processing take place on the lease, uh, before the sale of gas. If that were the case, presumably there would be a higher upstream cost and a higher sales price because the developer would then be— rather than buying unprocessed gas and paying for the processing, they would be buying processed gas and presumably paying a higher price for that. Follow-up.

I can certainly understand the desire to do this through the regulatory process. One concern I have is that we didn't define royalties in TAPS and where that, uh, the cost for that. And we went through decades of litigation that probably cost the state tens of billions of dollars. Is that an accurate statement? Senator Wilkowski, through the chair, um, not qualified to opine on the on the cost of that.

Follow-up. So I guess, uh, I would— my preference would be to make this determination now because, um, I think it's better for us to make the decision an informed decision, a rational decision, uh, so that there is a clear understanding for all the parties and so that we don't have to go through years of litigation and years of— that can potentially cost the state hundreds of millions of dollars, if not billions of dollars. That just seems preferable to me. So I guess I'm asking you, is there in the department, in protecting the state's interests and our fiduciary obligations to maximize the value, is there language— because we've never had major gas sales off the North Slope, and this is a new frontier. Is there language that you, the department, can come up with to protect the state's interests?

What my intent is that, like I said to DNR, if gas is selling for $1.50, we get $1.50 worth of royalties and production taxes, and that there's minimal expenses, and that there's no way that the system can be gamed so that it's processed, that the value is calculated after the gas treatment plant, or somehow after the pipeline, or somehow there's tremendous netbacks that are allowed. That, that's my intent in this whole process. And is there language that the department can come up with so that we can avoid potential litigation over this subject? Uh, sure, Senator Wielekowski, through the chair. So I will add that to our list of follow-ups and, uh, touch base with our in-house experts and see what we can do.

Senator Kawasaki, thanks.

Yeah, I got a question on the first bullet. You mentioned that the change from may to shall, and then you gave some examples. Can you run that through me again? Because I'm not quite understanding why we were not requiring payment on those sales. Sure, Senator Wilkowski.

Senator Kawasaki through the chair. I'm sorry.

So currently we do have— this bill would add the requirement that we shall, if oil or gas is sold at no cost or below the prevailing value, we shall require that tax be paid on the prevailing value of that oil or gas. Under current law, we have similar language, but a may language around that. And so I went back to our production tax experts that administer the tax on a daily basis and kind of asked them, you know, what's going on with this may language? How does that work in practice? And the examples that they gave is, as a general rule, yes, we require that tax be paid on prevailing value.

We have a higher of calculation where typically for oil and gas, the companies will pay their tax based on the higher of their actual sales price or our deemed prevailing value for that oil and gas. There are some limited instances where there's a de minimis amount of oil or gas being sold, that they'll invoke that "may" provision. So if we go in and, you know, we're going through an audit and we see a sale where there's $100 left on the table, it may not be worth the administrative process to go through the audit and all of the follow-up to collect that $100. $100, And that's where the May will be— will come in under current practice. Thank you.

Very good. Just an aside, Mr. Sickel, I don't know if you've ever run cross country, but there's roots on the trails, and if you've tripped on a root, every time you approach that root, you'll trip on it again if you don't focus. And so this is what I— because I mix these two up also, so I've tried to With my brain saying, no, no, this is the one. They are— anyway, it's like tripping on a root on a cross-country trail. Senator Wilkowski.

Got it. Okay. Okay. So if Glenfarn is taking custody of the gas at the inlet of the gas treatment plant, does that mean the state will be receiving royalty and production tax for the gas that is purchased by Glenfarn and used as fuel in the project? Senator Wilkowski, through the chair, that's our assumption, yes.

Does there need to be a statutory change to ensure that?

Senator Wielechowski, through the chair, I'd be happy to get back with a certain answer on that. I believe the intent is clear, but we will add that to the list of questions we're going to bring to our tax experts internally. If custody of the gas is transferred at the inlet of the gas treatment plant, as you suggested, how will that affect the state's decision to take gas in value or in kind?

Senator Wielechowski, through the chair, that— so there's two— Under current law, so the value versus in-kind is a royalty provision decision that's based by Department of Natural Resources. So I would defer that question to them. There's a subsequent election for a tax in-kind election. That tax in-kind election is at the producer's option if Department of Natural Resources elects to take royalty in kind. So that's really not a tax division question.

Follow-up. If custody is transferred, is it Glenfarn that in-state customers are negotiating with for access to gas? Senator Bullockowski, through the chair, that's the assumption in our modeling, yes.

Follow-up. With buyers, are they taking LNG at the dock, or is Glenfarn maintaining custody of the LNG through the market? Senator Wilkowski, through the Chair. So I do defer the detailed project planning discussions to the developer or AGDC. The way that we have modeled is that the— that Glenfarm is purchasing the gas at the inlet to the gas treatment plant, and then they are paying the entire cost of the midstream earning a rate of return and then delivering the cost into the global— or delivering the gas into the global market at whatever price the market will bear.

And so the way that we are modeling the project is that the midstream operator has custody of the gas from the gas treatment plant to the sale to a utility customer overseas or in Alaska.

Any other questions on slide 17? All right, seeing none, moving on to 18. All right, slide 18. So this is the requirement to assist with state investment decisions. This is similar from the, the prior version of the bill.

So AGDC is required to negotiate state purchase of options relating to the gas pipeline, and this bill requires DOR to support, to support them in that process and to assist the legislature in determining whether to take an ownership interest in the project.

Senator Myers. Yeah, thank you, Madam Chair. So, Mr. Stickel, you've told us that effectively you're going to hire somebody new because you don't do this right now. Is there an agency that is better set up to do this than you? DNR or somebody else?

Senator Myers, through the chair, so Department of Natural Resources has a commercial section. They do similar types of analysis around state best interest findings, royalty relief, things like that. What we envision is a We are developing a commercial capacity in Department of Revenue. We envision a similar sort of analysis and capacity. Within Department of Revenue, we do have significant investment expertise.

So we have the Treasury Division and then the Permanent Fund Corporation are within Department of Revenue. So it's kind of a nexus of those of those two functions. Okay, thank you. Senator Wilkowski. Do you have any assumptions or knowledge about how the project treats expansion costs for new gas beyond the initial contracted volumes?

Senator Wilkowski, through the chair, we have not modeled in a project expansion as far as how that would, that would work for the current iteration of the project, I defer that to AGDC. We have the ability to model project expansions.

Senator Rosier. Thank you, Madam Chair. So bullet number 2, where it says determining whether to acquire an interest, I will just start from the beginning. The DOR is required to cooperate and assist the legislature in determining whether to acquire an interest, including identifying potential funding sources, political, uh, potential fiscal effects on the state. Is this— we're talking about exercising our equity share here, or what else are we talking about here?

Uh, Senator Rauscher, through the chair, correct, yes. So exercising the equity share, and then the bill adds requirements that AGDC negotiate equity options into any future contracts it negotiates. Follow-up. Follow-up. And is that the limit there or are there other things?

I'm trying to understand what the sentence says. Sure. Senator Rauscher to the Chair. So there is a significant portion of this bill deals with AGDC and different oversight provisions around AGDC. This requirement is kind of one narrow piece of one of those AGDC oversight provisions where Department of Revenue is directed to cooperate with the legislature in evaluating whether to exercise any option to take an ownership in the project.

Okay, thank you.

Mr. Sickel, I have a question that focuses on, again, the point of production. I'm kind of going back to that, related to the Point Thompson unit. So, so this is a complex reservoir. It has condensates in it that come up with the gas as the pressure— my understanding You can correct me, and we're going to have AO GCC, by the way, on Wednesday come and speak about this. But it's my understanding that as the pressure is reduced and the gas is coming up, the condensates fall out, which I believe is the propane and butane elements.

So there's dry gas and then there's the condensates. Is there a treatment facility— I'm calling it a treatment facility— that would capture these two streams on Point Thompson that then could be construed as a gas treatment facility still on the lease? Do you know how that works?

Sure, Chair Giesel. So I think the question is, is there— some technical potential loophole here?

Possibly, that's what I'm asking. I guess, um, what is the point of production on the Point Thompson Unit for gas? Is it after some kind of a facility that captures the condensates and allows the gas to then go off the lease, which is where, uh, the taxation or the transfer of ownership would happen, right? I guess that's what I'm wondering. Do you know technically how that works?

Chair Giesel, so I can speak for oil purposes. So presently there's oil and gas coming out of the ground. The condensates are being shipped into an oil sales pipeline over to Pump Station 1. That pipeline pays a tariff and the point of production is at the lease boundary at Point Thompson. Our assumption is that for gas sales— so the gas is currently being reinjected into the field.

Our assumption is that for the AKLNG project, it would be a similar definition where the point of production would be at the lease boundary. There would be a gas— basically, a feeder pipeline transmission line from Point Thompson to the gas treatment facility over at Prudhoe Bay and a tariff associated with that pipeline.

Very good. Thank you.

Thank you. All right, any other questions on slide 18? Seeing none, moving on to— Yes, Senator Kawasaki. Thank you. Let me get back to 18.

Under 18, one of the changes in the H version of the bill had to do to do with stating AGDC is a fiduciary. Did that have any material impact to the cost of the bill?

Senator Kawasaki, through the chair, not from a Department of Revenue standpoint. Okay. I would defer, you know, if that changed AGDC's fiscal note, I would defer that to AGDC. Thank you. Any other questions on 18?

All right, seeing none, we can move on to 19. All right, so slide 19 is our implementation costs. Um, so our staffing plan on slide 20. So for this version of the bill, we're requesting 4 positions, which is a pretty large reduction from the 11 in the earlier version of the bill. So we're requesting a corporate income tax auditor to administer the new Tax on pass-through entities.

We're requesting a tax auditor to administer the alternative volumetric tax and the community impact fee. We're including one oil and gas revenue auditor to administer the increased valuation requirements for oil and gas and generally our increased audit requirements associated with major gas sales. So having major gas sales is going to add significant workload regardless of which version of the bill is passed. And then we're requesting a commercial analyst in our research group to assist with the project ownership decisions and commercial analysis that we talked about earlier, and then generally the increased analytical requirements associated with with major gas sales. Madam Chair.

Senator Dunbar. Thank you, Madam Chair. For this slide and the next slide, I appreciate that you mentioned we went from 11 to 4 from the previous version of the bill. Could you also describe the difference between the governor's introduced version? I think there were 3 positions there, so this is one more position than the governor's, but I could be misremembering.

So how does this staffing plan compare in in terms of number of people to the governor's introduced bill? Senator Dunbar, through the chair. So I think in the governor's introduced bill, and I don't have the fiscal note in front of me, I think we just had the one position for administering the alternative volumetric tax. Follow-up, Senator Dunbar. Follow-up, Senator Dunbar.

Why wouldn't the commercial analyst be necessary under the governor's version? Sure. Senator Dunbar, through the chair. Through the Chair, so one of the significant additional analytical duties is what we're envisioning for this requirement to assist with project ownership decisions and equity stake decisions. So we envision a robust analysis to really try to address the intent of that provision to provide detailed analysis and recommendations to the legislature.

Follow-up? No, it's all right, Madam Chair. All right, further questions on this slide? Seeing none, slide 21. Slide 21 is our capital request.

So we're requesting a total of $1 million to upgrade our tax revenue management system on a short timeframe. This would be for implementing the alternative the alternative volumetric tax, the community impact fee, and importantly, the pass-through entity tax. Those would be 3 new tax types in our system. And then $250,000 is an estimate for assistance with the state ownership decision-making process to bring in outside expertise, to bring that global perspective and support our internal workload.

Very good. Senator Dunbar. Thank you, Madam Chair. Just to reiterate, which of these— do we also have to do that, the project ownership options under the governor's introduced version? Can you remind me what the capital request was for the governor's introduced version?

Senator Dunbar, through the chair, so that language was not in the governor's introduced version. That was added in the committee substitute. Some increased provisions around AGDC oversight and disclosure and then bringing DOR to help support those state investment decisions directly to the legislature. Follow-up, Madam Chair? Follow-up.

And the other versions here, the million dollars, so you need to do something to do the AVT under the Governor's version, correct? Senator Dunbar, that's correct. That is correct, and I don't have that exact number. I don't have the, the introduced fiscal note in front of me. This is a larger request than in the version as introduced.

There was a request in the governor's introduced version in addition to the alternative volumetric tax. This bill adds the community impact fee and then the pass-through entity tax, which is a significant new tax type. Very good. Thank you, Madam Chair. I see no further questions.

Slide 22. All right, slide 22 is the snip from the fiscal note, um, with these annual numbers. So a little over $800,000 per year for the person— for the additional staff, and then a total of $1.25 million for the capital appropriation request. See no questions. And moving on to the detailed project modeling, slide 24 is a reiteration of our base— our baseline model assumptions.

So we're modeling 30 years of full export projects, 32 years from first LNG sales. We're assuming a— in real 2026 dollars, a construction cost of $46.2 billion for the a LNG project. We're assuming a 10% pretax return on investment over a 20-year time period for the project developer. We're assuming a $1.50 per thousand cubic feet purchase price for the gas from the upstream into the midstream. We're assuming that production starting in 2029 will be from some field on the North Slope yet to to be determined that requires gas treatment.

And then the anchor for the project beginning with exports in 2031 would be a combination of Prudhoe Bay and Point Thompson Gas, assuming no oil production impacts at Prudhoe Bay on net, and then assuming a total of 270 million barrels of additional liquids production from Point Thomson over life of project. And those are the same basic assumptions that we've used for our modeling for previous versions. Very good. Questions? Yeah.

Senator Rupture. Thank you, Madam Chair. So I was just wondering, in bullet— what is it? 1, 2, 3, 4, 5, And 6. So have you modeled the liquid loss at the level reported by BP back in 2015, because they did a study at the end— that time it was 300 million barrels of oil loss.

And that's because when you blow down the gas cap, you get liquid loss you can't recover. So have you taken that into consideration in your modeling? Because I noticed your numbers might not be reflecting that, and that's an —Prudhoe Bay area. Sure, Senator Rausch, through the chair. So we worked with AGDC on that liquid losses assumption for Prudhoe Bay and actually used that BP information as kind of the basis for the assumption.

The thought was that since we're now another decade-plus further along in field life, that any potential liquid losses would be much lower than that. And so they felt comfortable with a zero liquid losses assumption. That makes the modeling very straightforward. We certainly have the ability to run scenarios on that. Follow-up, Senator Rusher?

Yeah, but I don't know how to phrase it, so I'll pass. Thank you. And that actually is going to be a topic that we discuss at length with AO GCC on Wednesday. That would be good. Because I have concern about Point Thompson and the loss of liquids there.

Did I see your hand, Senator Bullockowski? Oh, just same concerns, because I've heard— I heard it was actually 400 million barrels, but maybe it's 300. But do you know, has AO GCC done any recent modeling? Because I don't know that zero is correct, and I think that would be important for us to understand. Sure.

Senator Bullockowski is the chair. So I don't know if AOGCC has done the modeling. We certainly— we've set up our modeling to run scenarios where we look at, you know, what is the impact if oil production declines at Prudhoe Bay are different from zero. So if oil were to decline faster than in our official revenue forecast, what would that mean? We haven't prepared that in our base set of slides for the committee, but we are certainly happy to run scenarios on that.

Follow-up? I guess I'm not so interested in scenarios. I'm interested in what the reservoir engineers are suggesting the actual losses might be. Maybe they are zero, but do you know if DNR has done any analysis or if AOGCC has done any analysis or anybody has done any analysis that you have— that probably DNR should have access to as the as the department responsible for managing our resource. Uh, Senator Wilkowski, through the chair, so I'm aware of some preliminary analysis that's taken place.

I don't know, I would defer that to the agencies on if they're ready to release any of that. Um, the, the field operator obviously would also be a great source of information. Senator Wilkowski, Ryan Fitzpatrick, Commercial Manager, Division of Oil and Gas, is online if you would like to ask that question. Sure. Mr. Fitzpatrick, would you please join us again?

And did you hear Senator Wielechowski's question just now?

Is he still online?

He's— Mr. Fitzpatrick, Make sure you're unmuted if you're talking.

Apologies, is that better? That's much better, thank you. Okay, thank you. I did have my phone on mute. Thank you, apologies for that.

For the record, Ryan Fitzpatrick, commercial manager, Alaska Department of Natural Resources. And yes, Senator Wielekowski, through the chair, I know that that is something that the department has looked at in the past. I don't know that we have a definitive viewpoint as to liquid loss. Obviously, I think depending on the timing of major gas sales out of Prudhoe Bay, it is something that the department has looked at previously. I can follow up with the committee and see what the most recent information we have on that is it is a very technically involved calculation.

And so that is something that the perspective of the field operator, I think, would be very useful as well. Follow-up, Senator Wielekowski. Yeah, and I have a document that I, I don't know if this is accurate or not, but it, it talks about potentially reduction in Prudhoe Bay oil production by 452 million barrels if initiated in 2029. Is that a number that you're familiar with?

Uh, Senator Wielekowski, through the chair, I'm not familiar with the document that you referenced. Um, uh, typically I think it would be, um, other personnel within the department that would look at these, these sorts of issues specifically. We have a resource evaluation section within our division that is principally geologists and petroleum engineers, and so they may be familiar with that document. But like I said, I can follow up internally and follow up with the committee on what our most recent information is. That would be really helpful, Mr. Fitzpatrick.

Thank you. Any questions additionally for Mr. Fitzpatrick? All right, seeing none, thank you very much for joining in for that answer. All right, so any other questions on slide 24? Seeing none, um, I'm evaluating here.

Because we're about 5 minutes out, so perhaps this would be a good stopping point. And would you be able to join us tomorrow, Mr. Stickle? Absolutely. Very good. We meet at 9:00 a.m. tomorrow morning.

All right, just checking. I didn't know if you were a morning person or not. Um, thank you.

You know, I know the public listens to these meetings often I'm pleased that they do. This is, I hope, evident to them that this is very complex. And while we have named AGDC in this bill as having fiduciary responsibility, we ourselves do to the people of Alaska to make sure that we get the maximum value for the— for our resources and that we don't relinquish our taxation authority. So this is taking time. We are going to be meeting twice daily for the rest of this week, so 9 AM and 3:30 every day, in an effort to meet the governor's expectation of getting a, a reasonable and responsible bill to him.

But we're not going to do that at the risk to Alaskans for passing bad legislation. So it's a, it's a, it's a high bar we're trying to meet. So at this time, we'll set this bill aside. Our meeting will be tomorrow morning at 9:00 AM. We're going to hear this bill again, supporting a gas line for Alaskans.

And Mr. Sickel, just so you know, we do have two House bills we're going to hear very quickly at the beginning of the meeting. That's House Bill HB 79, naming Vic Fisher Soup Bay Marine Park, and HB 93, resident requirement hunting, fishing, trapping. So those hopefully won't take too long and then we'll get on with this. So at this time the meeting will stand adjourned. Let the record reflect the time is 4:55 PM.