SRES-260513-1530

I call Senate Resources Committee meeting to order. Today is Wednesday, May 13th, 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 am Senator Giesel. We have a quorum to conduct business.

Thank you again to Heather, who is keeping the record of this meeting, which is essentially a legal document, by the way. And thank you to Doug, who's keeping the audio running for us. Today we're hearing Senate Bill 280. Supporting a Gas Line for Alaskans Act. This is hearing number 29 of this piece of legislation.

We have a new version before us. It's version W. This morning we adopted two amendments. These can be found in version W on page 8, line 20— begins on line 20 through 28.

And the second amendment can be found incorporated on page 31, beginning on line 28 and going on to the next page.

So these have been incorporated into the bill, and so we have a new working document. Senator Wilkowski. Madam Chair, I move to adopt CS for Senate Bill 280 version 3-4 backslash GS-2038 backslash W, as in Wainwright, as our working document. And I'll object for purposes of discussion. Basically, I've already told you what the changes were, so I guess we don't need to discuss it further.

I'll remove my objection, and version W is now before the committee as our working document. So today we have scheduled a presentation or a discussion with the Alaska Oil and Gas Conservation Commission They are online with us. Uh, there are 3 commissioners. Commissioner Jesse Chimilowski is the petroleum engineer. Greg Wilson is the geologist.

Tom McKay is the public member. Joining them, I see on my agenda anyway, that Dave Robie is with them, petroleum engineer, senior petroleum engineer, and Samantha Calderon, special assistant. So, um, AOGCC members, can you hear us?

Yes, we can, Madam Chair. Isil, how are you today? Very good. We had posed to you some questions related to the complexity of extracting the gas from Point Thompson, and so we were hoping you could review for us the technology that's required, the complexity. As well as what you would speculate would be the loss of condensate that could be removed with the blowdown of the gas at Point Thompson.

So I'll turn it over to you to present.

Yes, thank you, Madam Chair. Giselle, can you hear me okay? Yes, we can hear you just fine. Okay, this is Commissioner McKay, and can you see our slides? Uh, not yet.

Not seeing slides. Okay, we're working on that. Um, we did put together a presentation that responds to your questions today, and, uh, can you see our slides now, Madam Chair? Yes, we can see the slides now. Okay, very well.

Um, I'm going to turn it over. This is Tom McKay. I'll turn it over to Commissioner Wilson and Commissioner Kamloski to go through these slides for you, and we hope that they are satisfactory in answering all your questions. So with that, Commissioner Wilson, we'll have additional questions for you, I'm sure. Yeah, yeah, this will more or less frame the discussion, and I will talk through the slides, but I won't be shy at all at quickly turning to Dave Robie if there's more technical questions.

A retrograde gas condensate field such as Point Thompson is a very complex field to develop and requires a special expertise. So with that, we'll start walking through the slides. First, I know you're familiar with where Point Thompson is, but put in a location map. Point Thompson, 60 miles east of Prudhoe Bay. The operations today include facilities to support the gas cycling, very critical in a retrograde— with a retrograde condensate to maintain the reservoir pressure.

If you don't maintain reservoir pressure, you will drop out the liquids in the reservoir and in all likelihood they will never be recoverable. And not only that, but there's additional complications to produce the gas in that situation then too.

There were early expectations that the field would produce in this cycling project around 10,000 barrels of condensate. Per day, but the current production rate right now is about 4,000 barrels of condensate per day. Before you go on, at the end of each slide, would you please pause for questions? And I'm going to ask you to explain more the term gas cycling. The reason for this is the public is listening to these meetings.

There's huge interest in this gas pipeline project, and so I'd like the public to understand more in depth what is gas cycling. So the reason you would do gas cycling is to harvest the condensate from the reservoir. Uh, the cycling— you're bringing the gas to the surface, uh, harvesting the condensate from the gas, and then, uh, putting energy back into the ground to maintain the reservoir pressure and you send the gas back into the, the reservoir. The whole time, the whole point is to maintain the pressure as near as possible to the original pressure of the field so that you don't drop condensate out in the reservoir itself. That would be liquids coming out of the gas in the reservoir, in the pore space of the reservoir.

That's a great explanation. Why is this challenging. I'll give you a hint. Could you talk a little bit about the amount of pressure that exists in this reservoir? Certainly.

This is the highest pressure reservoir on the North Slope, and it even compares favorably on the high pressure category worldwide at about 10,000 pounds per square inch. By comparison, Prudhoe is about— Prudhoe Bay is about 5,000— about 5,000 pounds per square inch of pressure. And so you're dealing with extremely high pressures. And in order to do a gas cycling project with a reservoir that has extremely high pressures, it takes a lot of compression at the surface. And so it's an expensive thing to do.

It's a complicated thing to do to maintain that pressure. But it's critical in that you maintain that pressure and not drop out the liquids in the reservoir rather than when you bring that gas to the surface and then harvest the liquids. Very good. Could you clarify who's speaking? Again, we have a secretary who's keeping record and we need to know who's speaking each time.

This is Commissioner Greg Wilson, and I will be— in general, I will be speaking to each of the slides. Uh, but like I said, I, and I will make it known when I would want to turn the expertise over to Dave Robie or one of the other commissioners. Very good. Thank you, Commissioner Wilson. Any other questions on slide 1, or actually slide 2, I guess, the title page?

All right, I'm not seeing any other questions. I'll let you move on.

So this slide 3 is a slide that was prepared by Hill Corp. And it is a Point Thomson structure map. And so the lines that you're seeing on that map, you can think of them much as you would a topographic map, except that it's of a surface in the subsurface, mapped from well data and seismic data. And so it shows the highs and the low points within the reservoir. To the northeast on that map, the reservoir is truncated to the southwest along the line that runs northwest-southeast. The reservoir pinches out.

And then, like I said, there are highs and lows within the reservoir. Also shown on this map are the active wells. There's a number of wells that have been drilled to delineate the field over the years, you know, discovered in 1977. A number of wells that have been drilled. But the active wells right now are Point Thompson 15, 16, and 17.

And then there's a well right now under completion, which is Point Thompson 19. And so Point Thompson 15 and 16 are injectors. They would be the wells sending gas back to the reservoir under extreme pressure. And Point Thompson 17 is the well that's actually producing the gas right now. Stripping out the condensate at the surface and then, you know, going to 15 and 16 to be reinjected.

Very good. Any questions, committee members? Yes, Senator Kawasaki has a question. Thank you, and thanks for being online. So directly under Point Thompson PTU 17, if there's like another colored portion surrounded by green, it looks like.

Is that area that has been discovered there just— is it not part of that unit? It looks like it's not necessarily connecting. And how would you describe that?

I am, through the chair, Senator Kawasaki, I am going to take a stab here, and maybe Dave Roby will correct me, but I think that might be denoting the oil rim near the bottom of the reservoir. Is that correct? This is Dave Roby. Yeah, the green line around the reservoir is the oil rim. The pinkish color is where the gas is.

The reason there's a gap between the large blob to the north and the smaller blob to the south, I believe, is because there's a cemented rock in the, in the reservoir area that doesn't allow oil or gas to flow through it. Okay. Any other questions, committee members? All right, seeing none, thank you. You can move on to the next slide.

So we wanted to put in the approach of the ALGCC. It's a conservation-minded path to maximizing recovery, and so kind of a mission statement here for the AOGCC. It's to protect the public interest in exploration and development of Alaska's valuable oil, gas, and geothermal resources through the application of conservation practices designed to emphasize and ensure greater ultimate recovery and the protection of health, safety, fresh groundwaters, and the rights of all owners to recover their share of the resource. So those are kind of our guiding principles here at the AOGCC. But important in today's discussion is ensuring that greater ultimate recovery.

Great, thank you for that. Senator Kawasaki has a question. Thanks, and this is for the commissioners. Um, when you read that, does it— it doesn't delineate whether you're trying to produce gas or produce oil. Obviously, from the tax side and from the revenue side here at the legislative side, the oil is valued much more than the gas, and so How do you reconcile the two?

Senator Kawasaki, through the Chair, what I would say is that the AOGCC, in large part, we don't reconcile the two. We look at the overall ultimate recovery, but you won't find mention of economics or the value of a barrel of oil versus the value of of a standard cubic feet of gas in our regulations or in how we regulate the industry. That is for the legislature and others to debate and the DNR. Follow-up, Senator Kawasaki. Thank you.

So if you're using gas to pressurize a well to enhance oil recovery, under those circumstances, do you— and then we say we would like to use some of that natural gas that's being reinjected to pressurize a unit. I guess, how do you make that decision about whether pressurizing the unit and using the gas to pressurize a unit is more important because we're producing oil? Uh, there is that somewhere in statute.

Uh, Senator Kawasaki, through the chair, I can't think offhand of where it would be in statute, you know, again, I'll come back to ensuring the greater ultimate recovery in how the resource is used. I'm thinking— looking for a lifeline here if there's help in the room. You're trying to maximize both oil and gas.

Yeah, and you'll see as we go through the slides here that we'll start defining some of the resource in terms of barrels of oil oil equivalence, and, and we will show, you know, what that equivalence is. And that is how we would gauge the, the greater ultimate recovery in terms of barrels of oil equivalence. And so the gas can be looked at in terms of barrels, barrels of oil equivalence, and that's getting a little bit ahead on the slides, but you will see that helps us make that determination if we're getting the greater ultimate recovery. Now, there's other aspects to be considered too in the process, not just strictly in terms of either the barrels of oil or the barrels of oil equivalents, but in a project like Point Thompson with that massive compression to maintain the reservoir pressure, it takes a lot of energy. And so you're, you're burning some of your gas in the process.

You're going to consume a certain amount of gas in the process. And so that's, you know, a consideration too. Ultimately, you know, and a good example is Prudhoe. Over the years, that gas resource or reserves number has gotten smaller, and that's because they continue to use that gas in the field. And so the longer you go without a blowdown situation producing the gas, the more of it you're actually going to consume for in-field uses and other such things.

Thank you. Senator Wilkowski. Thank you. When you evaluated potential offtake for Point Thompson, did you— in looking at the greater ultimate recovery, did you look at the BTUs? Did you look at the economics to the state?

What, what evaluation did you use? Yes, Senator Birkowski, through the chair. Again, we do have a slide coming up that will address that, but we did not look at the economics. It's in that terms of barrels of oil equivalence.

Very good. I see no other questions. I do appreciate that you've put the AOGCC mission up. You know, most of the public has never heard of your commission, so this is very helpful. Thank you.

You can go on to now to the next slide, which I think is number 5. Yeah, we kind of like to think the longer we can go with them never hearing of us, that's not necessarily a bad thing. It means that maybe we're doing our job correctly. Well, that's true.

So this is just a snippet from the existing gas offtake order. It was Conservation Order 719 from 2015. And so Rule 8 down below is just a very small part of that gas offtake order. But in that, that was where the allowable gas offtake was for Point Thompson was set at 1.1 billion standard cubic feet per day. That's the BSCFD, billion standard cubic feet per day.

Very good. Senator Rauscher has a question. Thank you, Madam Chair. Madam Chair, to the gentleman speaking. So why was it set at that number, 1.1?

I'm going to turn it to Dave Robie to answer that. He was here during the time of that drafting of that opt-in order. Senator Rascher, through the Chair, as Commissioner Wilson said, my name is Dave Robie. The reason it was set at 1.1 BCF is in part because that's what the applicant ExxonMobil at the time had asked for. But we didn't just blindly approve what they asked for.

We actually had a contractor working with us, Gaffney, Klein, and Associates, and with them and myself and another geologist here, we worked we had access to a data room at Exxon where we could see all the data they had, the reservoir simulations, this, that, and the other. And in reviewing that, we determined that at approximately 1.1 BCF per day is where things would start— recovery would start going lower. Up to that point, it was pretty constant regardless of what rate you're producing at. You just still end up getting about the same amount of gas out of the reservoir. So that's why it was set at that point.

Senator Rosier, follow-up? Yes, thank you. So the project that we're talking about, which is the gas line and the amount of projected amount of gas that will go through that pipeline in a day, Is this going to— that number going to be a workable number for you if it was just your number going through the pipeline?

I don't think we understand the question. Yeah, Senator Rauscher, through the chair, What do you mean by a workable number? Could you elaborate on that for us, please? Yes, I appreciate it. So there's an obvious number that they feel they've built the pipeline, they could transfer gas down the pipeline to make a profit and ship overseas, or added to the states, uh, the municipalities which are going to have offtakes.

So Are you going to be able to meet that if it was just you, or obviously we're going to need more, or just what you can take, 1.1, safely and assure it can maintain that? Is that going to be enough to just send gas from Point Thompson down the gas line? That's not our goal. Yeah, so Senator Rosser, through the chair, That's— the 1.1 is not adequate for major gas sales in the current project with Glenfarm.

Okay, thank you. Other questions? Senator Wilkowski. So the—. Is that the 1.1 BCF per day, is that pursuant to a blowdown or gas cycling?

And how much recoverable condensate do you expect with that over the life?

So, Senator Wilkowski, through the chair, that is in a blowdown scenario. And I— again, I will turn it to Dave Roby to discuss ultimate recovery of condensate, which is going to be compromised in a blowdown situation.

Excuse me. Yeah, in a blowdown situation, you will recover less condensate than you would in a gas cycling project. But at the same time, the amount of fuel usage necessary for the gas cycling project to process and recompress the gas so you can re-inject it will actually take more resource on a BOE equivalent out of the reservoir than you'd be losing in the condensate from a gas sales project. So, and the 1.1 is, is like Christian said, is the, uh, just the gas, just removing gas from Point Thompson for sale down the gas line. And the 1.1 is actually, um, higher than what they're actually planning to do, which is 0.9 BCF.

They asked for 1.1 in case they had downtime or something and had to ramp up production in order to make up for the losses during the downtime.

Senator Wielekowski. And my understanding— correct me if these numbers are wrong— but in a blowdown situation like this, the estimated recovery for liquids is between 210 and 305 mmSTB. Versus a gas cycling would significantly increase the recoverable condensate and oil by as much as 500 mmSTB. So are those numbers accurate?

Not with the math that we're— not with the math that we're going to show you on the current understanding of the condensate yield and the gas resource.

It does not calculate to 500 million or even close.

We'll show on a subsequent slide here what that calculation looks like. And in part, it, you know, it's dependent on the amount of resource that you— the gas resource that you have to begin with, because from each million standard cubic feet, You're— right now, you're recovering about 55 barrels of condensate per million cubic feet.

That number was originally considered to be significantly higher, but there has been 10 years of production data to help determine the number that's being currently used. And so we'll show on a subsequent slide the calculation on what the amount of condensate in the gas would be expected to be at the current estimates of gas volume. Senator Wielechowski.

And my understanding is there was a PetroTel report that was done for an EIS just a couple years ago, and they said the field had— and that's where the numbers come from— the field had as much as 500 MMSTB of incremental recoverable liquids if cycled up for 20 years. And that was their recommendation or suggestion that gas needed to be cycled for as many as 20 years before major gas sales to maximize the recoverable liquids?

So, Senator Bulkowski, I'm not familiar with that study, but the numbers that we are working with are the numbers that the current operator is using as far as gas resource and as far as condensate yield. And so, again, it's just a— it's a math problem at that point. Then the volume of gas versus the condensate yield in that volume of gas. Those are the numbers that we're working with at present. Senator Wielekowski, through the chair, this is Dave Rhomby again.

There was a study commissioned by DNR back before Point Thompson came online, and that study said that they could get 500 million barrels of crude oil out of the oil rim at Point Thompson. But that was based on a lot of assumptions that would be nearly impossible to meet. And I believe DNR has backed away from the conclusions in that report.

Thank you. Before we leave this slide, I think it might be helpful for the public who are listening, and perhaps committee members and the audience, etc., tell us more about condensate. It's unique, it's different than regular petroleum. Could you describe more and why it's so valuable?

Madam Chair, this is Dave Robie again. Condensate is liquid hydrocarbons at the surface that exist as gas down below. When you reduce the pressure, then the liquids can come out of that gas. And, uh, And so that's why gas cycling is important to keep the gas flowing through there to push the condensate-rich gas to the rest— to the wells that can produce it instead of having it— instead of having the pressure drop in the reservoir and then liquids start dropping out in the reservoir and get trapped in the rocks and reducing your ultimate recovery. And then, Chair, with what you would call a wet gas, you can produce condensate by chilling it and it'll drop liquids out.

But in the case of Point Thompson, it's a retrograde condensate. And so by dropping the pressure, you're going to lose those liquids to the reservoir itself. And then they become extremely difficult to, to harvest at that point if you've lost them to the reservoir. Rather than at the surface. And that's why maintaining the pressure is so critical when you have a field that's a retrograde condensate.

Thank you. I'm told that condensate, the liquid condensate, is a much lighter product than the oil that's being drilled for in Point— excuse me, Prudhoe Bay.

Madam Chair, that is correct. It's a very high gravity. I've got a definition here of condensate. You know, a low density, high API gravity mixture of light hydrocarbon liquids that separates from raw natural gas when pressure and temperature drop below the hydrocarbon dew point. It's often called natural gasoline or natural gas liquids.

NGLs, you'll hear the term. And so it's produced from wet gas wells or processing plants acting as a crucial component for the petrochemical feedstock. And it's used, you know, feedstock for the heavy oils. So for instance, Cook Inlet is a dry gas. You chill that or you drop the pressure on that and very little condensate.

To yield from any— from cooking the gas. It's almost pure methane. But some of your richer gases, and, you know, Point Thompson being one, you have the retrograde condensate. What I would say is that the yield of the condensate from Point Thompson is kind of on the low end of what you would like for a retrograde condensate field. There are fields that produce hundreds of barrels per million cubic feet of gas.

So that's, you know, several times the amount of condensate yield that you get from Point Thompson. So it was, you know, fairly lean retrograde condensate field to begin with. And something was mentioned just a bit ago about the oil rim in this field, and that was considered uneconomic to produce. It's a fairly heavy oil, and it's fairly thin at the base of the reservoir, and it's extremely difficult to produce an oil rim when you have a very large gas cap, maintaining the pressure and, and the techniques you would have to use to recover an oil, let alone a heavy oil, which is the, the oil in, in the Point Thompson field. And so I just want to draw that distinction between the oil, the potential oil that I think they have long since given up on recovering in Point Thompson versus the condensate, which is a valuable commodity within the gas Point Thompson.

Thank you for that. And that was Commissioner Wilson, I'm thinking?

That's correct. Okay. Thank you. Thank you. You know, part of the value of your answers to these questions, this is a very complex field, is my understanding, and expensive.

And this kind of explanation helps the audience and the, the public understand why it's so expensive, what a unique field it is, and why the condensate is something we don't want to simply write off and not recover to the maximum amount possible. So thank you for going into this level of detail. Are there further, further questions from committee members? Seeing none on this slide, we can move on, I think, to slide 6.

So this is Commissioner Wilson again. And so Point Thompson, this is one of the questions, you know, what, what has changed, I guess. So Point Thompson 2015 versus 2026, referencing back to the discussion that this committee had years back with Commissioners Forster and Seamount. It focused on the best recovery approach, including full-field cycling versus the blowdown scenario. So optimizing liquids and an assumption of substantial gas uptake in the mid-2020s.

That was the discussion, you know, 10, 11 years ago. So after 10 years of cycling with the 2 injectors and 1 producer, uh, the current operator, Hilthorpe, has a more conservative estimate of the original gas in place. Uh, also based on the production that's happened, uh, the condensate yield is somewhat leaner than the initial estimates. And then another issue, reservoir compaction has been observed, and that adversely affects the deliverability. And to say just a little bit more about reservoir compaction, Typically, the open pore space in a reservoir is maintained by the structural integrity of the rock, whether that's a limestone with open pore spaces in it or a sandstone with open pore space between the grains.

But that grain-to-grain contact or the structural integrity of the reservoir, it will maintain that open pore space even if you drop the pressure. That's not the case in all fields, and what's been observed in Point Thompson is that this 10,000 psi in the reservoir is helping to maintain that open pore space. And so if you start to drop the pressure in that reservoir, you're going to see compaction within the reservoir, and so your porosity is going to be reduced, and that will adversely affect the deliverability because it's not only reducing the porosity, but then it's also going to reduce your permeability, the ability to move the liquids around in the reservoir. Thank you for that. Those are— that's a key point.

Thank you. And that was a new learning. Excellent. Questions from committee members on slide 6? Moving to slide 7.

And so this table— this is Commissioner Wilson again— this table shows some of those differences, changes from 2015 to today. And so first was just the estimated start date for major gas sales. They were looking at approximately 2025 in 2015. Right now, just looking at the published dates, we're looking at in-state gas in 2029. And LNG export about 2031.

The gas in place in 2015 was estimated by Exxon to be about 8 TCF, and that has been the number that's kind of generally accepted out there. But a more recent interpretation, you know, and maybe in part based on the production, the new wells and the production from those wells, the behavior, Hilcorp saying about 6 TCF, trillion cubic feet. And so you can see the source there, technical review meeting with Hilcorp in July 27th, 2023. In 2015, the condensate yield was anticipated to be 60 to 65 barrels per million standard cubic feet. MM is an abbreviation for million.

I know it gets confusing. Why, why isn't it just M? But M is thousand. So mm is million standard cubic feet. Today, the estimate based on production data, and so there's a lot more to go on, that estimate is more like about 55 barrels per million cubic feet, standard cubic feet.

And then the reservoir compaction, that wasn't considered to be an issue. It wasn't really on the horizon, I guess, in 2015, but it's been noted to be a significant issue, uh, in the present interpretation of how the reservoir is behaving. And again, that source is a technical review meeting with Hill Corp, uh, on July 27, 2023.

Very good. Questions from committee members? I don't see any. We're ready, I believe, for slide 8.

This is Commissioner Wilson again. Just a very brief description of cycling versus blowdown. So, and I think, you know, we've addressed some of the questions distinguishing the two, but cycling, you produce gas and condensate, then you re-inject most of the gas to slow the reservoir pressure decline. It helps sustain condensate recovery so that you're able to bring that condensate to the surface to drop it out of the gas rather than lose it to the reservoir in a cycling project. So the goal again is to maintain that reservoir pressure to the maximum extent possible in a cycling project.

Blowdown is produce and sell the gas and the condensate, but with that pressure decline, you're going to get an increase in condensate dropout in the reservoir and reduce the amount of liquids recovered. And so a trade-off between the two— cycling tends to recover more condensate, but it would delay gas sales and it reduces the amount of recoverable gas. So blowdown recovers more total energy in terms of barrels of oil equivalents, but it can lose some of the condensate and may require different development choices.

Very good. Senator Kawasaki has a question. Thank you. And then As you, as the AOGCC, how do you decide on what to sanction as far as the request goes for whether they start to cycle or whether they do blowdown?

We reviewed their reservoir models and Those models showed the sensitivity of the reservoir under various scenarios. They did scenarios for gas blowdown at different rates. They did scenarios for gas cycling in different forms. And reviewing that information for this— for Point Thompson specifically, the amount of liquids in place, condensate in place, is a much smaller volume on a barrel of oil equivalency basis than the gas is.

There are fields that are richer in gas and also lower pressure, so they don't have to spend as much fuel gas to recompress the gas to get it in, where in those situations, continuing cycling for an extended period of time will get you some significantly more recovery than if you begin blowdown right away. But at Point Thompson, the models that we looked at indicated that on a total BOE equivalency, the gas blowdown would actually recover more BOE than, than doing cycling because the, uh, this significant increase in fuel consumption would more than offset the loss in the condensate consumption— consumption— or production, sorry.

Senator Kawasaki, follow-up? Follow-up is that, um, I guess it depends on how long the time horizon is too. So how do you take into account the time that a company says, do you, do you have plans of development that they're going to redevelop structures nearby or other, or they're going to access other nearby parts of the participating area. How do you, how do you make that part of the equation and decide, and decide on whether, okay, this is a, this is a unit that's just going to be, that's just blowdown and then they're, they're leaving.

Senator Calhoun, Secretary of the Chair, this is Dave Robie again. Uh, we would look at the entire field when making a decision like this. In the instance of Point Thompson, there is no currently known, uh, additional formation there that's productive. There have been some discoveries in the Ripien Formation in the area. But those are relatively small, and it's possible that those could be developed later on in field life by utilizing Point Thompson facilities instead of having to build their own facilities.

But at this point in time, that's all speculative. Okay, thank you. Senator Myers. Yeah, thank you, Madam Chair. So, um, my understanding is that, um, between a combination of the, of the extremely high pressure of Point Thompson and the reservoir compaction, that The gas cycling is also extremely expensive, and so it creates a significant difference between oil, the condensate that is technically recoverable versus what is economically recoverable.

Is that accurate? Senator Myers. Senator Myers, Mr. Chair. Yes, that's accurate.

As part of the data review process that we had with ExxonMobil, they showed us their economics. Unfortunately, I can't go into any details on that because it's under an NDA, but I can say that gas cycling was only profitable in a— if all the various parameters of the field were the best it could be, like highest potential yield, best permeability, cheapest, uh, cost to put in the facilities and do the wells, etc., etc. Only under that circumstances would it be economic, and that was only maybe a 5% chance at most that that would happen. Okay, thank you. Very good.

Senator Rauscher. Thank you, Madam Chair. Um, so I don't know how to ask this question, but I'm trying to understand the worth of condensate. So if gas— I'm just gonna use the inlet right now— is worth $8 to $13, uh, and oil is worth about $90 to $110, what's condensate worth in that arena? If that— the only way I know how to ask the question.

That's price per barrel. It's a really expensive crude, right? It is. I don't have a number. It's mixed in with the—.

Yes, it's blended. So, was this— I apologize, was it Senator Rauscher through the chair? Yes, it was. None of us have on the tip of our tongue what a standalone price for a barrel of condensate would be, but it is used as a blend with the crude also. I mean, it'll lighten a crude by blending it.

And so, you know, obviously it has a substantial worth in today's environment. A barrel of condensate has a substantial worth in today's environment. Follow-up. So, Senator Rosier, um, the Quality Bank, uh, determines— all the oils that come in at mile zero of the pipeline, um, are put together, and the Quality Bank kind of looks at the values. That would be an interesting question to ask the Quality Bank.

What is the value of condensate, which is so light versus the heavier Prudhoe Bay oil in terms of its ability to go down the pipeline, its energy content. That would be an interesting question for the Quality Bank. Did you have another question, Senator Roscher?

Yes, thank you. I was just— after what I had heard from both of you, I guess it just has to actually— it aids in the production of getting it from one end to the other. And then its worth is valued in that process, or am I wrong?

Commissioner Wilson or Mr. Robey?

Restate the question. Could, uh, Senator Rauscher please restate the question? Yeah, okay, I will. I'm just trying to understand, is it valued in the process more than anything else, uh, when you— or is it actually valued in now the mixture of what is in the oil? As from what I heard by Senator Giesel, or how is it valued?

I just want to know how it's valued, if I don't need a number, um, of what it's valued, but just how it's valued.

Here, Roger, through the chair, this is Dave Groby. Generally speaking, the lighter a hydrocarbon liquid is, the more valuable it is. With condensate being on the light end, it's generally more valuable than crude oil. Like, for example, the West Sac produces a fairly heavy oil, so that oil is worth less than what's produced from Prudhoe and Kuparuk. But it's all mixed together and it's just one stream that going, going south.

So that's the price of— that's the composition that they're getting paid on is the composition there. The thing at a pump station 1, but then they— the Quality Bank will look at what each facility produces and sent to pump station 1, both the volumes and the composition. And then they will back calculate the value of a particular barrel of oil coming from a particular field. Thank you. Thank you, that was a good explanation.

Senator Wilkowski. Thank you. I think Senator Rascher hit on the very critical point, which is the condensate at Point Thompson is probably the most valuable substance on the North Slope. It is extraordinarily valuable. And I know for decades that this field has been the subject of litigation, lawsuits.

The state at one point took away the lease. Exxon refused to develop this lease. Probably 20 times. Long, long, long battles. And I know, I know, years ago, Exxon wanted to blow this down, and, and the state said no.

The state had a policy for many, many, many years to not allow blowdown in this field because the condensates were too valuable. And so I'm curious, how many barrels of condensate and oil are— is the state foregoing? I see we're getting 330 million barrels under this blowdown scenario. How many How many are we foregoing under a cycling scenario?

Sounds like that may take us to slide 9.

That's correct. I was just going to suggest we move to the next slide.

So this is that calculation. This is Commissioner Wilson again. This is that calculation that I referred to earlier on Point Thomson reserves. First, you know, why do the reserve estimates range between 6 TCF and 8 TCF? Uh, you know, there are differences of interpretation, um, primarily around net pay thickness.

Uh, there may be some, uh, interpretations too around the overall porosity, uh, in that pay. But, uh, it's, it's a difference of interpretation. Obviously, it, it's a volume issue, a calculation where you integrate the well data with the seismic data with core data to come up with that void space in the rock that contains the gas. And so that is the volume that you would calculate for a given reservoir of the in-place gas. Obviously, to produce it, you have to apply a recovery factor.

And so when we talk about original gas in place or original oil in place, That doesn't mean that all of those fluids are going to be recovered. You'll apply a recovery factor, and that's based on a number of things too, but the quality of the reservoir comes into play considerably on that recovery factor. So we talked previously about barrels of oil equivalent. One barrel of oil equivalent is 5.8 million British thermal units, or BTUs. That's one barrel of oil, but roughly equivalent to about 6,000 cubic feet of gas at standard pressure and temperature.

And so using the current operator's numbers of 6 TCF of gas, that would say that you have about 1 billion barrels of oil equivalent in place.

To look at condensate, the current yield by— that has been determined by the operator given the production data is 55 barrels per million standard cubic feet. And so that's per million standard cubic feet, so it's just a matter of 55 times the 6 TCF, and that's where the 330 million barrels of condensate would come from. But that would be, again, more of an in-place number. And you would have to apply a recovery factor to that number. But using the volumes that have been shared by the current operator, that would be the maximum extent in that 6 trillion cubic feet using the 55 barrels per million cubic feet of condensate recovery.

So those are the numbers we were alluding to earlier. And so going back to our mission statement, you know, we look at the ultimate recovery of the overall resource, and the gas resource in that context is 3 times greater than the condensate resource. But as we discussed earlier, uh, in our determinations, we are not looking at the price of a barrel of oil or the price of a cubic feet of gas. Uh, that's, that's for other agencies and the legislature to consider. Follow-up, Senator Wilkowski.

But the question is how much condensate can be recovered under a blowdown scenario versus how much condensate could be recovered under a gas cycling scenario.

Senator Wilkowski, through the chair, this is Dave Roby again. During the testimony that led to the gas uptake limit for Point Thompson, ExxonMobil stated that over the 30-year life of the project, about 75% of the gas could be recovered. And they also said that about 200 million barrels of condensate would be recovered out of the gas cycling project. And that was based on their higher— their larger volume that they were using and the higher yield that they were using. So the— their in-place condensate is about 450 million.

So, $200 million out of $450 million is less than 50% recovery. So, this is just with $130 million, you'd get about 165 million barrels of condensate if you did a gas cycling project. And you get obviously less than that if you did a blowdown.

But it'd probably be somewhere about 2/3 of what you'd get from a, from doing cycling is what we'd get from doing blowdown. So, 165 versus 100 million, roughly.

And Senator Wilkowski, through the chair, you know, there's kind of two different paths of thought here. You know, one is on ultimate recovery of the resource and the AOGCC thinking in terms of barrels of oil equivalent. But on the other hand, there's also the value of the resource. And as we've discussed, you know, the value of a barrel of condensate is considerably high, you know, compared to other resources on the North Slope. And so, but the trade-off there is, you know, beyond the scope of what the AOGCC does.

We don't have economists —anyone on staff to evaluate that sort of thing. That would be with other agencies. Follow-up, Senator Wielekowski. Just so I'm clear, so gas cycling, you— Gas to convert. —$165 Million recoverable, roughly blowdown scenario, $100 million barrels of condensate recoverable, and under the cycling, 75% of gas recoverable, and how much under the blowdown scenario?

Senator Bulkowski to the chair. This is Dan Romy. The, uh, 75% was, um, for both— well, over the 30-year period, it'd be roughly, um, the same recovery efficiency for gas under both, um, blowdown and gas cycling, but there'd be less gas to recover under cycling because of the additional fuel usage that would be required to repressurize the gas from basically atmospheric pressure to 10,000 PSI and pump it back downhole to complete the cycle process?

Senator Murkowski, through the Chair, I don't have a number for Point Thompson, but just You know, for comparison, at, at Prudhoe, about 10 trillion cubic feet of gas have been consumed over the life of Prudhoe Bay, uh, just for, uh, infield use, um, you know, on, on compression, on fuel gas, that sort of thing. So, uh, the, the longer that the field goes without gas sales, the less gas you're going to have to produce at the end of the day.

And you lose 10,000 PSI. Senator Dunbar. I'm fine, Madam Chair, thank you. Further questions? Senator Myers.

Yeah, thank you, Madam Chair. So just to clarify, when you're giving us those figures of the condensate coming out, is that what's technically recoverable or what's economically recoverable?

It's technically recoverable under the gas cycling case, but very, very, very, very low probability that could be done economically. Under the blowdown case, assuming you could do a blowdown project economically, then the gas recovery or the condensate recovery would also be economic because you're not expect you're not doing any more to get the condensate out than you were— than you are doing to get the gas out. Okay, that makes sense. Yep. Thank you, Senator Werlikowski.

The compression is not needed in that case. All the energy goes into that compression to maintain the reservoir pressure. Right. Senator Werlikowski, could you—. And last, this is probably the last one for me, but could you just get us something in writing comparing the on condensates and gas that would be available to the state for— available in cycling versus blowdown?

Because I'm seeing very different numbers from the EIS that was just done a couple of years ago. They said gas cycling for 20 years would produce 620 to 850 MMSTB of liquid hydrocarbons versus a blowdown, which would be 210 to 305. Those numbers are wildly different than your numbers. And that was just a couple of years ago. So could you get us something in writing and the facts that you have to verify that?

Thank you.

Further questions from committee members? Yeah, we certainly— we certainly can send— was that Senator Bullockowski? Yes, it was. We can do requests for information. That's certainly within our purview.

And we are with a lot of this line of questioning, we're getting to— I'm not sure if it's the final slide next or if that's a few slides out. But the potential that we need to revisit the gas offtake order for Point Thompson at the end of the day with the number of changes that are being shared with us since that gas offtake order was issued in 2015.

Thank you. Yeah, if you could write up the answers to the questions Senator Wielechowski has offered and send it to my office, all the committee members will get it and it will be posted on our public website. Follow-up, Senator Roscher. Thank you, Madam Chair. Real quick, because of the last statement that he said, do you predict it to be smaller or higher when you re-review?

Senator Roscher, the gas offtake? Yes. Are you asking is the gas offtake?

Because you said since 2015, that was quite a while ago. You believe there's going to be a re-review. So I'm wondering, do you expect it to be a higher number now or a smaller number, and by how much, if you could tell me? Senator Wolkowski for the Chair. Um, the— oh, sorry, Senator Rauscher for the Chair, my apologies.

Um, the— if If and when we reevaluate the gas uptake, it will not go higher than what it currently is. It'll either be the same or go lower than what currently is, based on what we know today.

All right, thank you very much. I think we can move on to slide 10.

This is Commissioner Wilson again, uh, addressing dew point and condensate banking. I think this was one of the questions that was also asked of us. And so just the two bullet points here. In reservoirs like Point Thompson, if pressure in the reservoir drops below the dew point, the liquid droplets form and block the flow of gas. And so that's referred to as condensate banking.

Gas flow is reduced and the condensate is trapped in the reservoir. So that's a— it's a loss of resource in two regards. You're losing the condensate to the reservoir, but also your ability to produce gas is hindered by the condensate banking. And so practical takeaway: keep the pressure above the dew point to reduce the chance for condensate banking and the loss of condensate.

Thank you. And the dew point is sustained by the pressure, is that true?

Madam Chair, yes, that is true. In the case of this reservoir, that is true. Dew point can also be maintained in other circumstances, but maintain— you need to maintain temperature also in some cases. But in a retrograde condensate, you need to maintain that pressure.

Senator Myers. Thank you, Madam Chair. So in maintaining that pressure, is the geology at Point Thompson such that you can use other of the standard enhanced oil recovery techniques that we've seen across the field, you know, pumping in seawater or something like that to help the pressure as well once you start pulling the gas out?

I'm going to turn that one to Dave Roby. There are methods, not necessarily economic in this case, but there are methods to— for enhanced recovery in a gas condensate field. Senator Myers, for the chair. Point Thompson is essentially a giant gas reservoir, and generally speaking, water flooding a gas reservoir is not a good idea. Okay.

Ends up reducing recovery instead of increasing it. They are doing water injection in the gas cap at Prudhoe, but that's a different process than a strictly UR process. That's a way to get more energy into the reservoir to slow or stop the rate of pressure decline in the rest of the field. And so it would have some impact on the gas recovery, but it's helping out the oil recovery by the estimated 500 million barrels by doing that. So it's a pretty significant number.

Okay, thank you. Um, did you want to address the temperature, Jim? Yeah, just that it's not practical in this case for—. Yeah, there's In addition to reinjecting just the produced gas, there's other retrogate condensate fields like the Antschutz Ranch field in Wyoming and Utah where they have a nitrogen plant there and they inject nitrogen into the reservoir to help with the pressure maintenance. And in a situation like that, if that was viable here, then if you had enough nitrogen to replace all the voidage out of the reservoir, then you could sell the condensate, the gas, and the at the same time, and you wouldn't have the condensate dropout problem associated with declining pressure because you'd be maintaining the reservoir pressure.

But that's yet another additional cost that would have to be imposed on the project. Could you also address the condensate recovery in the field you mentioned? Oh yes, also in the entrance ranch field, they have about 200 barrels of condensate per million cubic feet, so it's about 4 times richer than what we have at Point Thompson. So, and it's also about 5,000 PSI, so it's half the pressure. So they have a lot of positives going for it.

The one Thompson doesn't. Cheaper operating. And it's also in Wyoming and Utah, which is a lot cheaper place to work than, than some of Alaska.

Thank you for that. All right, we're ready to move on, I believe, to slide 11.

So we've addressed— this is Commissioner Wilson again— we've addressed some of the learnings that Hilcorp has attained with the production that's been going on for the last 10 years there at Point Thompson, but we'll hit them again here. And that's performance is pressure sensitive, careful pressure management improves outcomes, aggressive drawdown degrades the productivity, and it can permanently harm the rock and trap the condensate. And so that goes back to that condensate banking again to some extent. And then compaction does matter here at Point Thompson. Deliverability can decline as the reservoir compacts, so requiring smarter well and injector balance rather than simply pulling harder on the reservoir itself.

It would likely require more development wells than previously planned to avoid that reservoir compaction.

I see no questions. Thank you for that. And now slide 12. And so this is our final slide, but there have been changes in our understanding of Point Thompson Reservoir between the issuance of Conservation Order 719 and what we know today. On a barrel of oil equivalence basis, there are more reserves in the gas than in the condensate at Point Thompson.

Again, we're not talking about the value of either resource, but just, uh, there's more reserves in the gas than in the condensate at Point Thompson on a BOE equivalence. To maximize ultimate recovery, the gas will need to be produced, and based on new learnings from the field performance, revisiting the offtake order may very well be warranted.

Very good. Questions from committee members? Senator Dunbar. Thank you, Madam Chair. I have a fairly large question, and it's related to, though not directly on this presentation.

Perhaps there's another presentation. I'm curious about this kind of analysis with regard to Prudhoe, and we are getting presentations from the Department of Revenue that I hope that you have had a chance to look at, and they're trying to do calculations you know, of expected revenues and they are expect— they, they are at the present just, just modeling zero oil loss because it simplifies things a lot. Um, I assume that is not actually the case and they, they think so too. And I was wondering if you could opine a bit about what it will look like, um, when, when hopefully, uh, we start taking gas off of Prudhoe in very large amounts.

Not a concern. Sorry, I'm dumbfounded, Chair. It's Dave Ruby.

When they begin gas sales from Prudhoe, it will definitely reduce the amount of liquids they have recovered because they wouldn't be putting 2 to 3 billion cubic feet of gas back in the reservoir every day like they're— it's currently going in. So there'd be significant pressure decline, rapid pressure decline. So that would lose the— if I remember correctly, we estimated there was about 1 billion barrels recoverable left in Prudhoe Bay at the time we increased their gas uptake back in 2015. Since then, they've produced quite a bit of oil, so that number would be lower. I can't say off the top of my head how much lower it would be.

But that would be whatever is left. Then a portion of that, say 40% maybe, would not be recoverable when they do gas sales, as opposed to if they kept doing the reinjection— gas reinjection like they're doing now. And then Prudhoe is a field where doing gas reinjection made a lot more sense than at Point Thompson because there was a lot more liquids in the reservoir to begin with.

Under the initial plans of development, they anticipated beginning gas sales approximately 5 years after oil sales of crude oil. And at that time, they said the oil recovery would be about 9 billion barrels. We produce 15, 16 billion barrels now. A lot of that would not have been possible had they begun gas sales as early as they anticipated. And then, Senator Dunbar, through the chair, this is Commissioner Wilson again.

To further elaborate on what Dave Roby was talking about in terms of remaining reserves in Prudhoe, so, you know, something substantially less than 1 billion barrels of black oil. But then when we look at the gas resource there, On that barrel of oil equivalence basis, again, there is about 4 billion barrels of oil equivalent in the gas as compared to the remaining oil. So again, that's, you know, a perspective the AOGCC takes in part when we look at this. Follow-up, Senator Dunbar. Well, thank you both.

That's really helpful. Um, I— the, the 40% would become unrecoverable. Could you elaborate a little bit on that? You know, what we're looking at is not so much the absolute term of what is unrecoverable, but the delta between, um, what would be unrecoverable with and without, uh, large gas offtake. And so I guess my question is, if we, if we didn't have the gas offtake, would all of that 40%, um, recoverable?

Could they really get down close to zero? Or is the delta some number smaller than 40%?

The Chair, the 40% was just a wild guess on my part. I don't know if it's 10%, 50%, 70% difference if they do gas sales and if they don't do gas sales and liquid recovery. But the billion barrels that was left in 2015, that, you know, that was based on the economics of field development. Eventually, Prudhoe will get to the point where they can still technically recover oil, but they'd be spending more to do it than they'd be making off of doing that. So there will be liquids left in the ground for any type of project just due to economics preventing further development of the the project.

That makes sense. Thank you. Um, one quick follow-up. I suppose this is for you, Madam Chair. Do, do we intend sort of as a committee to formally ask them for that kind of analysis at Prudhoe, or is that something that's not practical in the short time frame we have?

So, Commissioners, is that a practical request, uh, to make of you for producing a report like that in the next couple days?

In order to do that kind of analysis with any sort of confidence in it, we would have to have access to Hill Corp's reservoir simulation model. And have them run various scenarios to compare doing blowdown now, doing blowdown 5 years from now, 10 years from now, et cetera, et cetera. So it's not something that we could put together in a short amount of time. Understood. Thank you.

Thank you, Madam Chair. Thank you. Any other questions? Senator Wilkowski. Just on that point, my understanding is that there, there has been some analysis of the impact to Prudhoe Bay if there is a switch over to gas production.

I— from, again, from the EIS a few years ago, it shows that switching to producing more gas out of Prudhoe Bay in 2029 would result in a reduction of 450— a loss of 452 million barrels of oil. Does that sound right?

It might be half of what's there right now. Sarah Wilkoski to the chair. Um, I'll have to look at the EIS itself and see where they're getting those numbers from, so I don't want to hazard a guess without doing that first, if that makes sense. Okay, thank you. Thank you for that.

Any other questions from committee members? Seeing none, Commissioners, thank you very much for joining us today. And Mr. Roby, thank you for joining in also.

This has been a very valuable presentation, super interesting. So thank you very much. All right. With that, that concludes our presentation today. I'm going to open public testimony for a few minutes that we have remaining.

And I'm going to start here in the room. The guidelines are going to be the same as always. 2 Minutes. I do have a timer that I will be setting so you will be able to hear when your 2 minutes is up. When you come to the table, please identify yourself clearly for the record and any affiliations that you have.

So I'm going to go through the list based on time signed up. So number 1 is Dave Bronson. He will be followed by Andrew Rawson. Please come forward. We have about 15 minutes left.

Thank you, Madam Chair, committee. Thanks for this opportunity to speak on this important subject matter. As a former mayor of Anchorage, I saw firsthand in February of '22 the shortage, the potential shortage of natural gas on the rail belt, we were facing in a 2-week period of double-digit below zero temperatures, we were facing brownouts in the city. And we had to make a decision, or the NSR had to make a decision between producing gas for heat and producing gas for electricity. It got so close that the difference was made by Colonel Wilson, who turned down the heat in his hangars at Elmendorf, and that's specifically what made the difference and kept us from going into brownout.

I'm not going to get into the details. There's other people that can— especially you folks, I'm not going to try to educate you on this. I'm just trying to convey a sentiment, and the sentiment is across the rail belt, something's got to be done to produce more heat and more electricity, and especially in Fairbanks. Fairbanks is suffering deeply. They're using wood and heating oil to heat very many homes up there.

And this, this gas line and the related spur for this gas line is absolutely essential. Not passing this, not getting this project in the ground and getting it done will create, I think, real social problems in specific parts of the state, especially Fairbanks. This is absolutely essential. I know there's a balance between gas and oil production. We just heard heard about that, but we've gotta produce gas because that's our heat and that's our electricity, and this is absolutely important.

So I will close my remarks there. Thank you for the opportunity. Thank you very much for your testimony. Next up, Andrew Rawson. He will be followed by John Theis.

Thank you. My name is Andrew Rawson, general manager of Golden Heart Waste Management, a locally owned and operated uh, Interior Alaska company serving local businesses, the oil and gas industry, and the United States military. Um, Golden Heart Waste Management operates across the interior. Energy is our single most unpredictable and punishing cost. Interior Alaska consistently faces some of the highest energy prices in the United States, with heating fuel and power costs that can be 2 to 3 times higher than the national average.

When energy prices spike, We feel it immediately, and so do the thousands of customers that we serve. Every increase forces us to consider raising rates, and every rate increase drives up costs for families, businesses, critical industries across the interior of Alaska. We have been holding hard to not do rate increases, and we've been carrying that burden, and we can only carry that burden so long. We're at a pivotal moment right now. Alaska has a narrow window to stabilize energy costs.

Grow our economy, keep people in the state. But we cannot do that if we continue to maintain a tax and regulatory structure that makes major energy infrastructure financially impossible. Right now, Alaska's infrastructure tax burden is 10 to 12 times higher than comparable LNG jurisdictions in other parts of the country. That is not an opinion. That is a structural reality.

Every successful LNG market in the world and in the United States has a tax framework designed to attract investment, not repeal it. Correcting an outlier is not a giveaway, it's normalization. It is what every competitive LNG rate region has already done, and the consequences of inaction are not theoretical. Without a viable project, Alaska receives zero state revenue. Without a viable project, local governments receive zero revenue.

Without a viable project, there is no pipeline No gas to Fairbanks, no gas to Anchorage, no gas to the peninsula, and no energy relief for any of us. Without a viable project, Interior Alaska remains dependent on volatile fuel markets that have already driven families and businesses out of the region. Thank you for your testimony. Thank you. Um, next up is John Theis.

He will be followed by Constantine Misiuk.

Chair and members of the committee, thank you for your time. My name is John Theiss. I'm born and raised in Fairbanks, Alaska. I'm the owner of Golden Heart Waste Management and Worry Free Alaska. We're a general contractor working with general and civil construction throughout the community.

I appreciate your opportunity to be able to speak on behalf of SB 280. I want to be clear about the reality facing businesses in the interior. This past winter was one of the coldest in recent memories, and our heating costs simply just rise. They spike drastically.

With our facility heating bills and everything, ever just gone through the roof, that leaving that volatility making extremely difficult for any business to plan a budget, maintaining stable operations. While diesel is not the focus of this legislation, it is part of the broader picture of the energy instability in Alaska. When global events caused diesel prices to almost double, we felt it immediately. But the deeper issue is that it affects every household, every employer, every community in the interior, as well as the state of Alaska. The lack of affordable, reliable natural gas— without natural— the issue is, without having reliable natural gas dependent on price is also the most— we're sorry, we're having problems without having the natural gas.

My company's been absorbing these increases And we've been trying not to pass them on to customers, but sooner or later that is going to happen. The Interior needs natural gas to help stabilize our heating costs and support the economic growth and the families and the businesses in Alaska. We understand this framework is complex and there's a lot to put this thing together. But similar to me being just a trash man and a contractor, I'm not an expert in gas lines and I'm not an expert in these kind of contracts. And as well as you guys as a committee, our project— are not project managers, financial experts, and contract experts in this field.

The AGDC was created to be a professional organization to represent the state. Now, from what we can see on our side, it doesn't look like the trust is there in that committee to be able to handle the contracts in agreement. If I can make one suggestion, can we please focus on having a striving economy and better gas prices and let— and try not to squeeze every dollar out of this gas line? Thank you. Thank you very much for your testimony.

Um, Constantine Mizziouk, he will be followed by Jacob Carlson.

Thank you, Chair, and the members of the committee. Thank you for the opportunity, for giving me this opportunity to testify.

I am a long-time Alaskan, live in Fairbanks. I own Gen Solar, or we own multiple companies, and I'm also a pastor of a community church in North Pole, Alaska. And I get to hear the worries the families have here in Alaska. We are having a crisis, an energy crisis, especially, for instance, in Fairbanks. We're paying 32 cents per kilowatt for electricity, not counting the high heating bills that we had this last year.

It killed— from a business standpoint, it ate up a lot of profits on our business side. A lot of homeowners, a lot of small families, they're struggling to make their ends meet. We have an energy crisis. Not only that, but we have a population crisis here in Alaska. In Fairbanks, just, we have a hard record or a high record of people, young folks moving out of Fairbanks, right?

And that's a crisis. It's unsustainable. For instance, the growth in the past 10 years in Fairbanks only grew half a percent, 0.5%. Anchorage grew 3%. Wasilla grew 13%.

Why? Because they have lower property tax and the regulations are less. So it's making more inviting, more feasible for contractors to come in to build new homes. And whatnot.

We need the gas line. We ask you, the legislators, to make the right choice, to make the right decision. We cannot afford, we cannot go any longer without the gas line. We've heard promises for the past 70 years, and please do not be this next generation that just provides empty promises. So we the people We trust you and we ask you and we pray that God gives you the wisdom to make the right decision.

Thank you. Thank you for your testimony. Next up is Jacob Carlson. We will also then go online and Dean Bartsch from Nakiski will be after Mr. Carlson. It's the first time doing this.

Thank you for the opportunity to speak. I moved to, uh, move my family to Alaska in 2021 and, uh, to enjoy the Alaska resources. And since we moved to Alaska, we have opened numerous businesses. My children have graduated from high school in Fairbanks. Trying to grow our business with the lack of population growth, the economic development, and a lot of the population of Fairbanks aging, that makes it very challenging to grow a business effectively.

It is, it is a real, real challenge. I've built I've participated in building pipelines all across the country in the upstream and midstream sectors.

I love building pipelines, and I was very tickled to hear this pipeline was coming to fruition finally. It's very frustrating to hear that this is getting stalled in these committees right now. I came down here to just to speak, to put my support as best I could to encourage everybody to pass this and to get this get this thing moving. It's a much-needed pipeline for the state of Alaska for numerous reasons that have already been covered. Thank you very much.

Thank you for your testimony. Before we move to the phone, obviously many of you here are from Fairbanks. Two of our committee members are also— Senator Myers, Senator Kawasaki. I was born and raised there before statehood. I'm very familiar with Fairbanks.

I have a family member who still lives there. We'll move on now to the online. We have Dean Barsh. He's calling in from Nakiski. He'll be followed by Ken Huckabay.

Mr. Barsh, can you hear us? Yes, thank you. Thank you for taking my testimony. Although the information that was given today and for the last couple of weeks was very interesting, it's really none of your business. Your business is to know what— that there is going to be gas coming in one end of the pipe and coming out of the other end.

Glen Farnham has come to the state and said they need a change in the way tax was assessed to bring investors into the pipeline project. The industry can get a 10% return on their investments if they use it elsewhere in the world. With the current tax structure, they can't make that return, making investment at, uh, in our state. Your paid consultants say the same thing and you refuse to listen. You legislators see the program as— no one in Alaska has asked for businesses' programs and business profit centers to redistribute tax revenues as you see fit.

Oil companies have seen dealing with warlords as more desirable than dealing with Alaska legislators. They have gone from our state. The greedy, self-aggrandizing legislators— the price of oil companies are allowed to change, charge for their products has been depressed and tax rates go past reason and has forced developers out of the state. And now the only ones willing to develop our resources are being forced out in like manners. Pass these bills out of committee so the entire legislature can act— legislators can act on the voters, and voters can see who is standing up for them and who is opposed to citizens of Alaska.

Thank you for your testimony. Um, next up is Ken Hakaba, and I'm going to remind folks, please state your name at the beginning of your testimony so we know who's speaking. That is recorded in the minutes of this meeting and is a legal document Committee Statement. Mr. Huckaba will be followed by Garrison Collette. Mr. Huckaba, calling in from Wasilla, welcome.

Thank you very much. My name is Ken Huckaba. I'm unaffiliated, speaking on my own behalf. Chairman and distinguished members of the committee, I want to thank you for allowing me to speak. I approach this not with emotion but with the cold eye of experience in economics, the same lens that has exposed so many well-intentioned government projects costly illusions.

We are told the Alaska LNG Project will deliver cheap gas to Alaskans. That is the promise repeated in every presentation, every press release. Yet nothing before us codifies it. No statute requires a firm share of the gas for in-state use at prices insulated from export markets. No binding contracts force the private majority owner to put Alaskan families ahead of higher-paying Asian buyers.

A price cap floated in one version of the tax Bill is not a guarantee. It is a hope. Incentives tell the real story. When capital costs run into tens of billions and export prices beckon, local consumers have a way of becoming the residual claimant, as happened in other locations around the world. History is littered with energy projects sold as local salvation that end up delivering higher cost once the rhetoric faded.

Even more troubling, this project quietly enlists every Alaskan as a financier of the carbon control scheme. The massive Arctic carbon capture plant is no option. Green add-on. It is required to strip the gas down from the North Slope from the investors. It's kind of an extortion thing.

So the product meets pipeline and LNG specifications. Billions in capital costs are added, offset in part by federal 45Q tax credits that our grandkids are going to pay with debt and inflation that flow primarily to developers out of state. These are out-of-state investors. Any shortfall, any foregone property tax revenue from the special deals now under debate, any upward pressure on utility rates lands squarely on Alaskan ratepayers and taxpayers. We're not buying affordable energy.

We as Alaskan gas buyers and Alaskan taxpayers and American taxpayers are underwriting an export project's environmental compliance. I have a question, if I may. Taxes and contracts place the viability square on Alaskans and Americans. What is the dollar figure for this viability? Yeah, I just want to know what is that.

So I appreciate it. Thank you for your testimony, Mr. Hakuba. Next up is Garrison Collette from— calling in from Fairbanks, and this is our last testifier for today. Welcome, Mr. Collette. Thank you, Chair, and thank you to distinguished members of the committee.

Thanks for hearing my testimony today. Today I'm celebrating 20 years as an Alaska energy professional. Professional. I think I am one of the most experienced energy professionals that was born and educated in the state. Uh, to start off with, um, sorry, uh, to start off with, um, there was a lot of complicated, uh, oil and gas talk with the, um, ALGCC, uh, uh, witnesses.

Uh, the, the main thing you need to know is methane is 1 carbon, ethane is 2 carbon, propane is 3 carbons, and butane is 4 carbons. These condensates are the, by far, the most valuable fraction of the oil and gas mix. Producing gas means producing less oil. I oppose SB 280 because you should be considering wind power, in my opinion, and not more welfare for oil and gas. But I think that The ALGCC testifiers also made it pretty clear that producing gas makes an end to the increase in— the temporary increase in oil volume production.

Volumetric gas is— volumetric tax is problematic. I oppose that if you do go ahead with your committee substitute for this bill. The upstream cost of gas is absolutely unknown. We will not know that. That will— the cost of gas will be the cost of the competition, which will be the same cost of LNG, which will be high.

So any, any gas that we get could be extremely expensive. We'd be walking ourselves into a no-win scenario, less oil, higher gas, cost of energy. So I'm from Fairbanks. Other folks have talked about the high cost here. The only way to lower the cost the cost of gas in Fairbanks, or the cost of energy in Fairbanks, is with wind power and geothermal heat pumps.

We need cheaper heat. There's only one way to do it: wind power and geothermal heat pump. Thank you very much. Thank you for your testimony, Mr. Collette. So I will close public testimony for today.

We will certainly have other days of public testimony. This concludes our meeting for today. This is our 30th meeting on this topic as we are ardently pursuing the best for Alaskans in supporting a gas line. Uh, the next meeting will be tomorrow at 9:00 AM, and so at this time we will stand adjourned. Let the record reflect the time is 5:01 PM.