Alaska Legislature: Senate Finance - June 8, 2026 1:30pm

Call Senate Finance Committee to order. It is 1:36 in Senate Finance Room, State Capitol. Monday, June 8th. We have Senator Steadman, Senator Olson, Senator Keehl, Senator Merrick, Senator Kaufman, Senator Cronk, and myself, Senator Hoffman. We have a full contingent this afternoon.

Good afternoon. We are going to hear from the 3 producers on the North Slope regarding SB 2001, the gas line— the gas pipeline volumetric tax bill that the governor has introduced. The first presenter will be from Hilcorp Alaska.

We have with the Hill Corp their Alaska Senior Vice President, Luke Sojay. Please come forward, introduce yourself, and give your comments on the proposed legislation.

All right. You guys hear me? Yes. Okay. Thank you for the opportunity to come and testify today.

See if I can advance my slides. Okay. So, yeah, thank you for the opportunity to testify today. It's important. It's important to me to be here personally.

And I think one of the points that I want to make as I run through these slides is that Representing Hilcorp, we're kind of in the middle of all of this. We propose to sell gas on the North Slope. We are currently the seller of gas in the Cook Inlet. And so, you know, we're right there.

Oh, right, sorry. My name is Luke Sauget, Senior Vice President for Hilcorp Alaska. Good? Okay. So I've got our kind of our standard introduction slide here.

Um, talking about who we are and what we do, 1,750 employees in the state, 3,000 to 4,000 contractors working for us at any point in time. We are the largest and most active operator in the state of Alaska. We have 8 drilling rigs running, not to mention several workover rigs, uh, 4 or 5 coil tubing spreads, and, uh, quite a few coil, uh, E-line and slickline units. Around the state. You know, we have more drilling rigs running than all other operators combined.

Of all of the gas— all of the oil that goes down the Trans-Alaska Pipeline, about 450,000 barrels a day, Hilcorp operates about 300,000 of that. So, largest operator. And every year we spend about $4 billion on behalf of ourselves and our partners across the state. Okay, so, um, let's see, uh, as I said, we're kind of in the middle of all of this, and one of the things I'll talk a little bit about is our gas sale precedent agreements with Glenfarm. So a gas sale precedent agreement is a way that two parties that want to agree on buying and selling gas kind of approach one another.

So we, you know, the things on which we agree, we agree on those things, we set them aside and kind of take those off the table as we continue our commercial negotiations, if that makes sense. These are non-binding commitments. Um, and as it says, they don't, they don't trigger any gas deliveries or financial obligations. It's our continuing commitment to work together. And, you know, I think they're helpful because they show where, where we are as we move forward.

They are confidential, so I can't answer specifics about what these GSPAs say, but I will say that they contain pricing. We've agreed on pricing, we've agreed on volumes, we've agreed on terms, right? And there are other things that we have not yet agreed on that we continue to work on as we move forward. Okay, so those are the GSPAs. What I'd like to do is give you an overview of the gas resources on the North Slope where Phase 1 and Phase 2 gas sales would come from.

And I want to start out with kind of a high-level view of North Slope oil and gas operations.

They're fundamentally integrated. When we drill wells on the North Slope, when we build roads and pipelines and facilities, all of that is in order to sell oil down the Trans-Alaska Pipeline. But when we drill wells, we end up handling other fluids as well. Every well that we drill produces 3 things. It produces oil.

We sell that. It produces gas. And it produces water. So today, we have to handle all three of those. And I've got a pie chart here showing, you know, roughly proportionately how much of each of these fluids we manage through our ongoing operations.

And you can see, we manage about 10 times as much water as we do oil, and about 5 times as much gas as we do oil. Okay? So all of these things are very much interlinked. We have, as an industry, invested extensively over the last 50 years in facilities to separate the oil from the gas from the water, to transport those various fluids to the appropriate places across the North Slope, to— for gas, to treat it, to strip the liquids out, to compress it, and re-inject it into the reservoir. And for water, to do much the same thing, to pump it up to high pressure, and inject it into the reservoir.

And that reinjection for gas and for water is very important because it maintains the reservoir pressure, serving to help maximize the ultimate oil recovery for the working interest owners and for the state of Alaska. Because of that, because of what we already do, we estimate the cost to sell Phase 1 gas into a pipeline would be, we think, less than $50 million. $50 Million cubic feet a day. I'm sorry, less than $50 million. And that's, you know, of course it always depends where that takes place and things like that.

But the agreement generally that we have with Glenfarn is we have these large gas handling facilities, and if they build a pipeline to that facility, we will connect up and begin gas sales. Okay? Does that make sense?

So what I'll do now is move on and talk about some of our individual—. Before you continue, we have a question from Senator Kaufman. Yes, thank you. Back on the other slide. I just— I think that's interesting.

I think it shows a much different picture than what a lot of folks think of.

Bless you. Bless you. Bless you. And anyway, I just think it shows a— a much different picture than some folks, you know, they think of what they see on TV where on Beverly Hillbillies maybe where, you know, oil is just pouring out of the ground. But the water-gas-oil ratio makes it more like you're mining and you're working with ore and you're getting some trace materials out of it.

I just think that's worth taking a look at. And that's a lot of water to handle, and a tremendous amount of gas. Now, the gas, when you put it back in, is it— it's dry gas, so you're putting it back in basically stripped of any of the richer components that come up with it? Through the chair, yes, that's generally correct. We can sell liquids, hydrocarbon liquids, oil, down the pipeline, and so We process the gas usually using refrigeration and cryo treatment to strip out as much liquids as we can.

Not all of those liquids are stable enough to go down the pipeline. Some of those have to be reinjected into the reservoir. But the heavier liquids that are stable at atmospheric pressure, we send down the pipeline. We blend it. About 20% of the oil that we send into the Trans-Alaska Pipeline actually comes to the surface as gas and then condenses out and is recovered from that gas.

Yeah, I mean—. Go ahead. Senator Kaufman. Yeah, just curious, so that's not shown in the gas production wedge. I guess that's shown in the slice of pie that's oil?

That's correct. Okay. All right, yeah, just interesting. A lot of work to produce a little bit of oil. Thank you.

Thank you, Senator Kaufman. Please proceed.

So what I'd like to do now is, as I said, run through each of the specific gas resources that potentially will be selling gas into Phase 1 or Phase 2. And when I talk about the gas resources on the North Slope, I would suggest that you think about them as a spectrum from fairly straightforward to quite complicated. And so here's what I mean. On the one hand, fairly straightforward, you have fields with a single owner and without a whole lot of oil production. Then there— and that's North Star and Endicott Field, and they have substantial gas resources.

A little bit more complicated are fields with maybe two owners, like Point Thompson has two owners, Hilcorp and Exxon.. And more complicated reservoir fluids that have, you know, it's a retrograde condensate, we'll talk about what that means, and requires a higher level of reservoir management. And then on unfortunately the very complicated and complex side, you've got Prudhoe Bay, which has 3 owners, so harder to get 3 to agree than 2 than 1. And it has a lot of oil production, and that gas cap is important for the oil production, and as I said, we strip liquids out of the gas. So Prudhoe Bay gets quite complicated.

And so the way that we think about it at Hilcorp is, for Phase 1, let's focus on the simple, straightforward gas resources, and we will, over time, work our way towards the larger, more complex gas resources at Prudhoe Bay. Okay, just to kind of think about how these things sit on the spectrum as we talk through them. So I'll start with Northstar. Hilcorp is the only owner of Northstar Island. Northstar makes about 5,000 barrels of oil every day.

We produce about 600 million cubic feet of gas every day at Northstar. We handle it, we compress it, we re-inject it back into the ground.

That's about 3 times as much gas as Anchorage uses every day. And then water production here is relatively minor. It's about 3 times as much water as there is oil produced. Okay, so in the grand scheme of things, 5,000 barrels of oil per day is on the North Slope, not a particularly large field. There are single wells that make that much oil.

Okay, so North Star is very much towards the tail end of its life. It has high operating costs because because it's in Arctic, in the middle of the Arctic Ocean, makes a little bit of oil and a whole lot of gas. And Hillcorp is the only operator. And so this was our first, let's say, targeted gas resource that we wanted to sell because it is towards the end of its life. And when you sell it, there is a cost of the oil production, but the gas resource at 800 billion cubic feet is, we would say, significantly larger than the remaining oil resource.

We would need to work with AOGCC and get their permission to sell this gas resource. I misspoke in front of, I think, the House Finance Committee and said we didn't need their permission. We do. But I'm very confident that we would get to agreement with AOGCC to sell the North Star gas. And North Star is one of the fields where we have a signed gas sale precedent agreement with Glenfarn to supply gas for Phase 1.

Moving on to Endicott Field, again, single owner, only Hillcorp owns Endicott. Not as large a gas resource, about 500 billion cubic feet. But again, here we produce about, I think today it's actually over 7,000 barrels of oil per day. We had a very successful oil-focused drilling season this last winter. And we produce about 450 million cubic feet a day of gas.

That's about twice as much gas as Anchorage uses every day. Endicott is not one of the fields that we have a GSPA signed for, and there's a technical reason for that. Endicott, you know, has a relatively small gas pipeline that is used to sell a little bit of gas to the Badami field to today and wouldn't be able to supply the volume of gas on a daily basis that the pipeline operator wanted for Phase 1. And so that's something that we would look at probably later on or to supplement existing sales volumes. Okay?

So Endicott and Northstar, fairly simple, fairly straightforward, not a lot of oil production to be lost if the gas resource was sold.

So moving on to Point Thompson, I think most of you are aware that Point Thompson has a long history. There have been some development agreements with the state. And there are two owners. Exxon owns about 60%. Hilcorp owns about 40%.

So now we're getting a little bit more complicated, because Hilcorp and Exxon need to agree on how to manage this large resource. And it is a large resource. It's 6 trillion cubic feet of gas recoverable, is what ARGCC estimates.

Today, this field only makes about 4,000 barrels of oil and, I want to say, 60 million cubic feet of gas. I'm pleased to report that Hilcorp has drilled the first well at Point Thompson in about 10 years. It's been a 2-year project, most of the activity taking place this past winter. And within the next couple of weeks, we'll be bringing online the largest and most expensive well that Hilcorp has ever drilled, and that should fill up this facility and maximize the oil and gas production from the existing facilities. So we'll be moving— after we bring on this new well, we'll be moving 10,000 barrels of liquid and 200 million cubic feet of gas per day from only 2 wells, 2 productive wells.

So the way that Point Thompson works is we produce the gas to the surface, we then strip out the liquids from that gas and re-inject what we call lean gas back into the reservoir to maintain the pressure. And Point Thompson is a retrograde condensate. And what that means is that in the reservoir at about 15,000 feet underground, you got very high pressure and very high temperature and that reservoir fluid is a gas. As the pressure drops, that gas turns to liquid. And so the pressure can drop in a couple of different ways.

If you produce the gas to the surface, now Naturally, the pressure is lower, and so in our separation facilities, a lot of that liquid falls out, and we're able to sell that very valuable liquid down the pipeline. Alternatively, if you don't reinject the gas back into the reservoir, the reservoir pressure itself will drop, and the liquid will actually condense in the reservoir, turning what is currently a gas reservoir into partially an oil reservoir. And then obviously, your development options for an oil reservoir look a little bit different than those from a gas reservoir. So you can manage these kinds of reservoirs as a gas cycling operation where you produce the gas, strip the liquids, and reinject the gas, or you can produce the gas, strip the liquids, sell the gas, and then you're going to have to focus more on oil recovery from the reservoir in the way that you drill your wells and manage that facility either through waterflood or in-water injection, okay? So a little bit more complicated, reservoir management here.

And it's— Point Thompson is fairly early in its life as far as development goes, right? There's only 2 producing wells. They're wildly productive. We're very enthusiastic, but it's exceptionally remote, which makes it very, very expensive to develop. So, you know, we see great things ahead for Point Thompson.

We intend to continue drilling and developing this field. And again, today that's 100% focused on oil sales, but obviously we handle a substantial volume of gas.

Okay, a little bit of a commercial here, but there's some pictures on this slide and the next slide showing what we did at Point Thompson. When we acquired assets from the Italian oil company Eni a couple of years ago, one of those assets was Spy Island, and on Spy Island there was the Doyon 15, which is a very large, highly capable drilling rig. We didn't have access to that rig until we acquired Spy Island. Once we got our hands on that, we saw the opportunity to use that rig over at Point Thompson and drill these very challenging wells. So that was pretty cool.

We, uh, we took the rig apart into two pieces for transport. We moved it onto this very, very large barge that we shared with Santos. And then we barged it over to Point Thompson, offloaded it. You can see that red bridge there we had to custom build for getting the rig off the barge and onto our drill site. So a lot of work went into that just to get the rigs there, a lot of logistics.

And then finally, here's our kind of a shot of our drilling operation this winter. A lot of activity out there at Point Thompson.

Senator Steadman. Thank you, Mr. Chairman. Before we get off onto other things like Prudhoe Bay, we've had testimony here about the reservoir at Point Thompson not performing as expected, and it may need additional drilling and higher capital costs going forward. Can you help us clarify any of that? Through the chair, I certainly can.

So as I said earlier, Point Thompson only has one producing well. And I think it's important to clarify, all of the development at Point Thompson to date is focused on oil production and oil recovery. So one producing well, it makes about 6,000 or 4,000 barrels a day. We're drilling another well, it's going to make 6,000 barrels a day. I don't, you know, I would say the reservoir at Point Thompson has performed exactly as expected.

It is a complicated reservoir fluid. The reservoir itself, the rocks are very high quality, akin in many ways to the Prudhoe Bay rocks, which are world class. The reservoir fluid is complicated in that it is this retrograde condensate, but you know, We manage other retrograde condensate fields around the country. So no, I wouldn't say that the behavior of the reservoir has been any different than really what was expected. It certainly does need additional development, and that development will take place, frankly, regardless of whether or not a gas pipeline is built.

This is a good oil resource that we intend to develop and exploit. Senator Steadman. I might come back with another question, but I'll yield the floor. Thank you, Senator Steadman. Senator Kaufman.

Thank you. I think for the folks at home, we ought to explain what retrograde condensate is. It sounds a little bit like rocket science when we start talking retrograde.

Through the chair, I'll do my best. I don't have a phase diagram to put up here. A retrograde condensate is simply a fluid It's a hydrocarbon that is a gas in the reservoir, but is mostly oil when it comes to the surface. And so it simply means that you need to manage your reservoir more carefully and thoughtfully than you otherwise would. If you don't pay attention to the way that you maintain your pressure, either through water injection or gas reinjection, or eventually water flooding the reservoir, you could end up with suboptimal recoveries.

And that's a big part of our responsibility as the operator, is to make sure that we maximize oil recovery for, you know, the state, our working interest owner partners, and of course our own economic interests. Senator Kaufman. Thank you. And just while we're on that subject, I guess, um, you know, AOGC's remit is to assure, you know, maximum total value recovery And— but the operators, they have the— really the same concern. I mean, you're trying to maximize total value as well.

And so when we were discussing whether or not a resource is available to pull gas off of it versus oil, could you just explain a little bit from an operator's perspective of the two curves that you're looking at of the value of the oil production versus pulling gas off of it, and just how those considerations work inside the— inside your operations, what you're considering. Through the chair, yeah, I'll do my best. As we think about managing these reservoirs, I think this is true for Point Thompson just as much as it is for Prudhoe Bay, Endicott, and Northstar. The oil is the much more valuable fluid. The oil is what pays the bills, and so all of our development activity is focused on maximizing oil production.

To the extent that we have the opportunity to sell the gas resource, you know, I would say that the price of that gas, the way that we negotiate around pricing that gas, is basically priced to— it's priced according to the value of the oil production associated with it. So for example, if you were to find a field that is only gas, well then the price you need for that gas has got to be reflective of the cost to develop the field, right? If you find a field— if you have a field like Prudhoe Bay where you produce oil and gas, and I I think everybody understands that if you were to sell all of the gas and behave irresponsibly to sell all of the gas and not manage the reservoir through, you know, water injection and kind of making that reservoir whole, you could, you know, suffer a loss of oil production, okay? And you would have to price that gas to, you know, basically recover the value of the lost oil production. And part of what we do as the operator is make sure that we balance those things and try to find, ideally, let's say a third way where we can maintain reservoir pressure while still selling some volume of gas.

And there are opportunities to do that, right? And that requires some investment, but I— usually that is like the happy middle ground between just selling off all the gas— and not selling any of the gas, is you can sell some of the gas and overcome that loss by investing in additional water injection to maintain that reservoir pressure. Senator Kaufman. Thank you. Thank you, Senator Stidman.

So we've got a proposal to build an in-state gas line, and my understanding is Hilcorp's gonna sell gas at the the tailgate or the wellhead or what have you. And we need to clarify our deductible operating and capital costs because it goes against our oil revenue, which we all understand is where the value is. So can you help me differentiate when that title of that gas— where it's going to change hands and where the separation of of deductible capital and leasehold expenditures are? Through the chair, yeah, I think I can.

The reason that we have structured our agreements on selling gas the way that we have is to minimize the cost to Hilcorp, the upstream operator, to sell that gas, right? So I'm not quite sure what the cost of building a gas pipeline and a gas treatment plant are, but none of that cost will be paid by Hilcorp. Our only upstream cost will be that connection into the pipeline, which will be right at, as you say, the tailgate of our plant. And I think that's consistent with our business model. We are an upstream oil and gas company.

We are not a pipeline company. We are not a gas treatment plant company. That's That's not our business. It's not our expertise. Does that answer your question?

Yes, so if I can interpret that, then the cost of the gas treatment plant and the feeder line up to Northstar will be a non-deductible expenditure against our production tax, and that would Those expenditures then would fall into the midstream or the pipeline. Through the chair, that is correct, to the best of my understanding. And I would add that the cost of the pipeline out to Point Thompson also falls into that same midstream category. That does not go against upstream lease expenditure. Thank you.

Thank you, Senator Stidman. Senator Kaufman. Thank you. And as we discussed earlier, the gas that you're putting back downhole, that, that has already been cleaned up to where it's pretty much methane and the CO2 is not an issue. In other words, if we're shipping volumes of gas, you don't have much treatment in order to get it to the quality that it needs to be to go down the pipeline for consumption.

Through the chair, I'm going to have to defer to our friends at Glenfarm on that question. We don't treat the gas to a state where— well, I guess I simply don't know. If you're sending gas down a pipeline, it's got to be good enough to go to people's homes, is what I understand. You know, look, we use very expensive metallurgy and things like that to manage whatever is in the gas as is. We strip out hydrocarbon liquids that have value, but that's all that we take out of the gas.

So that would say that you're not gonna be building infrastructure to further treat that to get it into that condition. So again, that wouldn't be in your remit as the provider. So you see that at that custody exchange from Hilcorp over to the gas line, that that's not going to be anything that you're gonna be building need to, to write down as a construction cost or investment cost. Through the chair, yes, that is correct. Hillcorp will not be spending any money on additional gas treatment to remove whatever impurities or CO2 or anything like that.

Thank you, Mr. Seljay. Please continue.

Okay, um, finally we come to Prudhoe Bay, which as I said is the most complicated complicated. So we have 3 owners at Prudhoe Bay. Hillcorp being 27% and the operator. And I think everyone understands, but it's worth saying anyway, in order for something to happen at Prudhoe Bay, all 3 owners need to agree. Right?

So that makes things, you know, let's say take a little bit longer. We need all three owners to agree. You have to have unanimous consent for anything that happens. And so the working relationship between the owners is very good. We try to be a good partner on the operating side, but everybody has to agree.

The gas resource, as everybody knows, at Prudhoe Bay is tremendous. 22 Trillion cubic feet of recoverable gas by the AOGCC's estimate. You know, the oil production, as everybody knows, is also tremendous. 13 Billion barrels of oil have been produced so far, and we still make about 250,000 barrels of oil every day. With that oil, we produce 6 to 9 billion cubic feet of gas.

That's as much as Germany uses in a day, right? So massive gas processing, treatment, and compression plants. Up on the north slope. That picture, the photograph, shows our, uh, our central gas facility. There's a gas processing facility that strips the liquids out, and there is a compression facility.

That's the two— the treatment plant and the compression facility. Those already exist, um, and handle that 9 BCF of gas every day. And then, as I said on one of the first slides, we handle 10 times as much water as we do oil every day. Right, so we're already moving a lot of fluids and we have, you know, about 1,400 people up there working across, let's say, 11 major facilities at Prudhoe Bay. We do not have a gas sale precedent agreement in place for Prudhoe Bay because we feel like we can satisfy all of the gas needs for Phase 1 from other less complicated fields, specifically Northstar, and we're working on one for Point Thompson.

Senator Kaufman. Thank you. I was just thinking when you were talking about the volumes and all that, I got thinking of the turbine generators spinning and, you know, the compressors and everything that's happening to clean up that gas and push it back downhole. Do you have any idea of the net efficiency gain that you'll get in your operations from, from not having to do that? And I know you're not talking about gas from Prudhoe, but just in any instance that we're talking about, the net gains in efficiency and how that might help your operating costs and your ability to produce.

Yeah, through the chair, unfortunately I can't really answer that. Part of what makes Prudhoe so complicated is that Answering a question like that, which would seem fairly simple, is actually very complicated. We need a lot of surface modeling work and a lot of subsurface modeling work to look at what would be the outcome of any particular action. So if you talk about, for example, what would happen if we pulled 2.5 billion cubic feet of gas a day off of Prudhoe? We have the wells, we don't have to go drill more wells.

We have the gas handling facilities. We don't have to build additional compression or things like that. What would be required would be some very thoughtful and careful reservoir management. We're already doing those kinds of activities, and I can't tell you what exactly would be required. That's a lot of work for quite a few subsurface engineers and surface engineers to figure figure out what are you going to do to manage this process of taking the gas to market.

But it's significant, significant work. Senator Kyl. Thank you. To follow up on that topic, I mean, it doesn't sound like at any point you're going to stop compressing and reinjecting gas, right? You just take some of it off because if you— I don't have this Prudhoe slide up.

If you're making 6 to 9 a day and you're allowed to sell 3.5, you're not going to store the rest on the surface, right? Do you think that it's likely to bring about cost savings on the lease or just sales? Through the chair, you're right, we would not stop compressing and reinjecting the gas. I don't think it would bring about Again, now I'm kind of guessing. I don't think it would bring about cost savings on the lease.

I think it would bring about gas sales. There would probably be some incremental cost, you know, operating cost. I can't tell you what that would be though. We'd have to— like I said, we've looked hard at Northstar. We're looking hard at Point Thompson.

We simply haven't done the work yet on Prudhoe to know how that would shake out. That's fair. Thank you, Mr. Chairman. Thank you, Senator Kiel. Please proceed.

Mr. Chairman. Oh, Senator Steadman. I need a little bit of help here. We've got this proposed Phase 1 project that's got some gas sales precedence agreements lined up to produce gas for Phase 1. And they're asking for concessions to help with the cash flow to make it economic.

On property tax, but then when we talk about Phase 2, Phase 2, which is the major volume with the conditioning plant and the liquefaction plant on the south side, that gas has gotta come from Prudhoe. And if there's no gas sales precedent agreement with Prudhoe, I'm having trouble trying to connect Phase 1 and Phase 2 both at the same time. Could you give me an idea, help me with that, and the difficulty or the ease of putting together a gas precedence agreement on Prudhoe with the 3 different operators, or 3 different owners, I should say. Yeah, through the chair, certainly. Glenfarn has certainly been very vocal about their desire to get a gas sale precedent agreement signed with Hilcorp for Phase 2 gas.

And what we've told them is we're perfectly willing to enter into those discussions. We want to finish setting up GSPAs for Phase 1. We think we're very, very close to that. Once we've done that, and they have a FID Phase 1, we will pivot our internal resources, which are limited, to doing the work that is required for the Phase 2 GSPA. So we can and will do the work.

We just haven't begun that yet because we've been focused on Phase 1, gas sale precedent agreements. Understatement. Yeah, that makes it— I guess the chicken and the egg, you know, when we're dealing with Glenfern, trying to figure out on the concessions for both Phase 1 and Phase 2, when Phase 1 is so challenging economically— someone argue it's uneconomic and could only get to be economic when you do Phase 2, which is substantially larger investment of possibly an additional $40 billion.

The other concern that some of us have at the table is when you take Phase 1 and you sell it to Tailgate or you sell it at Northstar, the edge of your lease, or over at Point Thompson, it's pretty clear where that, you know, calculation is as far as a transfer of title or ownership where the operating and capital leasehold improvements get expensed or pushed against our value of our oil. We understand that and we can figure that out. But when we look at Point Thompson, our consultant, Nick Fulford has cautioned us that it's highly likely that there may be a desire to retain ownership throughout the gas stream all the way to market, pick Tokyo or Korea. And I think, and there's netbacks all the way back. And that puts the state in a different position.

Not as clear tax-wise and calculation-wise as Phase 1. So I was wondering if you can help me with that struggle.

Through the chair, what I can tell you is that Hill Corp has had internal discussions about how far through the value chain we want to own the gas. And the conclusion that we came to is we want our ownership to stop at the lease line. Okay, fair enough. I understand. I think that answers the question for Hilcorp.

Thank you, Senator Steadman. Senator Kaufman. Thank you. Mr. Chairman, the gas sale precedent agreement, so what's the— trying to— I think we should all have an idea of like where that is. If you saw the diagram of, well, this is step 1, how many steps are there?

How big of a step is it to get where you go from that to an actual agreement to sell? What does that process take, or what do you think it might take in view of our current situation? Through the chair, this is the first one of these I've done, but I think it starts with a gas sale precedent agreement, and then it goes to a gas sales agreement. I don't know if there's another step beyond that. So I think I would respectfully direct you towards Glen Farn to get kind of that— what exactly does that process— but that's my understanding.

GSPA, then a gas sales agreement, which I think is the binding agreement. Senator Kaufman. So in context, so you've gotten approvals from AOGCC, Alaska Oil and Gas Conservation Commission, And so with that, then you're saying, okay, and here's the framework of what we'll put together for the sale. These are kind of the rough attributes of what the agreement would look like. Then you have the step to actually go to a contract that would liberate that gas at a price to go into the line.

I'm guessing, but just to kind of put it in context with the approval to remove gas from on the reservoir coming through the commission, and then that agreement with the carrier from the producer to the carrier. And then it sounds like there's one more step, but we can ask more about that. But I just wanted to kind of frame it up in the sequence of events that have occurred and what is yet to occur as best we could today. And through the chair, I guess one thing that I would— I want to make clear, I received a letter from AOJCC today informing me that I most certainly do need their permission in order to sell gas. So I want to make sure that's clear.

We do not yet have that permission for Northstar. We haven't asked for that permission from Northstar. I'm totally confident that we can get their permission, but we do in fact need to make our case there, and we haven't done that yet. Senator Kaufman. Thank you.

That's consistent With what I heard from them with regards to Northstar, that the others, you know, the other two cases are good, but Northstar was— that process needs to be run, but that the parameters are well known because of the maturity of the reservoir. Thank you, Senator Kaufman. Mr. Sojay, please continue. All right. Those are the end of my slides on— the North Slope.

And so I have a few slides here on the Cook Inlet aspect of our business as well. Uh, Hilcorp operates all but one of the gas-producing fields in the Cook Inlet Basin. Uh, we supply substantially all of the gas for Southcentral Alaska. This is a very important business to us. Um, we spend $400 to $500 million every year to ensure that we deliver the gas volumes that we have contracted for and continue to, you know, be very active here.

We have invested substantially in infrastructure and equipment specific to the Cook Inlet. We own a jackup drilling rig for offshore development. We own two onshore drilling rigs We run 2 rigs at all times throughout the winter and the summer. We are planning to drill over 25 wells in 2026. We're drilling all over the inlet, fully developing all of our leases.

And then slide 13, I want to just give an update on our 2025 program. 2025 Was our most successful drilling program to date. For gas in the Cook— well, I say, let's say in the last 6 years since I've been in the seat. It's most successful, we've been over a 90% success rate for our drilling, which in oil and gas is pretty good. As a consequence of that, we have been able to sell a little bit more gas than we had contracted.

So we specifically, we sold an extra 500 million cubic feet to NStar this winter when it was really, really cold, and we were able to partially extend our contracts with Matanuska Electric after their— the end of their contract term in 2029. And, you know, really appreciate Matanuska Electric working with us to, let's say, accelerate some of their payments into the present, which gives us the funds that we need to continue to expand our drilling activity and give us the opportunity to supply them with gas 3+ years into the future. So we appreciate them working with us on that. Senator Kaufman.

Well, we've got more on the Cook Inlet, I see. So when we get to the end of the Cook Inlet slides, I'd like to ask a few questions. Thank you, Senator Kaufman. Please proceed. Okay, so a lot of words on this slide, but what I would say here is that, look, the Cook Inlet Basin is a very challenging basin in which to operate.

It is very mature. It is very high cost. We continue to have the activity levels that we do because we plow substantially all of our revenues back into the business. We are always pushing to drill more wells, to have a higher level of activity, and despite all of that, I want to, you know, repeat the same thing that I've said for years, which is come the end of 2029, there is not going to be enough gas to meet all of the needs for South Central unless there is another source of gas supply in the Cook Inlet. And so the obvious point there is that we believe the gas line from the North Slope is a tremendously important piece of the overall Cook Inlet Basin gas supply picture.

You know, we've done a lot of modeling internally looking at all suppliers of gas, all buyers of gas, looking at storage and how that all plays in. I'm happy to walk any of you through through that offline if you're interested. It gets pretty detailed and complicated, but it just continues to reaffirm the same picture that come the end of 2029, the Southcentral Alaska community needs to have another source of gas supply outside of just the Cook Inlet production.

On, on Glenfarn building the line, Prior to them coming on the scene, was there any plans by anyone to assure that South Central was going to get gas from the North Slope?

Through the chair, I'm not sure. I would direct you to the utilities, Senator. I, for one, I'm not exactly sure when when Glenfarn came on the scene and what their thinking was as far as gas supply after 2029. Some of the utilities, some of our customers, NSTAR specifically, has contracts extending out until 2033. And so I think there are some different thoughts from the different utilities about how they think about gas supply, but I'm not sure I can speak to that.

Thank you. Senator Steadman. A couple things we need to cover here, I think, is the concern in the rail belt for gas if it's, you know, starts running dry on, on in '29. In the event that this in-state gas line doesn't get constructed or gets substantially delayed, the other potential import facilities, I think there's a couple of options or 3 options that the region is looking at. So we need to cover that, and then, Mr. Chairman, I think we need to cover some time to learn what's the inevitable outcome at Cook Inlet if we do have an in-state gas line that supplants Cook Inlet and/or we have an imported LNG facility that facilitates, you know, gas supply for for the rail belt, who and how much exposure do we have for reclamation of the infrastructure that's put in place in Coquille?

And that possibly should also be directed to DNR. I think they're the ones from the state's perspective that's responsible.

Senator Kaufman. Thank you. On that front, And this was coming to mind when we were listening to AO GCC talk about their remit, which they're concerned with pools. So, but it sounds like we need more information on who's looking at the big picture. And I don't know how an impending gas line coming down is probably going to suppress the will for some drilling activity in Cook Inlet.

If the thought is that that will soon displace any demand. I know the resource is in decline, but I think we need to have a clear line of sight on how we're managing that so that we don't prematurely devalue production in Cook Inlet and can create, you know, that liability there. There's decommissioning costs. There's also the threat that we somehow folks don't want to drill because they don't think that the gas will be needed and maybe we have some opportunity issues that come out of all that. So I think we need to talk with DNR about this big picture management of the pipeline as it affects Cook Inlet because the constitutional remit to optimize the development of resources, I think that's really coming into play.

It's a complexity that I don't know that we— who do you point to to assure that that's managed? I think we have questions on that.

Please proceed. Sure. So slide 15 here shows the level of drilling activity that Hilcorp has undertaken for the last, I guess, 14 years that we have been in south-central Alaska. Drilled 192 wells over that time. Period, which is significantly more than all other producers combined.

So that just echoes the same point that I've been making. We are and have been very active. And this is a different perspective on that. This shows the amount of gas supplied from all producers over the last, let's say, 10 years. And you can see Hilcorp's production is in green, and it's been stable right around 50 billion cubic feet per day.

And all other producers' production has basically been declining off. And that's because Hilcorp has continued to be very, very active in the Cook Inlet, while most other producers have not. A shining exception to that, I would say, is Hex. So we should all, well, all of us in Southcentral Alaska should appreciate Hex for, you know, stepping up and drilling a couple of wells each year for the last few years, and again this year. They share the jackup drilling rig with us, and so it's good to see them active.

But this is kind of our problem, right, is there's just not enough activity going on.

I'll wrap up with this slide. Senator Steadman. Years ago we had a Cook Inlet revitalization program going on, and we put several hundred million, $200-300 million a year into it in credit. And we struggled year after year after year to try to turn Cook Inlet around. And it seemed like once we let the price be adjusted a little bit, all of a sudden there was lots of gas.

And we went on for another decade. So is this a gas price constrained Cook Inlet or lack of gas in Cook Inlet?

Through the Chair, I mean, that's an interesting question. What is considered by the SEC to be recoverable reserves are reserves that are economically recoverable. So, you know, to use a silly example, if gas was $100 per 1,000 standard cubic feet, would you find more gas? I suppose you would. At some point, though, you run up against parity with other energy sources.

So I'm not exactly sure what the price of diesel is on an energy equivalency, but I think it's around $20 or something, $20 per 1,000 standard cubic feet for a gas equivalency. So, you know, I'm hemming and hawing to answer your question a little bit. As far as Hilcorp is concerned, substantially all of our volumes are sold under long-term fixed-price contracts. And so those are the prices that we're working with. I would say 90-plus percent of our gas is sold under long-term fixed-price contracts, kind of in the sub-$9 range.

I don't think it's right to say that there would magically be a whole lot more gas that would show up if the price was substantially higher. I think it's really a question of the amount of equipment and people available to execute the work. We have to, you know, we generally prefer not to own our own drilling rigs, but we own all the drilling rigs we use in the Cook Inlet because there are no services available to provide those drilling rigs. When it comes time to find crews, it's difficult to find drilling crews to work in the Cook Inlet because, and that's why we, you know, we have a very stable 2-rig program because we can keep consistent crews running. If we wanted to pick up a third rig, we would need to pick up a third full year of drilling, and we can't do that.

We don't have the prospects available to us to do that at this time. So it's really more about the availability of people and equipment than it is about gas price at this point in time. And I think that's been the case for the last 4 or 5 years. Thank you.

Thank you. The Cook Inlet, the big picture Cook Inlet, there's the production, but then we also have storage. And there's CNGSA, Cook Inlet Natural Gas Storage. And that's been a bit hampered. I think there's two of the wells are having problems.

And so they're— going back to the idea that we've got a big picture that we that we need to get to the bottom of as we're working enabling the gas line, that question of what the transition plan looks like and how that plays into SINC. So not really a question for you about that, but unless there's anything that you want to note, but it's just another piece of the puzzle to maintain that high demand. You need to be able to flow when folks are really needing the gas. I guess when we talk with NSTAR, maybe we'll go into that a little bit as well. Thank you, Senator Kaufman.

Mr. Soji. Yeah, through the chair, I'll take the opportunity to talk my own book here a little bit. Hillcorp has developed several gas storage facilities, and Pool 6 is commercialized, and we are working on commercializing other gas storage facilities and developing some more. We've done quite a bit of work looking at how much gas storage the Cook Inlet Basin needs, and we think it's substantially more. And so we are pursuing several additional gas storage projects because we think the market has to have it over the next, I don't know, 5 to 10 years, let's say.

So I think this is my last slide. I'm just reiterating a couple of things I've already said. Hillcorp deploys over $4 billion each year on behalf of ourselves and our partners. We're really proud of the work that we've done on the North Slope in tripling the production at Milne Point, applying new technology as far as extended reach horizontal drilling and polymer flooding. We think that we have decades of additional development in front of us across the the North Slope.

And, you know, there's my— one of my favorite slides, the Hilcorp wedge there, showing, you know, that we've really stepped in to stabilize oil production from the assets that we operate to the great benefit of the state of Alaska and our working interest partners.

So—. Thank you, Mr. Chairman. Sergey, on your previous slide, previous comment, can you help me a little bit more with Cook Inlet needing significantly more gas storage? I look at slide 16, it looks like production seems to be below demand.

Which gas?

Through the chair, storage— the senator is quite right. Storage does not solve a gas supply problem, right? What storage allows you to do, whether you're importing from LNG or you've got a pipeline available to you, storage becomes very important because you need— well, let me describe two scenarios. If you have a gas pipeline and an LNG export facility, facility. That's where we all hope we end up, right?

Uh, you need extensive storage facilities in that scenario because if you have to take your pipeline down for maintenance or an emergency, you want your LNG export facility to be able to continue to manufacture LNG. So you'll pull gas out of storage to keep your facility working. Conversely, if your LNG export facility has to go down for maintenance or some problem, You want your gas pipeline to continue delivering gas, and so you need to fill your storage in those situations, right? So it's kind of acts as a buffer, an operational buffer between the pipeline and the export facility. So that's why storage is important if you've got a gas pipeline from the slope.

If you don't have a gas pipeline from the slope and you're meeting South Central Alaska gas demand through LNG import, those LNG ships, offload at very high rates, and that gas has to go somewhere. They offload at too high a volume for it to be taken into everybody's homes and businesses. So that gas goes into storage, and you want to deliver year-round, but it's probably going to be cheaper in the summertime. So if you're delivering in the summertime, storing it, and then pulling it out at very high rates in the winter, and so that's why storage is important in that scenario. It's kind of— I guess that was my point, and I think, you know, you make an important point as well.

Storage doesn't create additional supply. It simply helps you manage the available supply better.

Mr. Chairman, thank you. That's extremely helpful. Can you— so you talk about— I don't want to put words in your mouth, and I can't remember exactly whether you said interest or investment in additional storage. Toward which scenario of those two scenarios are you interested or investing? Which one did you say?

Through the chair, it's the same. So the, the path forward on storage is the same regardless of which of those scenarios comes to pass. In either scenario, you need that storage resource available to the market, and so that's why we are investing in additional storage resources. Just one more follow-up. Is there a volumetric difference?

Is there a quantity difference? Through the chair, I'm not sure. I don't know. Um, yeah, fair enough. Thank you.

Thank you, Senator Kaufman. I just wanted to pile on that a little bit. There are kind of 3 cases. So there's, there's bought gas coming in, getting offloaded. There's slope gas coming down, and in both cases you have that kind of dampening effect that you're looking for to cover for either big volumes coming in or disruption in supply with any supply interruption.

But in our current situation, what the storage is providing, what I was speaking of earlier, is kind of that peak demand, because you can bank during low demand times and then you can serve the peaks that cyclical effect. So no, it's not like having a bigger paycheck, but it is like putting some of it in the bank so that you can use it when you need it. Further questions? Senator Merrick. Thank you, Mr. Chairman.

Can you please give us an update on the import facility?

Through the chair, respectfully, I'm going to have to decline. Hillcorp does not have an import facility I'm aware of. 3 Proposed import facilities, but I guess I would ask those entities to speak for themselves. Thank you. Any closing comments, Mr. Soji?

That's all for me. Thank you. Okay. Thank you. With that, we'll take a brief at ease, get ready for the next presenter for 5 minutes.

Call Senate Finance Committee back to order. We're dealing with the governor's Senate Bill 2001, the gas pipeline. The next presenter this afternoon will be ExxonMobil. They are online. The president of ExxonMobil Alaska, Todd Griffith.

Please identify yourself and proceed with your presentation.

Good afternoon, Mr. Chairman and members of the Senate Finance Committee. For the record, my name is Todd Griffith. I just want to stop for a minute and make sure you can hear me okay. We can hear you loud and clear, Mr. Griffith.

Excellent. I am president of ExxonMobil Alaska and responsible for North Slope natural gas sales. My remarks will be brief, but I should start by saying that while we are not the operator of either Prudhoe Bay or Point Thompson, we remain actively engaged not only providing a significant portion of the continued investment, but also by providing our extensive engineering, project management, and drilling expertise to assist with development of these assets on the North Slope. As we have previously stated to this legislature and prior ones, ExxonMobil has and will continue to make this gas available to any project under bilateral mutually agreed and commercially reasonable terms. In fact, over the years, ExxonMobil has entered into a gas sale precedent agreement with EGDC several years ago, and we currently sell North Slope gas to other oil developers, including Santos for the Pica development.

Additionally, as announced by Glenfarn earlier this year, ExxonMobil and Glenfarn have agreed to a gas sale precedent agreement for the Alaska LNG Phase 1 project. And while we have a confidentiality agreement and cannot comment on specific gas sale terms, I can confirm that the precedent agreement addresses both gas price and volumes.

In closing, ExxonMobil is working to help make the AK LNG project successful. We are pleased to have completed a gas sale precedent agreement for Phase 1, and we are committed to working with Glenfarm to finalize the gas sale agreement later this year. And begin negotiating additional agreements for Phase 2. Lastly, ExxonMobil looks forward to the progress of the project. If completed, both the state of Alaska and ExxonMobil will benefit along with our partners.

And with that, I'll be happy to take any questions.

Thank you, Mr. Chairman. So we've been curious at the table here dealing with Phase 1, and I think we got a pretty good understanding that the sale is going to be at the tailgate or the edge of Point Thompson, what have you, the unit. But, you know, if we think back years ago when we had our consultant take a look at BP, Exxon, and Conoco and why they were in the state. We were told that Exxon was here for our gas, Conoco for our oil, and BP was in harvest mode. Now BP's gone, Hilcorp's taken their place, but then when we fast forward to look at this project and we secured Gaffney Klein as our consultant, and to help us look at this, and Nicholas Felford, he was a little, he cautioned us a little bit on where the gas is gonna be sold and by who, especially when we deal with Phase 2, which is Prudhoe Bay.

He said that, he told us he thought that the Exxon shareholders might get a little excited if the gas was sold at the wellhead versus taken through the, the LNG system that Exxon has as one of the largest traders and active companies in LNG. And, and from our perspective, the state's perspective, there's a— could be considerable tax and value difference to us also. So I'm kind of curious, Exxon's position, Mr. Griffith, if you could have that, where it was particular. We've got Phase 1 nailed down, that's at the edge of Point Thompson and North Star. But how about Phase 2?

Can you help us with that?

Through the chair, Senator, what I can tell you is that Exxon has no plan to toll the gas through the infrastructure. But I suppose in the remote case that we or another company did want to toll the gas, my understanding and my expectation would be that the DNR would establish a value for royalty purposes And the DOR would do the same for tax value. You know, I— on your point about who is here for oil and who is here for the gas, what I can tell you is ExxonMobil is in Alaska for both the oil and the gas, anything that is commercially viable. But we understand your concern, and what I can just tell you is we have no plans to to hold the gas. Our plan remains to sell the gas at the wellhead.

So one of the concerns we have, if I could, Mr. Chairman? Yes. One of the concerns that we have is, you know, Glenfarm, the less expensive or the cheaper they can buy the gas from the producers, the better off they are. To make the pipeline economic. We the state aren't gonna make anything off of the gas line.

In fact, a little bit of property tax is gonna be waived, for lack of a better term, to try to get the project moving forward.

The royalties and the severance tax are up on the in upstream, which would be paid by yourself at Exxon and then Hilcorp and Conoco and Santos eventually. And we understand that, but we're a little concerned that if the gas price gets too low in the— at the tailgate or the wellhead or whatever, when you transfer title, leaves the state in kind of a tough peculiar position over the value. Can you help me with any of that?

Well, through the chair, Senator, what I can tell you is we're motivated to get the best possible price that we can for the gas, and for us that means the highest possible price, and that's part of our negotiation with the developers. And so, uh, you know, we, we want the highest gas price possible. We'll get the highest gas price we can that can be agreed to, uh, with the buyer. And, uh, and so, you know, all I can tell you is that our, our interests are, are aligned with the state in that, in that regard. Good, Mr. Chairman.

Yes, Senator Steadman. So the other concern we have is the previous project we were looking at, when Exxon would hold roughly a quarter, BP a quarter, Conoco a quarter, the state a quarter, we're all in alignment, each with roughly 25%, so everybody is gonna win or everybody's gonna lose or be penalized collectively.. And this particular project under those old statutes, there's virtually little to no alignment at all. And that creates some caution on the— from the state's perspective. In particular, when Exxon themselves is not at the table with the project.

Our— a lot of my colleagues biggest concern is the breadth and depth of Exxon and their skill set not being at the table to help facilitate the construction and management of this project, which is one of the biggest capital projects on the planet and certainly in North America.

Could you— help me with that at all?

To the chair, Senator, I do want to start by pointing out that there is a substantial amount of work to be done with the upstream development related to LFG Phase 2. There will be a— a very substantial expansion required at Point Thompson in addition to the other work that's needed at Prudhoe to tie in the gas to the pipeline. And we will bring our expertise without question to assist in the development of the upstream infrastructure. What I could also I would also just offer is that a lot of the work which ExxonMobil led early in the project has been handed over to the current developer. We and the partners spent $500 million of engineering to progress the concept, the pre-seed, and some would argue some of the fee deliverables for the project.

And so we have participated and provided that to the state when the state made the election to take over management of the project. And we look forward to supporting the state in providing a reliable, competitive supply of gas to the project.

Senator Steadman, if I could just— we've been cautioned by our consultant that when we— when the project like this goes to FID, it's extremely complex to bring everybody basically on board and marching in the correct direction. And the multiple facets and number of folks that have to come together. And I think as he referenced us, Exxon would bring in maybe a couple hundred people into a room on FID and try to get them all lined up so they can be successful execution of a particular project. And it doesn't seem that Glenfarn has that capacity. So there's some concerns there.

There's also concerns that have been expressed is when we look back at the past project that was worked on and led by Exxon, when we asked a question, Exxon would give us the answer or they would bring in one of the scientists or experts. And make sure that we understood what the issue was and answer the question. This project that we have at the table now is virtually the opposite. We have extremely high difficulty getting answers over time to questions and getting enough accurate data to run our economic models to gauge the risk level and potential pitfalls or where areas need to be worked on, on this project.

So for whatever that's worth, I guess, Mr. Griffin, it's noticeable, the difference in the process from several years ago when the questions would be answered at the table, including detailed modeling. Even if we didn't like the answer, we got the answer. And it makes it difficult and frankly risky for the state under this particular process. I just thought I'd mention that to you. Thank you, Senator Steadman.

Any additional questions for Mr. Griffith? Senator Kaufman. Thank you, Mr. Griffith. We were talking about the characteristics of Point Thompson and whether there's been some conflicting information about the anticipated performance of it. Do you have anything to add to that conversation?

Okay, to the chair, Senator, what I would say is, as my colleague from Hillcourt, Mr. Sojay, pointed out, Point Thompson is a retrograde condensate reservoir, which is a mouthful. But it—. In a nutshell, it's the opposite of, for example, with your gas grill in your backyard. The propane in the tank is under pressure and it's a liquid. You turn the burner on and it vaporizes into a gas, thankfully, and you light the gas and you grill your food.

The opposite is true of a retrograde condensate reservoir. And it's such that as the pressure drops, it actually liquefies rather than vaporizing like propane does. And so, and that has to do with where it is on what's called the phase envelope. But without going into those details, what I would say is what we found is the reservoir is as big as we had expected it would be. However, the well performance of the existing well has declined over time.

And that is a behavior that wasn't necessarily expected, but that we now better understand, uh, what is happening with the well. In the reservoir near the well bore. And that is why we have had to drill yet another well, one of a few reasons why we have had to drill another well at Point Thompson in order to fill the facilities. So we're continuing to learn every day more about the reservoir. It's large, but it is not easy to manage.

It is complex. The drilling is highly complex. The completions are, you know, in some cases one of a kind, and therefore we're learning every day. Senator Kaufman. Thank you.

Thank you. Further questions of Mr. Griffith? Senator Keel. Thank you, Mr. Mr. Chairman, Mr. Griffith, this morning we saw some modeling looking at the potential for gas offtake at scale to have possibly negative impacts on how much oil comes out of Prudhoe. I know the potential for gas offtake at scale probably increases what you're going to get out of Point Thompson.

Do you have concerns about the risk there, the potential for lost total revenue or increased cost to produce oil and oil— or gas liquids that we tax as oil anyway?

Or any of the trade-off concerns? Are those issues that you're keeping an eye on?

Through the chair, Senator, I may ask you to restate the question to ensure I heard it correctly over the phone. And I realize that the sound in the room sometimes doesn't come through clearly over the phone. Would you mind restating the question for me? Thank you very much. The question was about the concerns for tradeoffs, losses of recoverable oil or higher cost to recover oil from Prudhoe Bay with the start of large volume offtakes.

We saw the Department of Revenue model that this morning. Does Exxon have concerns about losses from that?

Thank you, Senator. As I'm on personal vacation this week, so I've not seen the report that you're mentioning. I will have to take a look at that when I get back. What I will say is anytime you blow down a reservoir like Crudo Bay, you can expect that there will be some oil loss over the life of the asset that is offset by the significant additional volumes, you know, monetized from the gas. And, uh, some would even say there could be a near-term uplift in oil production by virtue of debottlenecking the gas system by having another place to put the gas, and therefore you might be able to bring on some of the higher gas wells that are currently shut in because we're not able to process all of the gas through the facility.

Um, but certainly over the long term, you should expect some, and we would expect some, uh, some oil loss. That is all factored in to the economic analysis and the negotiations. In terms of greater complexity Purdue Bay. I'm not sure I can comment on how different or more difficult the oil development would be. It's not a— it's a pretty standard process at some point to blow down an oil reservoir, the gas cap on an oil reservoir.

And even we We are not blowing down all of the gas, as pointed out earlier. Some of the gas will continue to be reinjected into the, into the gas cap, as it will not all be consumed in rate by the LNG project. Hopefully that answered your question, but if not, I'm happy to try again. Mr. Chairman, just wanted to thank Mr. Griffith for his answer, and I hope I didn't give you the impression we had a report on the basin. We saw modeling of some hypotheticals.

Thank you, Senator Kiel. Further questions? Seeing no further questions, thank you. Senator Steadman. Mr. Griffith, I see on the posting here you're in Houston, Texas.

I was just wondering if that's vacation why you didn't go to Hawaii or somewhere coming out of Alaska. Through the chair, yes, my residence is in Houston now, and my vacation is at home to take care of a lot of overdue projects. So— Well, good luck on your honey-do list. Any further comments or questions? Seeing none, thank you for presenting to the Senate Finance Committee.

Our last presenter is also online. We have from ConocoPhillips, Barry Rhomberg. Mr. Rhomberg, please identify yourself and proceed with your presentation to the Senate Finance Good afternoon, everybody. Good afternoon, Chair Hoffman. First, I want to make sure you can hear me okay.

We can hear you loud and clear, Mr. Romberg. Excellent. Okay, so my name is Barry Romberg. I'm Vice President of Commercial and Midstream for ConocoPhillips Alaska. I've been with ConocoPhillips for a bit over 20 years, and for the past 27 years, been proud to call Alaska my home.

I'm dialing in today from Anchorage. Apologies for not being able to travel down there today. I had some competing things going on here in town. I'm here today to speak on behalf of Conoco Phillips Alaska, but for context, my direct responsibilities include gas sales, business development, land investment appraisal, and overseeing our ownership interest to Prudhoe Bay. The Trans-Alaska Pipeline and our North Slope pipeline system.

So thank you for the invitation to discuss ConocoPhillips' involvement in this project and the commercialization of North Slope gas. I do want to take a brief moment, and I know we're over time here, but there's something about today that's very historically important. And, uh, here we sit on June 8th, 2026, and exactly 57 years ago, on June 8th, 1969, the first LNG cargo was loaded down in Kenai. And that was a long time ago. That was actually the first LNG cargo that was sold in the world on a term contract.

And as all you know, that went to Japan for a nice long relationship there. At that time, that plant was operated by Phillips, which is obviously a predecessor to ConocoPhillips. So very proud of that moment in time, and we're very much supportive of bringing that business back to Alaska. As you well know, ConocoPhillips in 2026 and moving forward, our primary focus is continuing to grow oil production from the North Slope through exploration and projects like Willow. So while we have no plans to directly invest in this project, the AK LNG project, We do believe other companies are well situated in midstream and financial markets and investment markets to do so in an efficient manner.

And we intend to continue our support to the project by being a seller of gas to both Phase 1 and Phase 2.

You probably saw in the news here a couple of weeks ago, on May 18th, we announced our GSPA had been signed with Astar and Glenfarm. For Phase 1 supply of gas from our Prudhoe Bay working interest.

A lot has been said already about GSPAs. I think I'll kind of skip what I was planning to say there. Happy to answer any questions, but we believe this is a very key step in the process and a very normal step for a project of this size. We do look forward to moving into the gas supply agreement, which would be the binding agreement I think one thing I'd like to say to the committee is that while that— while the non-binding part of that might make you nervous, it is absolutely a very standard part of the process. There are dozens and dozens of agreements that need to be lined up and sorted, and it is very normal for those not to turn binding until everybody's ready for all of them to turn binding, which is when you have an actual project.

So we are, I think, in a good place to continue that moving forward. Thank you, Mr. Romberg. So, yeah, yeah. Do any members of the Senate Finance Committee have questions of Mr. Romberg? Senator Steadman.

Thank you, Mr. Chairman. I'm kind of curious, same with Conoco. Here, here you are as vice president of commercial for the midstream and And this is a midstream project and doesn't sound like you're interested in taking an equity position. And then I'd like you to clarify that. And also the issue of Phase 1 is being sold at the wellhead, for lack of a better term, I guess.

Is Conoco looking at doing that also in Phase 2 out of Prudhoe or carrying it through to the market. We'll be happy to answer those questions. Yeah, absolutely. So yes, my midstream responsibilities in Alaska do cover things like pipelines and tankers strictly on the oil side of the business. We do do a little gas sales on the North Slope, but, uh, you know, as a corporation, uh, ConocoPhillips is an upstream entity, and so all of our work and nearly all of our capital investment go into upstream activities.

We do have a legacy midstream business here that you're well aware of, and we think it's critically important that we continue to run that business very well as the primary cash register of the state that provides so much of the revenue. But as a company, as you've heard from my other colleagues, as an upstream entity, we do not intend to invest in the downstream part of this project. Uh, that's just not something that lines up for us, and it was a major part of the reason we left the project about a decade ago. And then in terms of where, uh, where we intend to sell the gas, it's the same for Phase 1 and Phase 2, and same as previous testimony. Uh, as an upstream entity, we sell the gas at the lease line, and, uh, transfer custody to the project developer.

That is how the gas supply precedent agreement is set up, so we intend that to be the same structure as we move forward. Senator Steadman. Thank you. And I have a question for Marie Evans. She's the tax counselor, ConocoPhillips.

If she could help us on the transfer of title on the gas and the upstream— not upstream, but the allowable leasehold expenditures both operating and capital, and where that debarkation point is when they're going to be selling at the wellhead, for lack of a better term.

Ms. Evans. Hi. Yes, Marie Evans, tax counsel for ConocoPhillips, for the record. Can you hear me okay? Yes, we can.

All right, Co-Chair Steadman to the Chair. I think you're asking about the, the definition of lease expenditure and how it interfaces with the definition of point of production for gas, if I'm correct. And when you're looking at whether a cost or an expenditure, whether it is capital or operating, is deductible. You look at 3 criteria, which are defined both in statute and regulation. The first being direct, the second being upstream of the point of production, the third being ordinary and necessary, and the fourth being that the cost does not exceed excluded.

Some costs, as you are well aware, are just listed as exclusions. For example, myself, I'm not a deductible lease expenditure by any means. So if we're looking at what costs are deductible for gas, one of the places we would go is to look at how do we define defines the point of production for gas. And when you look at 4355.900, those definitions for the point of production for gas were specifically changed and modified back when SB 138 was passed. And I believe if we were to walk through those definitions together, you would see that it is clear that the point of production for gas is like one of three locations, and it depends on where the gas was measured, separated, processed, or treated.

But each time when you read those sections, the point of production is furthest upstream of that metering the inlet to any gas pipeline system after, I think, mechanical separation, or the inlet of any pipeline that is actually transporting the gas to a gas treatment plant. I'm going to pause there and say it's very technical, and I could summarize that in a paragraph if I have completely confused everybody. Senator, maybe it makes sense. No, no, you didn't confuse us, and we wanted to ask you that question because we knew you'd give us a clear answer. And it's nice to hear it from several different people, but it's, it's been a concern for years when we look at the major gas development and the potential of pushing billions of dollars of expenditures against our oil revenue.

And that's the point of the clarification. And yet the statutes that you had referenced, and I just thought it would be good to get that point on the record because it appears that the sales of gas will be at the point of production in both Phase 1 and 2 for at least the 3 companies we talked to today. Thank you, Senator Steadman, for that question. Further questions of either Barry Romberg or Marie Evans? Senator Kaufman.

Thank you. Mr. Romberg, this is Senator Kaufman. I guess I'd just like to hear a little bit more from ConocoPhillips' perspective about kind of the other areas that we haven't. So we've talked about, you know, getting gas from the areas that we, you know, think are ready for commitments. But what about other areas?

Just kind of a brief assessment of other gas offtake opportunities. As you know, if we should develop the ability to pull gas off the slope and what effect that might have on your operations. Mr. Romberg. Yep, through the chair, Senator Kaufman. I think I understood the question.

Let me give it a shot. So if you're asking about other fields outside of those that have been mentioned that have potential gas supply. Yes, uh, there certainly is gas elsewhere on the slope, uh, nothing like the concentrations that you see, uh, in fields like Prudhoe Bay. 22 PCF is, uh, quite a large amount of gas, and I think it's very unlikely we would find something on that scale anywhere on the slope. However, there are many fields that are currently producing that have associated gas.

And so depending on the delivered price into the pipeline, there's other, other fields that might be competitive over time. But, but for good reason, the anchor suppliers for both Phase 1 and Phase 2 are the ones that have been mentioned. They do have available gas supply and are very close to the inlet of the pipeline. Most other fields would need many miles of connecting pipeline that would then affect their delivered economics of the project, which as things get rolling, I'm sure will be something that comes up. But to start things off, you go first to the sources that have a close and have it ready.

Thank you. Thank you, Senator Kaufman. Further questions from Senate Finance members? Mr. Romberg, thank you for coming before the committee. To testify.

Do you have any closing comments?

No, I don't. Thank you very much for your time. Thank you. Thanks for the invitation. Thank you.

That concludes the work of the committee today. Is there anything else to come before the committee? With that, our next meeting will be tomorrow morning at 9:00 a.m., and we We will be hearing from NSTAR. In the afternoon at 1:30, we'll be hearing from RCA. With that, we are adjourned.