Alaska Legislature: Special Coverage - September 10, 2026 1:00pm

All right, if everyone would please take your seats, we will be starting in just a few seconds.

I'll look in a moment, okay? I'm going to gavel in first.

I call the Joint Resources Committee meeting to order. Today is Thursday, September 10th, 2026, and the time is 1 PM. Please turn off any cell phones. Members Present.

Representative Colombe.

Representative Sadler. Representative—. Pausing—. Paul. Thank you.

I was going to say Carolyn. Sorry. Resources co-chair Representative Freer. I also have Senator Dunbar, Senator Clayman, and Representative Donna Mears. I'm sorry, I know them by first names.

And here comes Representative Fields. Thank you all for joining us. I also welcome the audience, and I also welcome all the folks online. I know quite a few people are streaming in today because they're very interested in this topic. Online we have 4 legislators: Representative Dibert, who is the co-chair of House Resources, Representative Elam, Rauscher— Senator Rauscher, and Senator Kawasaki.

So welcome to all the folks online as well. And Senator Gray Jackson is in the audience, so welcome to her as well. The recording secretary today is Heather, and helping us from the Juneau LIO and Anchorage LIOs are Doug, Ian, Cassie, and Tristan. So today we're continuing discussion of Cook Inlet gas supplies And we're going to have an update. Thank you.

Is Senator Tilton in the room? Ah, there she is in the very back. And Representative St. Clair, thank you for joining us. We're going to have presentations by Hilcorp, Bluecrest, Hex Energy, and Chugach Electric. So we're going to start with Hilcorp.

They are online.

Mr. Soujay— there he is— is online, and I'm looking for the screen to indicate he's there.

Are you there, Mr. Soujay?

Is it up to you to admit him? Do you see the sign that says admit? I, I do not see a sign, Senator, no. Oh, it's right there, but I don't have control of that, that I'm aware of. I don't see it here.

All right, I think I see him there. Excellent.

Mr. Sojay, can you hear us? Yes, ma'am. Perfect. Yes, I can. Great.

We can hear you also. So welcome to the committee. You've provided us with a PowerPoint and a presentation to present, so please proceed.

Okay. Do we— can we show the presentation on the screen? I can't see it. It is on the screen here.

Yes, I'm sorry, I don't know how to solve the you seeing it part, but we are showing slide 2 right now. It says Hillcorp Alaska overview.

Okay, I'm gonna see if I can maximize that. I can now sort of see what slide we're on, but not very well, to be honest.

I'll say this puts me at somewhat of a disadvantage. I really can't see any of the slides. There's no way you can share that.

Looking to staff.

Madam Chair, I think they're working on the sharing the screen. Representative Sadler. Thank you, Madam Chair. It might be possible for Mr.— for Luke to sign into AKledge, which might be carrying this live. It might be a little bit of a kludge, but you could watch yourself in your own rearview mirror.

As long as there's no echo, because that's often the phenomenon. I'll tell you what, I can look at the slides on my phone here if you'll bear with me, and, you know, I'll have to be looking down at my phone to see which slide I'm on, but we can do it that way. That sounds great, and we can make sure that we coordinate. You could tell us which number you're on. All right, so thank you for the opportunity to testify today.

Uh, slide 2 here is our standard Hilcorp Alaska overview. My name is Luke Saugey. I'm the Senior Vice President for Hilcorp Alaska, uh, and Alaska has 1,750 employees in the state. We employ 3,000 or 4,000 contractors at any given point in time. We are today running 6 drilling rigs on the North Slope and 2 drilling rigs in the Cook Inlet.

We produce in the state, or we operate about 350,000 barrels of oil equivalent in the state of Alaska. We've got over 2,000 wells. And we are the largest operator on the North Slope and in the Cook Inlet region. If you'll go to the next slide—. Slide 3.

Yes, ma'am, slide 3.

This shows an overview of our operations in the Cook Inlet. This does not show all of our fields, but it shows most of them. This is kind of the northern part of our assets. It shows the pipelines. We operate all of— almost all of the gas-producing fields in the Cook Inlet Basin.

We are the largest supplier of gas. We operate over 90% of the gas that is provided to Southcentral Alaska for heat and power. And what I'm going to say today is that Hilcorp has never been more active in the Cook Inlet, and that we remain completely confident in our ability to deliver on all of the gas supply commitments that we have made. Despite the fact that Hilcorp will deliver on all of its commitments, the market needs more gas. And without another source of gas supply by winter 2029, be that North Slope gas or LNG imports, there will not be enough gas in the system to meet all of the utilities' needs.

Um, that being the case, we believe that the Harvest LNG import project is the right LNG import project that can be accomplished by 2029 in order to bridge that gap and buy us 3 or 4 more years to gain access to North Slope gas through a gas pipeline, or could be expanded to meet the market needs, uh, if the North Slope gas line does not come to pass. That LNG import facility is going to require additional gas storage facilities in order for us to manage the nature of that supply And to that end, Hilcorp is developing additional gas storage facilities. We believe we're the right operator and developer of those facilities. That's really our core skill set, is drilling and completing gas wells and managing gas reservoirs. And then finally, I'll talk about the gas supply situation for this coming winter.

We believe that there is enough gas available in the system, but it will require some of the contracts to be adjusted. So let's go to slide number 4.

Uh, 2026 is a record drilling season for Hilcorp. We drilled the most wells that we've drilled since COVID and we continue to meet all of our contractual supply agreements. Our biggest customer is NStar, the natural gas utility. Followed by Chugach Electric and Matanuska Electric. And we also sell gas to a variety of other non-utility customers in south-central Alaska.

Go to the next slide, please. Slide 5.

We continue to invest heavily in the Cook Inlet, deploying $400 or $500 million each year, despite the fact that the Cook Inlet is a very high decline basin. And really faces challenging economics. Um, we have expanded our development activity into some new areas this year, including some of the areas that are subject to the most recent leasing terms put out by the DNR, and I will say that the only way that that was economic for us was because of the creative new leasing terms by the DNR. So we are supportive of that concept. We're going to bring some new gas into production that relies on that.

Go to the next slide, please. Slide 6.

So as I said, Hilcorp is investing $400 to $500 million per year in the Cook Inlet. In 2026, we plan to drill 26 or more new wells. And we are using 3 different drilling rigs throughout the basin. What I show here is a list of our executed and planned wells for this calendar year.

We are active both onshore on the west side of the Kenai— west side of the Cook Inlet. We're active onshore on the Kenai Peninsula, and we are drilling wells offshore utilizing our jackup drilling rig. Next slide, please.

Would you pause for a moment? Mr. Saugey, would you pause for a moment? There is a question from Representative Mears. Uh, thank you, Mr. Saugey. Uh, through the chair, uh, on slide 6, there are— which one of those are on platforms?

Good question. Uh, we are— we drilled 2 wells on an offshore platform this year. Those are the Looking for the names. It's the— that's interesting. I'm not seeing— I'm having a hard time seeing it on my phone.

We drilled 2 platform wells this year. They were both drilled from the North Cook Inlet platform, also known as the Tionik platform.

Follow up? The B-2. Follow-up, Representative Mears. Thank you, through the chair. So, Mr. Sarge, I'm kind of thinking as we're looking at operations tailing off, drilling tailing off, and then I know we've got a presentation coming soon from HEC about talking about an additional jackup rig.

I don't know if it's too early, but could you share— is there anything that you can share about what future offshore what the current drilling plans are for Hilcorp and if there's a termination date or a plan for stopping drilling out in the inlet. And then at some point, we'll need to get deeper into what happens to the platforms. But for the moment, you know, if there's anything that you can share about what your future for the offshore drilling is in the next few years.

Through the Chair, we do plan to drill on the Tyonic platform for the foreseeable future, I would say, for the next 4 or 5 years. We plan, you know, 2 to 4 wells per year from that Tionic platform. And what we're hearing from Hex is that they also would like to drill, I would say, a roughly equivalent number of wells each year, but I don't want to speak for them. So our view of the future is that that jackup drilling rig will be, you know, mostly fully utilized. We'll probably— we can drill for about 6 months in the offshore environment using that jackup.

And we expect to keep it busy most of that time for the next 4 or 5 years. Thank you.

Representative Sadler had a question also, Mr. Saugey. Thank you, Madam Chair. I appreciate the— on the topic that Mr. Saugey spoke briefly, he gave some tantalizing hints. You said that there's plenty— I'm sorry, there's sufficient gas would require changes in contracts. And you said that some new gas depends on DNR lease— I'll use the word accommodations.

Could you amplify what kind of changes in contracts and lease accommodations might be necessary to accomplish increased gas production.

Through the Chair, I'm going to ask you to wait until I get to the part talking about this year, if you don't mind. Sure. I'll speak more clearly on that point. But what I was saying about DNR is that the most recent state lease sale, the lease terms that the state put forth was what is considered, what's called a, I think it's a It's a— I'm going to get the terms wrong, but it's about a 5% net profit share lease. And so when we take the leases, these new— this new economic hurdle to bring new gas into production.

So some of the wells that we're drilling this year on the west side of the Cook Inlet are only economically viable because of those slightly different lease terms on that new acreage. So this is new acreage that we've taken within the last couple of years and will be bringing into production through new drilling in 2026. Thank you, sir. Look forward to it. Very good.

Senator Clayman. Thank you, Madam Chair. Mr. Sauge, the— you talk about platform rigs and jackup rigs and on-land rigs and not on-land rigs, but you've got 3 different drill rigs working. Can you, just so that I'm tracking accurately and others, describe the 3 different kinds of rigs and which are in the ocean and which are not in the ocean? For sure.

Yeah, through the chair, so we have 2 onshore rigs. One of them we keep on the west side of the Cook Inlet to develop and explore that area. One of the onshore rigs we keep on the Kenai Peninsula to develop and explore that area. It's very expensive and time-consuming to move those onshore drilling rigs back and forth. So two onshore drilling rigs, one on the west side, one on the Kenai Peninsula.

We have one jackup drilling rig. That jackup drilling rig is only for offshore drilling and production— or drilling and exploration. And we use that jackup drilling rig to drill new wells on our Tyonic platform We could also use it to drill new wells in other places. HexFury is using it right now to drill new wells on their platform.

Follow-up, Senator Klayman? Thank you. All right. All right, I think we're ready to move on to slide number 7.

Okay, slide 7 is a slide that I show regularly, and it simply shows the amount of drilling that was done by Hilcorp and by all other producers in the Cook Inlet over the last, let's see, 14 years at this point. 2026 Is the most active year we've had since COVID and really since 2014, as you can see on the graph. We will drill 26 or 27 wells in 2026, and our friends at Hex are on the board for 2. I think they're actually shooting for 3 wells, so that's good. We think they're probably going to be able to get that done.

So that's a good news story. You can see that drilling activity has been consistently increasing since a low in 2018. We've continued to push to do more each year. I'll brag on my drilling team a little bit. This year we're going to drill 27 wells.

That's not because we're running more rigs than the last 2 years, that's because they're drilling faster. We're were getting better each and every year. So good news, more wells are getting drilled. The bad news is that there are only 2 companies drilling wells in the Cook Inlet. Only Hilcorp and Hex are drilling wells.

And of course, if I look back 14 years ago when Hilcorp came to Alaska and entered the Cook Inlet, there were 4 or 5 companies drilling new wells in the Cook Inlet Basin. And that was a much, let's say, healthier, industry and healthier base that was supplying gas at that point in time because there were so many more companies active. Go to the next slide, please. So we're on slide 8, I believe. Yes, ma'am, slide 8.

Madam Chair.

Um, Representative Elam, is that you? Please identify yourself. Yes, this is Representative Elam. Thank you.

Welcome. I was hoping to ask a question. Yes, please ask. Thank you. On slide 7, I appreciate the information there.

It looks like this is mostly total counts of wells, and so I was wondering what total percentage consumption approximately is Hilcorp producing of the total use of natural gas for the utilities and heating that we're having here in South Central and along the rail belt?

Through the chair, Representative, I think your question— I think I understand your question. So this graph on slide 7 shows the number of wells drilled. It doesn't say anything about production. It's purely the number of wells drilled. And so I think I'm going to answer your question about production a little later if I can, if I can put you off a little bit.

Is that okay? Yeah, that'd be totally fine. Thank you. I appreciate it. Very good.

I'll take this pause to announce that Representative Prox has joined the meeting, as well as Senator Myers and Representative Eichide. Mr. Sauge, please proceed. I believe we are on slide 8.

Right. So slide 8— well, on slide 7, I talked about drilling activity. Drilling is not the only activity that we have going on. We also recomplete our existing wells. We might plug back out of a depleted gas zone and add new perforations in a zone up the hole.

We might work over a well to fracture stimulate it, or to access new gas reserves in an existing wellbore. We might build a new flowline or a new facility. So we have many different activities. We capture all of these activities as projects. And what this slide is showing is that looking back 5 years, our overall activities are represented by one bar for each month on this graph.

So this includes not just drilling, but all of the different activities that we have going on. And what I want you to see is that our activity levels have increased year after year after year. That's those purple bars there. We also track our success rate of these various activities, and we track the amount of gas resource that each activity brings forward. Unfortunately, what we're seeing is that as we are more and more and more active, The gas resource brought forward from each activity has decreased and decreased and decreased, such that even though we are at all-time high activity levels, that red line on this graph shows total gas rate, and it's basically flat for the last 3 years.

So more and more activity, but really running to standstill as far as gas delivery. So we're doing what it takes to deliver on our contracts, but our increased efforts are not delivering any extra gas. We capture all of this information and use it to create a model about what will happen in the future. And what it shows is that the decline rates we're seeing on our new projects are very, very high, some of the highest in the company. We're seeing 40 or 50% decline, which means that, uh, the amount of gas a well produces in the first year will be— it'll be reduced by 50% in the next year.

So if you make 1 BCF in the first year of gas production, the next year you're going to make 1/2 of 1 BCF, and 1/4 of 1 BCF in the following year. So an extremely steep decline. So all that to say, we have a very robust model that we've built using the data that we've collected about our activities and those of others in the basin. And it allows us to very confidently forecast what gas production will look like in the future. So the first question I think everyone has is, what about this coming winter?

So if you would go to this coming winter— I'm sorry, go to the next slide, slide 9. We can talk about that.

So NSTAR has testified that they are 3 BCF short going into this coming winter. The good news is that we have the gas in storage and we are willing to make it available this winter. It will require NSTAR to adjust their contracts to pull that gas forward.

And so let's, let's dig into that statement a little bit. What I show on the left is the gas that is currently in storage in the two publicly available gas storage facilities. On the left, I show Pool 6, which is managed by Hilcorp. On the right, I show CINGSA, which is managed by NStar. And what you can see is that both facilities have additional storage space remaining in them.

And you can see that we will enter the winter with about 30 BCF in Pool 6 and about, uh, you know, 7 or 8 BCF in Xingza. Hilcorp has 30 BCF of gas in storage going into this winter. All—. Substantially all of that gas, really all of that gas, is dedicated for future delivery to NStar. So this gas can be available today if contracts are adjusted.

And so I think, I think Representative Elam asked, what does that mean as far as— or maybe Sadler— as far as contracts being adjusted? Let me give you an example. So if you'll advance one slide. So now we're on slide 10. Slide 10.

What this is showing is that, you know, potentially We could allow NSTAR to take possession of this gas and the gas storage capacity associated with it now. And, you know, they would have that gas available to meet their needs this coming winter and the winter after. But obviously, we cannot then deliver that gas in the future because we've already delivered it now. And so we would need to adjust our deliveries down in the future.

The other thing that is involved here, you can see I've marked on this graph the Harvest LNG startup window.

We are confident that Harvest will be able to start up their LNG import terminal no later than the end of, let's say, 2029 or beginning of 2030. and that will allow us to have additional gas in the system to meet whatever potential gap in coverage should come to pass there.

Okay, I'm gonna—. Mr. Sojja, if you would pause. Are you finished with this slide? Pardon me. Yes, ma'am.

All right, if you would pause for a moment then, um, First of all, I want to welcome Representative Galvin, who's joined us. But I have a question. Again, and I believe it was Rep. Sadler who asked, what does this— I'll ask the question. What does it mean contracts are restructured? Tell me what that means.

I believe you were commenting that deliveries would be altered. But I'm asking what the price would be. What's the cost?

Through the Chair, you know, I guess I don't want to be guilty of negotiating in public. We are in negotiations with NSTAR right now, and so these are relatively complex contracts. The main point that I'm making when I say restructured is we can make the gas available today as long as we all understand that we are— we will be unable to make that same volume of gas available in the future. That's the main point I was making there.

So for the consumer, what would the restructuring mean?

Through the Chair, I think The main thing it would mean is that NSTAR has the gas available this winter that they need.

The consumer, however, would be paying a price for that. Would that be consistent with the price that's being paid now, or would that be substantially higher cost? Through the Chair, I can honestly say that we have not discussed pricing with NStar about this. We have already committed to deliver this gas to them. We haven't talked about pricing, we've only talked about timing.

Thank you. If you're—. Oh, Representative Sadler has a question. We're still on slide 10. Yes, ma'am, a brief follow-up, Madam Chair.

Just a quick question, Mr. Saugey. Would any adjustment to the contracts— I mean, we don't have— actually, we do have lawyers at the table, but that would require new contracts. Would the RCA be required to give its approval to any adjustments in contracts that you're currently negotiating with NSTAR?

Through the Chair, I assume that would be the case. I think they have to approve all of the utility contracts. Okay, good. Thank you. I also want to acknowledge that my Vice Chair, Senator Wielechowski, has joined the committee meeting.

Further questions on this slide? Senator Clayman.

Following up on the question about RCA regulation, My understanding has been the RCA regulates what the consumer pays NSTAR for gas to heat their homes, but that your contract with NSTAR is not regulated by the RCA, although if the price changes, they go back to the RCA and say, "We've got a price change." Do you have a different understanding of how that works?

Through the chair, um, I'm not sure if my understanding is different. I believe that any contract that NSTAR enter— or any utility enters into with Corp to supply gas must be approved by the RCA.

I could be wrong, but I think that's the case. All right, thank you. Representative Mears had a question. Um, thank you, uh, through the chair to Mr. Sajay. So the way I'm Reading this slide and where we're at with providing additional supply of gas to NSTAR this year, basically what you're showing us is there's an amount of gas underneath the curve that you're looking to supply to NSTAR that's under the contract.

And what you want to do is change the shape of the curve so that there's some of that supply earlier and less— or either less later or a shortened timeframe later. And another alternative is to be supplying additional now at outside of the contract. So those are the, the two business opportunities I think there are for Hilcorp to be providing gas to NSTAR this summer that they have available. And that is the business negotiations between those two entities that they are working out between them with approval from the RCA. It's just a little different way of working looking at that, but just checking if that's what I think are two options right now.

Through the Chair, I guess I don't think that's what I was trying to say. What I'm saying is Hillcorp has committed to deliver a certain volume of gas to NSTAR over the term of this contract. We are very confident that we can deliver that volume but not any more than that volume. The timing of those gas deliveries is described very specifically by the contract. We have to deliver exactly x amount— I think it's about 33 BCF per year, every year, kind of rolling forward.

And that's what's shown on that graph, the blue bars.

If NSTAR desires, we can talk about changing the timing of some of the delivery of that gas. What we can't do is deliver a bunch of extra gas now and also deliver all of the committed volumes in the future.

Follow-up, follow-up, Representative Mears. So just to clarify then, the area— the gas under the curve is the only gas available, so an option to buy more now outside of that contracted amount is not something that you are able to do.

Through the chair, that is correct. I wish that was not the case, but that is correct. Representative Fields. Uh, through the chair, following up on that question, I assume that is predicated on the existing economics and tax structure in the inlet, and I would wonder, would a change in royalty rates potentially enable a corresponding commitment to increase volumes? By changing the economics?

Thank you.

Through the Chair, you know, that hasn't been something that we've been focused on. Most of our gas actually comes not from state land but from private land. So it would not, you know, the state could take a much lower royalty and that would be great. We would commit to higher activity levels.

Maybe. I would not commit to higher volumes of gas being available.

Yeah, I wish I had a different answer for you, but this is kind of what we can do.

All right, thank you. I don't see any other questions if you're ready to move on to slide 11.

Madam Chair.

Uh, is there someone online wishing to ask a question?

Uh, yes, I have my hand raised. This is Representative Elam. Thank you, Representative Elam. Thank you. Um, through the Chair, uh, if we are looking at the, uh, that you guys have specifically 30 BCF capable or, you know, additional capacity available.

I guess my question would be is, when does, you know, if we combine all of that between, you know, what Hilcorp is doing and HEX and others, when does imported LNG become unavoidable? Through the Chair, that's a great question. Let's go to slide 11. Thank you. So This is a longer-term view of the market in Cook Inlet that we have generated using our model.

Again, I'll say we have a great deal of confidence in this model, but it is a probabilistic model. And so, let me walk you through what these various curves are showing. The sawtooth blue curve represents the demand in the south-central Alaska market, and it's sawtooth because demand is higher in the winter and lower in the summer. But you can see it's relatively fixed. It's not really increasing, and that's been the case in recent history.

The green line on this graph represents native gas production from Hilcorp, from Hex, and from everyone else that produces gas. And there are some basic assumptions that need to go into that, but it's not terribly complicated. That forecast of native gas production comes from our very robust data set looking at all of our activities and the results of our activities going back the last 5 to 10 years. So what you can see is that in the wintertime when demand is low, if we look at this year, when demand is low, native gas production is comfortably higher than— I'm sorry, in the summertime when demand is low, native gas production is comfortably higher than demand. And so we're able to put gas into storage.

And in the wintertime, we draw gas out of storage and we repeat that year after year. But as native gas production declines, eventually it is not meaningfully higher than summer demand. And we're not able— in the forecast, in the model, we're showing we're not able to put gas into storage in the summertime. That intersection of supply and demand comes in 2029. So what our model is showing is that come 2029 in the summertime, native gas production will only just be keeping up with demand, and we will enter winter 2029 with not nearly enough gas in storage to make it through the winter.

And so that's why I said earlier, we are very confident that come winter 2029, we will need LNG imports or access to North Slope gas.

If you look at— so if we can go to the next slide, slide 12, we're showing the impact of LNG imports on the overall market supply and demand situation. What this shows is that the Harvest LNG import terminal can be available by 2029, will import 20 Bcf per year, and that will buy us an additional 3 or 4 years before we need to decide either to expand that LNG import terminal to 40 or 60 or 80 Bcf per year, or to get access to North Slope gas through a gas pipeline. So it buys us an additional 3 or 4 years to gain access to another, another solution.

Mr. Soja, before you leave this slide, can you— you've referred now to the Harvest LNG import. You are the president, I believe, of, of Hilcorp Alaska. Can you speak to how the progress is going on that LNG conversion?

Through the chair, what I can say is that The Harvest team remains confident, as they said in their testimony earlier this year, that they will be able to bring that facility on within— I want to say, and again, I'm speaking on their behalf, so subject to correction— within 2 years of FID. And what stage are they at right now?

Gaines, as I— sorry, through the Chair, as I understand it, they are in negotiations with their potential customers. So they're at FEED. I'm just looking at where they are in terms of stage gates.

Through the Chair, I'm sorry, I don't know. All right. And do you have an estimate of what the conversion project will cost at the end of the day?

Through the chair, no, I do not. All right, thank you. Uh, I believe Senator Clayman had a question.

Looking both at the earlier slides, uh, 9 and 10, with regard to the gas supply and the, the gas in storage that is available if there's an agreement reached to use that. If, let's say, if 80 to 90% of the gas in storage is used over time. How much does the use of gas storage extend that timeline for needing imports?

Through the chair, I don't think it really changes the timeline for needing the imports. What I think it does is I think it— if if NSTAR takes possession of the gas and the gas storage capacity, let's say this winter, I think it would mostly align NSTAR's timing with that of the other utilities as far as needing LNG imports in 2029.

Thank you. All right. Seeing no further questions, we're ready to move on. I think to slide 13. Madam Chair?

Yes. Madam Chair, this is Senator Myers. I had a question for Mr. Sojay. Go ahead, Senator Myers. Thank you.

So, Mr. Sojay, you're referring to the harvest import facility here. We've heard some testimony from NSTAR that they are not interested in working with you guys and they prefer continuing to work with Glenfarn towards building an import facility. My understanding is Enstar is the largest customer, I believe, over 50% of— using over 50% of the gas in the South Central region. Will you still be able to get financing if you don't have—. For that project if you don't have Enstar on board as a customer right away?

Through the Chair, I'm going to go out on a limb and say yes, I think so. But again, I want to make clear that's not Hilcorp's project. So I would direct you to the testimony that Harvest provided earlier this year.

Follow-up, Senator Myers? Okay, thank you. No, thank you. All right. Again, seeing no further questions, I think we're ready for slide 13.

Okay, so slide 13 is an attempt to answer the question, you know, what are the implications for gas storage in Cook Inlet if we have LNG imports? We have a gas pipeline from the slope, you know, everything is rosy, we're in great shape. But if we're importing LNG, that has some implications for gas storage. Specifically, there is not enough storage capacity in the inlet today to meet the utilities' stated needs. So the utilities have said— and this is what the bottom graph is showing— utilities have said that they need about 700 million cubic feet a day of withdrawal capacity.

And they need the storage space to store a little over 100 BCF. And you can see that's the red bars on those lines. You can see how those compare to what is available today. And so what is necessary is additional natural gas storage facilities. Hilcorp is working to meet that need.

We are currently developing two gas storage facilities, one on the Kenai Peninsula and one on the west side of the Cook Inlet at Beluga River. We think that those two storage facilities will be enough to meet the vast majority of the needs to manage LNG imports.

I will also say we think we are the right developer of gas storage projects because this is our core business: drilling wells, completing wells, managing sandstone reservoirs, and producing gas.

Go to the next slide, please. So this is a— an overview of our Beluga River natural gas storage project. That we are currently developing. I think it's a pretty cool project. One of the things that makes it especially suitable— you can see on the map there's a star for the location of this gas storage facility, and it sits right at the intersection of the NStar gas pipeline that supplies gas to Anchorage from the west side of the Cook Inlet and the Harvest gas gathering pipelines.

As well as that purple line, which is the proposed— most recent proposed path of the North Slope Gas Pipeline. So it sits in a location that is advantageous for a variety of different customers to be able to put gas in and take gas out, depending on what's going on in the inland. This storage facility would involve installation of additional compressors on the surface and drilling, let's say, 5 to 10 additional, uh, additional wells to manage this reservoir, the storage reservoir.

Then my last two slides, if you would go to the next one, please. Um, I think it's always helpful to put some context on this. We have over 350 employees at Hilcorp, at Hilcorp Alaska, who are working on delivering gas for Southcentral Alaska. So this is a photograph of our Anchorage office team, who are all here, uh, right down the road, working hard every day to find and produce more gas. And then if you go to the next slide, we've got some of our intrepid field team who are out there every day in all kinds of weather, onshore and offshore, making sure that all of the gas is produced, the wells stay on, the compressors stay running.

And we are all well, well-lighted, dry, and warm.

Thank you for that, Mr. Saugey. A question often asked of other resource development companies: What percent of your employees are Alaska residents? That is, they own a home here and actually live here. Do you know the percent of your employees? I do, through the chair, I do.

For our gas-producing team, it is 100% or 99.9%. There might be one or two that manage to live outside, but it's effectively 100% for our Cook Inlet and Kenai teams as well, obviously, as the Anchorage team. If you look at all of our employees across the state, including all of our North Slope employees, work a rotational schedule. To the best of my knowledge, we're about 77% resident in Alaska. Thank you.

We were—.

Pardon me, I didn't mean to interrupt. You were going to say? No, that's fine. That's great. I'm going to call on Representative Fields first.

Through the chair, well, I first want to thank Hilcorp employees. Anyone who has friends who work for Hilcorp know how hard the employees work. It is impressive. But I wanted to ask a follow-up. One of the easier things that resource development companies can do is not reimburse employees who fly up from the lower 48, and I was curious, for the slope workers, does Hilcorp reimburse for flights, say, from Fairbanks and Anchorage, but not reimburse for a flight from the lower 48 to Anchorage?

Thank you.

Through the chair, we provide transportation from Anchorage or Fairbanks. Well, I'm not sure. We provide transportation from Anchorage to their place of work on the North Slope.

Thank you. Thank you. Representative Sadler. Thank you, Madam Chair. For the record, I cannot imagine being cold in February and declining to burn gas unless it was produced by sufficiently Alaska-centric workforce.

I'm going to burn what gas we get. But my question is, Mr. Sauge spoke about net profit share leases in the most recent lease sales. My question: if you're talking with DNR about ways to increase production, is it possible to reissue leases, current leases you're producing from, under a net profit share regime that might provide a little bit more incentive for you to invest more?

Through the Chair, I don't know. I don't know if they can reissue leases or not. You'd have to ask DNR. Good answer. Thank you.

Representative Colon. Thank you. Through the chair, Mr. Sojay, you were talking about the storage facilities that you were developing. You went into the Beluga one. I was asking or wondering about the Kenai storage facility.

Is that something— is that the same storage facility that Enstar's trying to acquire?

Through the chair, I believe it is. We have been working with the city of Kenai for over a year to secure the rights to develop a gas storage facility in the Kenai Loop Field. I think you correctly state that NSTAR is— was also trying to acquire the rights to develop that storage facility. I guess our view is that that storage facility should be made commercially available to anyone that wants to use it.

Follow-up, Senator— or Representative Colon. So with that, so you said you're working with the City of Kenai. Is that— can you kind of explain the complexities of that storage field? My understanding is it's not quite clear-cut or easy to follow because of the possession of the field and that there's gas still coming out of there.

Through the chair, as you state, It is quite complex. There are a variety of owners, and it's not entirely perhaps settled who owns what for space. I don't believe there is any existing production from the oil and gas leases. I think those leases have ceased production. But we were talking to the City of Kenai as the owner of the surface real estate about a lease of the pore space, which would allow— give us the right to store gas in that pore space.

I think there may be competing claims between DNR and the City of Kenai. I'm a little bit out of my depth, to be honest. No, that's helpful. Thank you. Thank you.

I see no further questions. Mr. Sauge, I will make a comment. The reason I asked you about how many of your employees are actual state residents is that we know that about 25% of the jobs in Alaska are filled by non-residents. These are folks that have their paychecks auto-deposited in banks in other states where they pay an income tax. Uh, that 25% sort of correlates with your 77% state employees, uh, in the oil fields.

I had the pleasure of sitting behind 4 of your employees on a recent flight from Seattle. All 4 of them were million-milers. Just a point of interest. Um, thank you very much for your presentation. Thank you for joining us today, and I see no further questions.

We'll move on to our next presenter. So our next presenter was scheduled to be BlueCrest Energy. The CEO of BlueCrest is Benjamin Johnson. Mr. Johnson apparently, at the last minute, as in, uh, this morning, let us know that he was not available this morning, and that's extremely disappointing since DNR shared with us at our— at the last presentation about 10 days ago that there's about 200 BCF under the lease held by BlueCrest called Cosmopolitan. 200 BCF of gas.

The whole consumption of South Central is 70 BCF a year. So you can see it's a substantial, meaningful deposit of gas. The BlueCrest company is struggling to make financial arrangements to develop that gas, and that was what I was looking for an update on today. Apparently he is not available to present that. The other thing I was going to ask him about today is the lien that has been filed against BlueCrest on August 4th.

Nordic Chalista issued a lien of $827,000, uh, And so I was hoping to get an update on that financial issue also. The lease has been carefully watched by our Department of Natural Resources. All contracts for oil and gas, of course, have a phrase in them, "duty to produce." And so the Department of Natural Resources is enforcing that clause. So disappointing, but BlueCrest will not be joining us today. So that moves us on to Hex Energy.

So I will welcome John Hendricks to the table and any staff that he's brought with him. It looks like Mike Coy, CFO of Hex Energy, is with us. So welcome, gentlemen. Thank you, Madam Chair. Thank you, Senators, Representatives.

That's no surprise. Do I push a button here or no? No, it's on automatically, but it does have to be down by you. Yes, that's great. Thank you.

Well, thank you to the Joint Committee for having us in today. It's a pleasure to speak on behalf of our company that is Alaskan-based, Alaskan-headquartered. We don't have any other offices outside this state. We are Alaska's only Alaskan-owned oil and gas company. Everything we own is in this state.

Uh, we make a— our, our numbers is probably like 80, 85% to 90%. It With a small company, it doesn't take much, but one person all of a sudden go come and all of a sudden we got a 5% swing. But we want to grow. We'd like to be the next Alaskan-type Hill Corp that's working with our state and bringing value to our resources and delivering. As you can see up there, we're heavily involved in the community as much as a small company can be.

Even just signed an agreement with Tyonic and Seary to do some exploration, which is going to be part of our presentation today.

So I am also joined by Mike Koy. He'll introduce himself here in a little bit. HexDrills, Cook Inlet natural gas. That's all we do. We basically are dedicated to that call.

I'm sorry at this late in the game and in the fall that we're having to worry about— people and Alaskans worry about where their natural gas is coming from. I I could probably show you ways of how to fix it. And I think we just saw that Luke Shawzy has a big part on how to fix that in the short term and the long term.

Our, our team is dedicated with Alaskans that are hardworking Alaskans that are out there drilling right now. Right now, I'm just going to jump ahead. We're about halfway through our second well. We're about 4,600 feet on a 9,160-foot well called the A7 well. We just finished the A10 earlier.

We hope to drill a third well. We're drilling this well with the Spartan 151 that's owned by Hilcorp and that dedicated team out there.

But more than anything, we are invested in our communities and we're here to demonstrate a pathway for more gas to Alaskans. Next. So moving on to slide 2. Okay. So the takeaways.

We're going to start right off with this and we'll tell you a little bit more about our company. We think the big takeaways we want to leave you with today is there's a lot of gas out in Cook Inlet. We got to do it. We have to do a better job exploring. We haven't been doing a good job exploring.

A lot of it was regulated. A lot of it— I can't speak on behalf of Hilcorp when they came in here, but if you had someone say you can't charge more than $8 for 10 years for your gas, And they're 98% of the production. Do you think they'll be out there trying to explore? Probably not as much as they can, but they've done a pretty good job to date. And like he said, we're the only two people that are out there drilling.

We're developing though. These are development wells we're doing right now. We're not into exploration. The deal we just struck with Seary and Taoneek is an exploration play.

Only— we are only producing right now 1.2% of our acreage. Now you're going to say, give it over to somebody else to produce it. Well, not really, because one thing we're going to talk about is we need security. And that's the biggest problem Alaskans have right now in our face, is I don't know how long I can sell gas into the market. If you're a fisherman and you say you have limited entry, you can almost catch so much fish, you're not going to go out there and catch more fish than you can.

Because even if I produce, if Cook Inlet doubled its production today, No utility would use our gas. They would use about 110% of it. Their storage would be full, and that's it. And we would suffer from that investment that's not producing anything. So it's not that we can't sell any more gas, it's just, it's just there.

We are a very small economy. The nice thing about it is it can be fixed with exploration, and you can fix with what they talk about as far as maybe a small import facility, put people at ease so they don't go into a panic. 'Cause panic kills, panic makes mistakes. We should have been focusing on this earlier. And that's why I commend you for inviting— basically, we're the fishermen of the oil and gas industry.

We're out there basically drilling, making oil and gas. We're not a utility. We're basically— actually, we're the ones rotating to the right, putting our bit down, investing our capital, our money, our savings into helping deliver gas for Alaskans. One thing that I told people at the, at the AOGA conference the other day was no one's talking about the 3.2 times increase in our firm gas that we've committed to Alaskans going from this year to next April. Do you know that we're committed from going from 8.1 of firm gas sales to 26 million a day in firm gas sales to InStar next year?

That's a 3.2 times increase in firm gas sales. Where is that getting the headlines? Is it because we're not connected to the oil and gas companies that are actually going out there farming your fields and trying to bring it forward? But that's a good accomplishment. That puts us at risk.

I mean, we're trying to do our best. We're going to try to go from 2 wells this year to 3, and that thing's— that's looking really good. But with our partnership with Hilcorp on using that, our dedicated team, we're using 25 different contractors through the state to make this happen. So you gotta have, we have to have to do this and to explore. You gotta have the runway where you know if you drill and you produce, you can sell into that runway.

Instar earlier this year signed an agreement with Glenfarm for 30 years. And they wouldn't sign an agreement with us beyond 5. How do you think that makes me feel as an owner? Do I want to continue and invest? And I told her people earlier, I'm Alaskan, but watch it when the Alaskan leaves this kid and I start acting like a business guy, right?

Because we want to continue to drill, but you got to give us the ability. And so when we talk about critical infrastructure— next— when we talk about critical infrastructure, That's one thing that we have to always think about. Critical infrastructure basically gives us the priority, the ability to sell gas in the market. The ability to sell gas into the market. It provides a better blended price.

Our price, our gas price right now of our firm gas is only 8 million of the 20-some-odd million we make a day that goes to InStar firm is a price of $12.30, and it only goes up 1.5% per year for 5 years.

Who else has done that? We're tripling the amount of firm gas commitment to InStar at a price basis point that only goes up 1.5% per year.

1.5% Per year. And no one's talking about a 3 times increase of firm gas being sold.

So it also, what this does, it allows investments. We can put investment in wells, maybe a jackup, but no one's going to buy a jackup rig if they don't have the runway to deliver people, infrastructure. So, and people say, you know, I heard just, it's all rosy when a gas pipeline comes down. No, it's It's not rosy when a gas pipeline comes down to Wasilla on Phase 1, and it's not really rosy until that main pipeline sells 90% of its gas as an export, because our Cook Inlet gas price is going to be cheaper until they sell 90% of that LNG export in the market. So you need Cook Inlet gas to be the blended gas, because I just showed you what our basis price is, is $12.30.

How did high prices hit Cook Inlet? Remember what they quoted? $16 Basis price to Alaskans based upon January 2025 pricing, plus adjusted for inflation. Do you know what that price is today? A lot higher than my $12.30 I'm charging Alaskans.

So a little bit about us. To support this, this year in 3 years drilling. We, we purchased the Atlantis, which is an Edison Chouest vessel. We brought it up here through the Panama Canal. It's a DP dynamic positioning vessel that can hold during the currents of Cook Inlet to provide us reliable delivery of equipment to our Allegro Lee platform.

The Allegro Lee platform is named after my granddaughter, a fourth-generation Alaskan, and I want her to grow like our company can. We have a 15-mile subsea pipeline to our central processing facility. And one other thing is Alaskans do benefit from this. Alaskans need to understand that they look at Henry Hub and they compare it to our price, they say, oh, we're overcharging. But at your meter— and I'll give InStar credit and us credit and everybody else— it's still the 12th cheapest gas at your home meter than any other state.

The 12th cheapest. Cheaper than Texas. It's been that way for decades. So you need to use facts when you start evaluating things. Next.

So we're on slide 3 right now. We're moving to slide 4 for the folks at home. Okay. Is that right? We're moving to slide 4?

Great. Yes, Madam Chair. Madam Chair, I have a question. Yes, a question from Senator Clayman. Thank you.

Mr. Hendricks, just going back to one of your earlier references, you talked about a development well and an exploration well. And I think I know what that means, but some listening may not. Can you explain the difference? Yes. Okay.

First you generally shoot seismic. Some people don't shoot seismic, but it's very smart to shoot seismic. And you look at it and you do ties to your seismic subsea, and that tells you about where to drill. And you drill your exploration well. You don't know, I mean, you know, 30% success on exploration is very, very good if you're shooting with seismic.

And then that's called an exploration well. And then hopefully it's a discovery. And then what you do is you drill another well that's an offset well to confirm the discovery. You might drill 2 or 3. You find the boundary.

What is the lateral extent of this field? And then there you call it a development opportunity. And then you put people together and you develop. You might even put people together to invest in the exploration phase, and then you go into development. And that's what we're at right now, existing fields that, that are being developed.

The Kitchen Lights unit is basically an underdeveloped field. We bought it. It was mismanaged. There's a lot of little fixes we had to do that had a lot of hair on it. But we were— we've made a great stride in getting to where we are today.

Did I help? Follow up? So the development well would be like in the kitchen lights unit. You're doing wells to figure out if you can put a pipe in there and get the gas out. Yes.

But you're working on more of a known field, whereas the exploration well is trying to find a new field. Yeah. Every time we reach out, we can tie that with the seismic. And so the actual— when you log a well, you can basically relate that formation that you see on your log, that you call it, with a seismic line. And then you can tie it to other wells.

And you can kind of extrapolate out where it might go to, so you have a better chance of hitting the next development. But Cook Inlet is, I mean, I've worked both. I started 20 years in Prudhoe Bay. But it's a lot more complicated, especially offshore. And then it's not, Prudhoe Bay is a 500-foot thick Saddle Rochette Formation.

Where here we have 5-foot, 10-foot, 15, 20, maybe a 50-foot every once in a while. Zone, and it's like an alluvial fan, right? Like you're looking at a glacial play. You have a little sand stripping off over here and there, and that's what we're trying to hit. But there's multiple layers that's built over millions of years.

Thank you. I see no further questions. Okay.

So this year, this— that's the Spartan 151 moving up to our platform. We're committed to investing $50 million drilling, targeting 3 wells. We're on our second right now. Planned depth is around 9,000, like this one right here is 9,160. And we've been meeting our plan of development, and we're hoping that we should start bringing on production sometime around the end of November, the first of December.

It all depends upon sea ice that's out there, and And just the efficiency of this rig right now, everything has been working good for us. But our critical infrastructure is not theoretical. It's in place and it's been delivering gas. Last year, this, this same group, these dedicated men and women delivered the number 1 and number 2 well in Cook Inlet drilling off this platform. One well is doing about 7 million a day to 8.

The other is doing about 6 billion. That was more than we anticipated. Our target is around 3. So we're very, very fortunate. This year our first well looks like it might be around 3.

We're hoping maybe more. And this next well we're drilling right here could be more, but we're not even into the pay zone yet.

So right now I'm going to turn the rest of this over to Mike Koy.

He's our CFO for HEX. We brought him on back in October. Welcome, Mr. Coy. Yeah, thank you very much. Good afternoon.

I'm going to start off by apologizing and say I don't have either the polish or flair as John for public speaking, but please bear with me. I'll do my best.

As John mentioned, my name is Mike Coy. I'm the Chief Financial Officer of HEX. I knew— I know I'm new to the members of the Joint Committee, so I'll just provide a short bio of myself. I'm an engineer with a master's degree in finance, have more than 30 years oil and gas experience, gained primarily with BP here in Alaska and internationally. My career is focused mainly on economic analysis and project evaluation, strategy, finance, mergers and acquisitions, and business development.

I've worked on numerous LNG projects and large-scale infrastructure projects, including, including previous iterations of the Alaska LNG Project and previous iterations of the North Slope Natural Gas Pipeline projects, both again from a commercial perspective. I've worked across a broad range of energy assets through the energy value chain and project life cycle. Prior to joining HEC, I advised AGDC during its negotiations with Glenfarn. That work gave me a good understanding of the commercial structure, agreements, and economics of the current AK LNG project. I'll say AK LNG export project.

And how that project may generate returns for the developers. I believe my background will provide a practical perspective on the role that HEX and the Cook Inlet play in Southcentral Alaska's energy security and how imports and domestic sales from an AK LNG export project can supplement this role. So I'm very happy to be here and thank you very much for the opportunity.

For the first slide I'm going to speak to is slide 5, and this is just really to talk about royalty relief because I know there's been a question on what are the benefits of royalty relief. So we'll give you the perspective as it relates to, to HEC.

So the graph on slide 5 is showing historic production from the beginning of field life all the way through the beginning of this year. And what you can see is that up until you get to the far right-hand side of that graph is a steady decline in production.

Uh, the preliminary decision by DNR was made in December of 2024 to grant royalty relief, with the final decision made in February of 2025. The inflection point that you see on this graph where production is going down and production then dramatically goes up is the point of royalty relief being granted.

There is no clear example, demonstrated example, of the benefit of royalty relief. In, in simple terms, prior to royalty relief, production for the kitchen lights unit, which is our which in our producing unit was less than 10 million standard cubic feet a day. Right now we're producing over 20 million standard cubic feet a day. So it's a 2 times increase in production with more to come, as John has highlighted. Mr. Kooi, could, could you pause there for just one second?

I know that there are constituents of mine in this room as well as watching online. They don't know what royalty relief is. Could you very briefly describe what we're talking about here. Sure. Our—.

The leases of HEX, um, from the Kitchen Lights unit are state leases. There is a 12.5% state royalty on those leases. We, in our case, also have an additional 12.5% overriding royalty interest, which are, um, is additional royalty burden. None of those ories or overrides are held by by HEX directly. They're all held by third parties.

So it's, it's an extraordinary burden on the company for development. The royalty relief took the state portion of those royalties from 12.5% down to 3%.

Good, thank you. And it was granted for a period that equals $712 million of gross revenues, which equates to about $50 million of royalty relief. Thanks for that explanation.

Yeah, it's coming, it's coming. John just reminded me of a point which I'm gonna— I will get to here shortly. All right, if you could pause again for one more second, Senator Clayman had a follow-up question, I believe. Just going on the royalty relief, my memory is that there's another party involved in that you have a contract with that also has a royalty provision. They wouldn't give any ground on their royalty, but the state was willing to give grounds on their royalty.

And if I've got the wrong field, please correct me, but that's, that's what I'm remembering was part of the, part of the challenging dynamic in terms of the price. So I can— I, I will speak to that, but this is before my time, and then John will correct me where I, where I go wrong, if that's okay. All right, I won't correct anyone. So as I mentioned, we, we have essentially two groups of royalty owners. We have the state royalty, um, and then we have the overriding royalty interest owners, of which there's several of them.

The company did go out to the overriding royalty interest owners and asked them to, to make concessions with respect to the royalty interest, and, and, and in no instance was, was HEX's offer accepted with the old overriding royalty interest owners.

So we, we still maintain the full burden of all 12.5% to those overriding royalty interests. Thank you. So that's a good summary. So would you say overall then you're paying a 15.5% royalty, which is essentially— well, you could think of it as a tax. That is correct.

All right, thank you. I'll let you proceed. Yep, thank you very much. So I said what we've seen is a doubling of production, but importantly is that Royal 3 Leaf has re-initiated development of Kitchen Lights Unit, which is leading directly to increased natural gas for Southcentral Alaska. More to come, and it's extending the life of the field of the Kitchen Lights Unit.

Importantly, it's also leading to a better understanding of the subsurface geology through this additional activity, which builds confidence, which leads to expanded development, as we've talked about couple times already, which then can lead to increased commitments going forward. So in other words, royalty relief is providing the underlying basis for this to happen. Two additional points I'd like to highlight on this graph.

The first is that state revenues from HECS prior to royalty relief and state revenues from royalty today are approximately equal, not quite, but approximately equal due to the increase in production. So in other words, the state was able to positively incentivize additional production of almost 5 BCF so far with little to no additional cost. Senator Giesel, can I ask a question on that? Yes, Senator— excuse me, Representative Fields. Thank you.

Through the chair, I introduced a bill to extend royalty relief, extend it to other fields. That's how it was modified in the Finance Committee. I just want to flag for people, it's interesting because Um, our own, um, agencies say that royalty modification will diminish revenue, but I think the example here is actually because royalty relief is effective, it does increase volume. Net revenue is held the same. We get more gas.

So I just want to flag that for people. Um, there is no sacrifice in terms of revenue. And I want to ask, um, Mr. Hendricks and Mr. Koy, what's the difference between an administratively granted royalty relief, which can be revoked on short notice versus greater durability of royalty modification in statute, how does that affect your ability to go attract capital and make more investments in production?

Tremendous. That's Mr. Hendricks. If you'd identify yourself. Yeah, sorry, John Hendricks. Yeah, tremendous.

I mean, that's— it all goes back to what we talk about security, the ability to sell in the market and know what you're selling into for the future. We never know when the rug's going to get pulled out from underneath us. You know, we were also under— you talk about taxation and burdens and stuff under the administrative one, and we didn't ask for it to be changed, but we had a— basically they put a DR&R thing on us where we were taxed with no level on how much we have to set aside, probably more money than Prudhoe Bay for our abandonment fees. Would you translate the abbreviation DR&R for the public?

Depletion? What are they called? It's basically abandonment. I forgot. It's a— I forgot what it stands for.

Sorry. It's the abandonment liability. We use acronyms so much we forget what we're saying. Thank you. So, Mr. Hendricks, as long as you have been speaking, would you also tell me, remind me, what is the production tax?

On gas in Cook Inlet? It's 17.7 cents per MCF. Thank you. We're paying about $1.8 million a year or something like that on it. $1.4 Million.

Okay, sorry. That's me. That's the CFO. Gotcha. Thank you.

Yeah, and just to add to John's comment— this is Mike Koy— that, you know, I've been in the meetings in large companies where we're deciding how to distribute capital across the world, and I'm sure you've heard this before, but fiscal certainty is often the leading driver, if not one of the leading drivers in making those decisions. And just— it's not related specifically to our conversation here, but just wanted to highlight that.

All right. Representative Colombe had a question. Thank you, Chair. Through the Chair, Mr. Koye, I just— can you expand a little bit on a $1.30 discount on the gas? Where does that number come from?

Where did you start? How did you come up with a $1.30 discount? Yeah, that— thank you very much. Through the chair, that was exactly the next point I was going to speak to.

So, excuse me, it is ironic to an extent that most of the economic benefit from the Rural Tree Leaf is going directly to Alaska consumers and not to HECS. And that's a contractual figment with our contracts with Enstar. So there was a price that was determined with NSTAR without royalty relief and a price with royalty relief. And so the price with royalty relief is what we're selling our gas for, and the difference between the two is $1.30 per MCF. Okay.

Or addition. Yeah.

That benefit so far has been about $2 million this year, and it will be up to approximately $50 million over the life of of our NSSTAR contract.

So I know we will reference some numbers here. We can provide the backup to any of these numbers at the request of the Joint Committee.

All right. Seeing no questions—. I have one follow-up. Oh, sure. Representative Colon.

Thank you, Chair. Just a clarification because I was writing $50 million over the course of the contract— or course of the life of the contract with NSSTAR. What is the $50 million? A $50 million benefit directly to consumers. Oh, benefit.

Okay. Thank you. So essentially, our current contract is 40 billion cubic feet, and the $1.30 is $52 million. Okay. Thank you.

Thank you, Chair. Sure. All right. If we could kind of pick up the pace, we have yet another presenter yet today. Sure.

So the next graph—. We're on slide 6. Thank you very much. Slide 6. This is Mike Coy speaking.

Just a couple points I want to highlight on this next graph. This is showing a couple things. In the blue squiggly line is HEX's production from the kitchen lights unit. The orange lines are our fixed contract obligations. So fixed contracts, obviously there's a known customer, there's a known volume, there's a known price.

And there's a known delivery timeframe. Okay? The difference between the blue line, which is our total production, and the orange line is interruptible gas. That gas has no defined customer, it has no defined price, and it has no defined volume associated with any sales. Okay?

Interruptible, by definition, means it's gas that could be available for a customer or it could be available for another customer. The determination of the price related to that gas is typically driven by supply and demand or market forces, where firm contracts have known prices again.

Um, excuse me.

So just skipping ahead here to our price— yeah, okay. A couple things I want to highlight on this graph is that prior to April of this year, You can see that HEX had very little to no firm contracts, which meant we were selling to the open market at whatever price was available in the open market at that time. It just so happens the majority of the gas we were selling during that time went to NStar. Starting April this year, we had our firm contract kick in at 8.1 million standard cubic feet a day. So as of April, We are committed to deliver on a firm basis 8.1 million standard cubic feet a day to NStar, and we have been meeting that commitment.

All the gas above that commitment has been available to sell to available customers.

As John already mentioned, our firm commitment starting April next year jumps up to 26 million and then to 29 million standard cubic feet a day the year after that. So as John mentioned, We are one of the only companies or the only company at the moment that is actually increasing its firm commitments into Southcentral Alaska and also at the same time increasing our firm commitments to NSTAR. Okay, doing it in a dramatic fashion.

And it doesn't take much by looking at this graph to see that when you look at where our current production is, which again is the blue line, with our drilling activity this year, and where the orange lines are in the future, that the majority of our gas that we produce will be going to NStar.

Representative Sadler. Thank you, Madam Chair. And just, Mr. Koch, I'm just looking at the graph again showing a zero production in July 2026. I don't see a line predicting kitchen light production past roughly current date to meet those orange commitments. And is that something I should just be assuming, or is that something missing?

Or help me understand what your projected future deliveries will be, the slide being future.

So you're asking what our future production will be? Or projected to be? Yeah, because it looks like it goes down to nothing.

So in, in July of this year, we had a planned shutdown, which is why it goes to zero. In that period, but then right after that, it comes back up to the same 20 million standard cubic feet a day we're producing today. This is just actual production, but we should be able to meet the demands of '26 to '29 based upon field results. Yep. And that periodic shutdown occurs annually just for maintenance-type procedures?

I'm looking at the 2 years—. Yeah, we had a planned shutdown there where we expanded to a 14-wellheader system. System with shutdown emergency valves that we wanted to install with Udelhoven and others, and Big G was out there. The downtick right there in February is where we— the only buyer of our gas was Marathon, so we had to shut in 35% of our production. No one else but Marathon bought our gas in February.

I misstated my question, but again, I'm just asking going forward, we've got what your commitments are, is it possible to make a projection of what you think your production is going to be? That was that cutoff that I was going to come in. Better be over the curve. Indeed. Yeah.

But that's the difference between us and utilities. Utilities have ups and downs on firm contract numbers, and that's why they go that way. Real life operations and production does what you see over here. We can do that if you want. We can make out a projection.

—Yeah, but—. And we should see the wells coming online in December of this year. And so I think what you were just referring to, Mr. Hendricks, is the fact that a gas well needs to be steadily produced to be most efficient, versus demand does fluctuate. It swings wildly because of our temperature fluctuations.

Well, we just— we produce, what's in the yellow there is contract firm price gas, right? There's straight line. They're easy to drill, to put in there. So sometimes we'll hit above it, sometimes we hit below it, but we mostly always hit above it. Understood.

We aspire to hit above it. And that's what makes storage so critical because you want to be steadily producing, not going up and down. And if we're, And this was built upon 2 wells. If we can drill 3 wells this year, we should be able to meet that 26, no problem. Thank you.

Further questions? That's why we want to hit 3. Further questions on slide 3? Yes, Representative Colon. Thank you, Chair.

Through the chair. So, Mr. Hendricks, you were talking about nobody bought your gas besides Marathon in February. Does that— are you talking about over and above your contracted gas with Enstar? Are you saying Enstar didn't take any of your gas that month? Okay, let's be very clear.

What you see in the orange line is the only firm contracts we have on that graph. So you see back in 2024, our firm commitment, firm contract was only $1.5 million out of $15 million. Okay. And then we had a dead period there. We had no gas.

It was just open market. If you ever commercial fish, right, you got a cannery you're committed to sell to because they store your boat. Right? They want a certain price. They want certain commitment.

And then you got the cash buyers out there on the north line or the south line or in Cook Inlet, you know, and you go to them for a cash buyer. So that's cash buyer season right there. Anything above those lines are selling to the cash buyer. And a follow-up. And February was only people we could sell to.

Represent Klowem to the chair is we the only buyer we had was Marathon for that gas. Instar didn't buy any gas from us in the month of February. We had to choke back 35 to 40% of our production, probably 35% of our production for that whole month. That was available gas, but some people didn't want to buy it. Follow-up?

Well, yeah, I guess they just didn't want to buy it. I was just trying to figure out the dynamics of if the storage is going down, why wouldn't we buy the gas? If you want me to run Enstar, I will.

Thank you. Senator Wielechowski. What was the reason that Enstar gave for not wanting to buy your gas? Ask them. The previous 6 months was the same price that we offered to them February, and then they bought it for the next month at the same price.

That's a question for them, not me.

I don't know, they had to make a decision. They waited it. Now we're having problems. Are we now on slide 7? Uh, slide 7, yes.

Thank you. So this is Mike Coy speaking. I'll be very, very brief on this slide. This is just a slide to highlight, uh, expected delivery, um, versus purchased natural gas, um, by NStar. So what we have on the top row is what NStar expected, and this is from public filings.

The second row is what was actually purchased, and the third row is the delta. Columns are firm, so as we talked about, this is what was actually contracted where we have an obligation to provide, they have an obligation to take. And you can see they expected 1.24 BCF of gas, and this is from July 2025 up through the end of August of this year, and we delivered 1.24 BCF. So we, we delivered exactly what we were required to deliver to them. In addition, on an interruptible basis, they were expecting— and I'll point out, this is a, not a joint expectation of delivery, this is a sole expectation of delivery on NSTAR's part, per I said public filings— on an interruptible basis, they were expecting to receive 4.2 BCF from HEX.

They actually purchased 5.4 BCF from HEX during this period, which means on total they're expecting 5.4 BCF and we delivered 6.7 BCF. So there's been a lot of talk in the markets around, you know, whatever kind of words you want to use. This is our best demonstration to show based on public filings, what the expectation was and what we actually delivered to NSTAR. So again, it's not only the firm, but it's also interruptible or noncommitted gas that's included in this table. The 1.2 BCF— 1.2 BCF of overdelivery relative to expectations means we have overdelivered by 123%.

And if we added in the half BCF that John mentioned for February, It would be a total of 1.7 BCF of overdelivery, or 133% more than expectations.

Thank you. Moving on to slide 8.

So the main point of slide 8 that we want to make is that when Hill Corp was speaking, and not to speak for Hill Corp, they are a development company, they are not known as being an exploration company. And Cook Inlet is by and large a discovered, developed basin, meaning that all the resource that, all the resource that has been discovered is in development, and it has been in development for quite some time. And typically with those sorts of assets, you also have quite a lot of optimization if you have a good active operator, which has been the case here. And those are the two methods by by which we've been extending production, increasing and extending production, is development of known resource and optimizing that same resource. And that goes into the graphs that Hilcorp showed.

And it goes in almost exclusively into the graphs that they showed. What they started to then talk about is imports. And we think that imports do provide a valuable backstop to cook in the production. And I'll go as far as to say that the Hilcorp Harvest project is, is a reasonable, viable project in that regard. Is it?

So it's the appropriate scale, appropriate level of investment to supplement what already exists in terms of Cook Inlet production, Cook Inlet production capability. What Hilcorp does not address and what we wanted to just make sure is part of the conversation is exploration. Is that by and large, the Cook Inlet is an underexplored basin. We have conditions finally where, from an economic perspective, meaning the market price is sufficient enough that it should attract exploration dollars, and that has historically not been the case. And you would expect from a healthy basin to have that exploration potential and prices that support exploration.

So you have your you kind of— your conveyor belt of prospects moving through the system from exploration to appraisal to initial development to brownfield development, which includes optimization here. So the main point of this slide is that commercial conditions exist from a price perspective that should attract exploration dollars, and feel that with that, exploration should be one of the tools in the toolbox with respect to meeting future natural gas supply expectations for Southcentral Alaska. The missing ingredient at the moment, or one of the missing ingredients, is long-term market access or long-term market security. With competing projects of unknown certainty, it creates a market uncertainty that will limit participants as it relates to exploration. So to state that simply is, You need known buyers.

You need known buyers for a longer time than 5 years in order to attract expiration dollars. Thank you. Just for the public, clear statements like that. Representative Elam is online with a question. Representative Elam.

Thank you, Madam Chair. Through the chair, as we continue to have this conversation, do you have any examples of what might make exploration more attractive, specifically if we're looking for that additional 5 to 10 BCF per year out of Cook Inlet production? Is the gas there to be able to do that? What would you need to do, and what kind of incentives would— incentives or relief would be needed to pull that off and find out what you can do there? With the chair's permission, I'll go to the next slide.

Yes, please do. This will be slide 9. Slide 9. So to answer the question, we believe there's, there's 3 main things need to happen here. One is market certainty.

We need fiscal modernization and drilling capacity, and we also need or could use help on exploration— excuse me— exploration and delivery risk. The first thing on market certainty As John mentioned, identifying Cook Inlet as a critical infrastructure that's important for Southcentral energy security is crucial. And along with that, identifying and securing a market for the Cook Inlet long-term is also crucial to help, help incentivize further development, exploration, and help preserve the 2,000 jobs that are currently actively engaged in providing natural gas to south-central Alaska.

Next would be fiscal modernization. So we believe there's some pretty simple things that could, could happen, including extending and expanding royalty relief that would help incentivize explorers and developers. And then if we're talking about offshore, access to additional drilling capability meaning additional rig capability would be necessary. Right now, the only rig available is the Hillcorp Rig 151, the Spartan 151. Just rough estimates, maybe 6 wells a year can be drilled with that well, given the limit timeframe in the upper part of the Cook Inlet.

And with that, I know we and would assume Hillcorp are focused exclusively on development wells. There is no— there's really no time available to spend on exploration drilling activity while meeting our commitments and wanting to provide gas today and in the near future.

And then lastly, I would say these are supplements, is that the ability to provide dry hole insurance is something very simple and used in other jurisdictions. And then there's also the potential of offering some sort of public a partnership where we could take the traditional oil and gas model and convert it more to towards a utility model, which would have benefits both to producers and consumers.

Thank you. Representative Sadler. Thank you, Madam Chair. Yeah, I do see the, the menu of possibilities, and some of those are achievable, some not, and some are— could be delivered by the state and some not. On the dry hole insurance, if that's something that's available in the private market, or is that Is that something that HEC would expect the state of Alaska to step in and backstop dry holes?

Is that insurance available now commercially, private market? No, that's something to be a partnership between producers or developers and the state. And to your— Follow-up. Follow-up. To your knowledge, in your career with BP, has anybody in the state of Alaska in the last 30 years provided it?

Has the state provided that dry hole insurance to any operators? Yeah, not that I'm aware of, no. So it's a new service.

Okay. Mr. Coy, I would argue that a few years ago, the mid-'15s, early '15s, '12 to '15, we had capital expenditure reimbursement. We gave cash credits. That's pretty much a dry hole insurance. It was much more than that.

And so This is trying to take some of the lessons learned from that program and apply it in a more fit-for-purpose manner that allows state more involvement and control in decision-making around those exploration wells as well. Thank you for that. Further questions? Yes, Representative Mears. Thank you.

Through the chair to Mr. Hendricks, I'm curious about this winter's production when you were not not finding the markets you were looking for and having to curtail production. Do you have access or agreements for utilization of third-party gas storage?

No, and I don't need it.

It costs me money to store gas. I'd rather sell it. I'd rather drill more wells and use that as my gas storage. I'd rather explore more wells and have more wells. Prudhoe Bay doesn't put things into storage.

They sell everything they make. Or they have wells choked up and they open them up. You know, it's— you know, it's— but right now our company with our size, we don't need storage. We want to produce. We want to drill.

We have a lot of leadway. We don't need to put gas into storage from us. That's— you know, the utilities can work that, but we're basically purely a drilling, make gas, get it to people.

And that was Mr. Hendricks speaking. Sorry, did you need follow-up, Representative Mears? I just, I guess, a follow-up statement that it's a commercial choice that there is that option and that this is just a business choice to go direct sales rather than going and having some storage. Understanding that there's an additional cost to that, but this is the physical opportunities out there and business choices are different? I think the state would be better if we had more producing wells than storage wells.

And I think with 19 T's being listed, 244 years of potential gas from the reserves that are sitting in the ground in Cook Inlet is a great prize that we all ought to be aspiring to tap. Representative Sadler. Thank you. And I won't be long. Very respectfully, Mr. Hendricks did speak about the issue with Enstar and interruptible gas supply and presented his perspective and some good facts.

I just want to say for the record, it is a matter that is in dispute, and Enstar might have its own views on that. We did have Mr. Sims before us, not specifically on that issue, but in fairness to both sides, I know it's in adjudication elsewhere, but there's two sides to the story. Thank you. I appreciate that comment, Representative Sadler. I was going to say something similar myself.

Did you have something, Representative— or excuse me, Senator Wielechowski? Yeah, thank you. On the exploration side, do you see— where do you think we could get the biggest bang for the buck on that? Is that exploration within Kitchen Lights? Are you talking about exploration in fields that haven't been leased out, or exploration on other properties owned by other companies or leased by other companies?

I think there's potential between us and the Tionik platform, between us and Hilcorp. Is a potential that would be first looked at. And then I think there's, there's a lot of seismic that my predecessor company shot and others in the Cook Inlet where we need to take more of an active role as a state. We shoot seismic and do we actually interpret the seismic? Do we process it and interpret it and then we reprocess and interpret it?

No, we don't. We put the seismic that we paid billions of dollars for to the producers and tax credits. And we put it on a shelf. And we wait for the oil and gas companies to grab it and look at it and have an insight on our lease sale. Really, the state needs to have the insight on a lease sale, especially when you paid $1 billion in seismic.

Follow-up, Senator Wielekowski. Agree completely. And, uh, it's, um, I'm curious what thoughts you have on why that's not being done or how we can maybe change policies or give directives to agencies to make sure that is being done? Because I agree with you completely. That is the path forward.

To Senator Wilkowski, to the Chair, if I was governor for a day or a week, I would basically just say oil and gas needs to have their own commissioner. 10% Of the net revenue coming from oil and gas ought to go to that commissioner so he can allocate funds to process seismic, identify lines and how to develop and permit and permit, put where roads and pads and entice people to bid on our leases. Be careful that you don't overburden with bureaucracy and too much taking the market out of the ability to have a marketplace.

But— yeah, so it's basically a prepackaging. You know, we tried to do this under Walker. You know, but it just didn't get the steam.

All right. I see no further questions. I just want to applaud Hex Fury. You have comments, Mr. Hendricks? One more slide, but it's okay.

That's all right. You're running out of time. Yes. I do applaud your efforts, and I also appreciate that you've illuminated the state state subsidy for the natural gas being produced in Cook Inlet through the royalty relief. That is something that I think most citizens don't understand.

The state is trying to participate with the gas producers in Cook Inlet. I appreciate also that you spoke about the $12.30 price that you sell for. Hilcorp, of course, has a long-term contract right now with our, our gas utility. I understand the price is slightly less than $10. So price is always an important thing with a regulated utility.

They have to meet the requirements that the Regulatory Commission of Alaska places on them to serve consumers with a reasonable price. And so that is really what this all boils down to, and And I appreciate Representative Sadler's comments. There are two sides to these issues. They're business negotiations. And each side has their insight, their perspective.

But regardless, I appreciate very much your presentation today and your emphasis that you are an Alaska company, Alaska-owned and operated. So thank you for that. Thank you. With that, we will move on to Chugach Electric. Thank you, folks.

That's healthy.

Welcome, Mr. Miller. Good afternoon. Thank you for the opportunity to be here. I'm Arthur Miller. I'm the CEO of Chugach Electric Association, and I'm here to really provide an update on our current gas supply position.

And what I would like to do before starting, I would like to recognize I have several board members from the Chugach Electric Association Board of Directors Directors, our Board Chair, Director Mark Wigan, our Board Secretary Catherine Bjørnstrom, and Director Penny Gage. And for the record, 100% of Chuugach's employees live and work in Southcentral Alaska. Thank you for that, I appreciate it. I will—. I'm cognizant of the time and— Mr. Miller, don't worry about that.

You know, I think the committee is happy to hear from you regardless of how long it takes, and they have questions probably. So thank you. I also acknowledge that you are a regulated utility as well, and so you're always looking at price. Yes, we are. Thank you.

Well, to start, there are 3 key points that I would like to make. Uh, number 1, um, Chuuketch is really in a good position on gas supply. And I'm saying that in the context between now and when we're looking at another supply structure, uh, importing liquefied natural gas. Uh, it is essential that we do have gas, not only over the short term but over the long term. We certainly recognize the challenges in cooking that we're all facing.

They are real on a gas supply structural basis. In addition, number 2, we recognize that the structure in Cook Inlet is changing and we are transitioning to an imported liquefied natural gas supply structure. It's not a question of do we want to import natural gas. We would much rather have in-state natural gas. It's a question of making sure we have 100% reliability and deliverability of natural gas for our members, not only today but over the, over the longer term.

Number 3, we recognize that importing liquefied natural gas is really an interim solution to a longer-term solution that Alaska can get behind, whether that's additional development in the Cook Inlet Basin or in south-central Alaska, or a gas line from the North Slope. Certainly we are looking at opportunities to increase our generation portfolio to be more reliant on renewable generation as well.

Are we moving to slide 2? Or actually it says number— oh, it's slide 1. Actually, I can't tell what slide number it is. But you've moved to the next slide. I've moved to the next slide.

And it's headed Chugach Generation Sources, just for people at home that are trying to follow along. I want to emphasize in the context, why is natural gas important for Chugach Electric? 80% Of our generation requirements are met met through natural gas generation, and about 20% is met through renewable generation, predominantly hydroelectric power. As you can see on this slide, our generation is diversified throughout Southcentral Alaska. Really, that diversification, it really is essential for reliability and resiliency.

I do want to highlight The Beluga Power Plant on the top left section of the slide. And really the— not just Beluga Power Plant, but the Beluga location. That really is a key location as we move forward. The Beluga Power Plant was put in service in the 1960s and served as the baseload generation for Chugach Electric's customers in south-central Alaska and also we had during those times, wholesale customers as well. That field— I'm sorry, that power plant is located right on top of the Beluga River Unit gas field, and that gas field is the top-producing field both in 2024 and 2025.

Chugach is a two-thirds working interest owner in that field. Hilcorp Alaska is a one-third interest and the operator of the field. Hilcorp has been really an outstanding business partner, and with Chugach and us working together, uh, for robust development in that field. Importantly, from a strategic and really a resiliency perspective, that location is essential as we move forward, even though we put a new generation that's more efficient in Anchorage. That's with the South Central Power Project and the Sullivan Power Plant, the two most efficient gas generation units in the railbelt.

But if something were to happen to the gas line between Beluga and Anchorage, there's not enough gas that can be delivered to those power plants to serve electric power to residents and businesses in Anchorage. And Beluga serves as that backup resource in the event something happened to that pipeline between Anchorage and Beluga. Importantly, what about an earthquake that damages, uh, some of our power plants in Anchorage? Or a volcanic eruption occurs and a plume comes over. We want to shut down our most efficient, uh, generation that we have and valuable generation that we have and rely on Beluga.

Importantly, Mr. Saugey referenced this, But Beluga Natural Gas Storage is also being developed right on the same footprint as the Beluga Power Plant and the Beluga River Unit gas field. That provides even more resiliency from an operational perspective. Not only is the power plant that is greater than 300 megawatts located on top of a gas field, we will hope to have a gas storage facility that can also be drawn on. That location is also the location of our solar development project, which will be up to 10 megawatts of solar. That's under construction right now.

We expect that will be in commercial operation next year. This will also be the terminus, assuming that AEA and the utilities continue moving this forward, which I believe we will. That's the Cook Inlet Power Link. That's the undersea transmission cable between between Nakiski or Soldotna to Beluga, providing really a critical link. That project is really tied very, very closely to the Bradley Lake Expansion Project, or otherwise known as Dixon Diversion.

That also is a critical additional generation resource by having meltwater from the Dixon Glacier and divert it into the Bradley Lake Hydroelectric Project. I say that because that sip link is critical with that to ensure that we get the necessary generation from Bradley Lake up into south-central Alaska, but also provided in a manner that we optimize our hydrothermal coordination for maximum efficiency purposes. I would be remiss if I didn't identify really the, the cost differential between a hydro project and a thermal generation resource. We are looking at today, and I think if you look at Bradley Lake, you look at Cooper Lake, and you look at Eklutna, at 4 to 4.5 cents in all-in delivered cost of electricity. That compares with 10 to 12 cents at the South Central Power Project or the Sullivan Power Plant.

Furthermore, these projects on the hydro side are 100-plus-year projects, providing tremendous benefit. They also support renewable generation on an intermittent basis for regulation purposes and so forth. So I just wanted to make you aware that we certainly look at additional hydro really as the cat's meow when we look at reducing our reliance on natural gas over the long term. And so we're excited about the opportunity in that area. We are looking at some additional hydro projects.

Uh, those studies are ongoing right now, and we look forward to when those will be completed. We hope later this year. This next chart is perhaps the most important slide for understanding Chugach's natural gas portfolio or our position today. And where we are looking out as we look out into the future. So let me interrupt.

Chugach Gas Supply Forecast is the title of the slide we're on now. Thank you.

The red line demarked as gas demand is the— our demand for natural gas, and relatively flat, but really with a sawtooth, very similar what Mr. Saugey was referring to earlier. Reflecting the monthly differential on a demand basis. Let me walk through this, uh, slide real quickly and identify some key points. Uh, number one, we have a long-term contract with Hilcorp Alaska for natural gas. That long-term contract is now becoming a short-term contract.

That contract expires at the end of first quarter of 2028. The area represented in green is Chugach's ownership interest in the Bluegill River Unit gas field. That represents production levels, actual and projected, from the Bluegill River Unit gas field that are Chugach's. Hilcorp also has a 1/3 interest in that field, as I mentioned earlier. Right now, Chugach is estimating the economic life of that field is through to the first part of 2035, and then that field does not become— is no longer economic from an operational perspective.

The successes, though, that we have realized through really robust drilling programs since 2022 has resulted in a surplus of gas.

That surplus of gas then we can use that and bank that gas to mitigate risk going into the future. And that's exactly how we are transitioning to an LNG import structure. We are making sure that we take that gas that we're banking and we can extend what, what it was about a year ago, our end of the, or our need for additional gas from the end of first quarter 2028 to the end of first quarter 2029. And that's depicted from the black area, the black vertical lines depicted by supply from storage. So we're excited about the opportunities that are there.

We do think if push came to shove, we probably could push that out even further to the right. We do have other tools in our toolkit, but the area under the red gas demand area that's blank, that's in white, Represents gas that we will need to receive through imported liquefied natural gas structure, and we hope additional in-state gas production. That really is critical as we move forward to keep that option open for not only if we do— when we do start importing liquefied natural gas, we want to make sure we have the option to continue supporting in-state gas development. Madam Chair. Yes, Senator Dunbar, question?

Thank you, Madam Chair, and I apologize, I do have to leave at 3 or shortly thereafter. So I might be jumping forward a little bit or perhaps taking a slightly different direction with this question, but this graph is something— this story is something you've told us a lot for a couple years now, and I think we understand it pretty well. I'm concerned about the shorter-term issue with the potential for a gas shortage this winter or perhaps the next couple of winters. And what I've heard is— and I think you indicate here with the purple line— that you do have a certain amount of banked gas. And so my question is, is this banked gas distinct from the 30 BCF that Hilcorp said that they had in storage?

Because I know that they are one of your operators. And secondly, if we had, let's say, a unusually cold winter, and hopefully that's not the case, but if we did and NSTAR came to you and said, "We need some of your gas," could you do that and would it cause you to burn diesel and how much would it cost you to burn diesel? Very good questions. Through the chair, this is separate and distinct from Hilcorp's 30 BCF that they have in storage. This is independent from that.

We have made offers over the last year to work with Enstar Natural Gas. Even earlier, about a year ago, even during the power exchange— gas exchange, we have offered to purchase gas from— I'm sorry, purchase electric power from Golden Valley Electric Association. And they have indicated to us if they have generation available, and they do at certain times of the year, that we could buy power from them. And use that power as a displacement to natural gas that we would otherwise burn and provide that to NSTAR. So we have also— are looking at right now, we have a meeting with NSTAR next week on a potential direct sale.

When we were looking at that earlier, we were looking at over a multi-year period. We don't— I would say it's questionable whether we could serve their needs in the short term. And what I would really be concerned about is not putting all of our eggs in one basket and putting us into a highly risk— risky situation. If we— if they're short this upcoming year, what happens next year and the year after? And I think the decision really is a balancing act of purchasing power from Golden Valley and displacing some of that gas we would otherwise burn, as well as running our own diesel generation on Plant 1 could be used.

Those solutions, however, are expensive. And you're probably— we're estimating, depending on which structure is put in place, anywhere between $29 an MCF to over $40, even up to $60, depending on the structure. So it is expensive. What is important in this is that if we were to go down this path and run or purchase power from Golden Valley, for example, the sooner we know that there is a supply shortage and there's a commitment from NSTAR that we need— that they need assistance, the more opportunities we have available to help them out. Because during the summertime, their reliance on diesel is significantly less And there may be opportunities, and there was an opportunity earlier this year where we could buy power from them, from their coal-fired generation unit earlier this year, which is significantly base-loaded, a lot cheaper than firing up diesel power generation or liquid generation.

A brief follow-up, Madam Chair. Follow-up, Senator Duncan. So I think from the tense of your statement there that that opportunity has passed. But are you saying that perhaps it could be done next summer? Yes.

Through the chair, absolutely. And our, our doors are always open. We want to do everything we can to assist Enstar in making sure that they are able to provide reliable gas service to their customers in south central Alaska. And we will do everything we can to work with them and assist them through that process. And we've identified really three options in that, and that includes gas exchange, that includes running our own diesel generation, purchasing power from Golden Valley, and potentially a direct sale, provided, however, it doesn't put us in a supply limitation into the future.

Thank you, Madam Chair. Thank you. In speaking with Mr. Million, GBA's CEO, he didn't feel they would necessarily have a lot of excess power to transmit south. You know, so certainly that's an issue. If you were to agree to sell some gas to NSTAR— this is very theoretic— would you be expecting them to pay that gas back, that is, return in kind, or would it simply be a price to cover your cost?

How would that work? Our, our strong preference would be to have that gas provided under an exchange structure so we get that gas back, very similar to the structure that we have both with Marathon Petroleum Company and Hilcorp Alaska. I'll talk about that here in a minute. That would be ideal to help mitigate risk. Absent that, we would be looking at if we were to sell them gas, looking and making sure the amount of quantities that were available did not put Chugach Electric at risk.

And then we would look at the opportunity cost of selling that gas. So it would be whatever incremental impact it would be on our system is what we would charge, um, NSTAR for that gas. It would not be on a fully allocated cost basis. It'd be rather on an incremental cost basis. Thank you.

I'll let you proceed. Oh, yes, Representative Colon. Thank you. I had a question on this slide. So I guess I need some clarification on the Beluga unit.

So my— well, you had mentioned in '24 and '25 it had peak production from the Beluga unit. And anytime I've spoke to you, it sounds like it's always been exceeding expectations. And so when I look at the graph, Right? At 2028, when the import facility is supposed to be— or when the contract expires, it just falls off a cliff. So I'm trying to figure out, is that because the field is not producing, or is that because production is going to be pulled back because you anticipate import of gas?

Through the chair, that would be just the decline in the production of the field, and we have a finite supply of gas that we do studies every 3 years on how much reserves are in the Blue River Unit gas field. And that's what we're drawing on. So I would look at this in the absence of not— we do a study, as I said, every 3 years, but in the absence of anything changing on the reserves, that's where that would come from. That gas would come from future periods and bringing it up forward. Okay, a follow-up.

Follow-up. What if Beluga produces more than what this graph is showing? Would you still go to imported gas? Would you just expand storage? Or do you have any idea of what you would do in that case?

Yes, through the chair. I don't see a situation that is going to push out the timeline significantly from what we are operating under. That would have to be a— literally a major, major find. To be able to push out that kind of demand out there. I do not see that this changing our timeline in any material way.

So I know— one more follow-up. So I mean, we've seen these charts on lots of gas fields, and it's generally a slow decline. This is— it's strange to me that it's doing well and then it just drops off in one year. It really goes down in one— And it's all around the import facilities. So is this something— it's just old field, it's got geography or geology there that's just— it's going to die really fast?

Through the chair, yes. I mean, the decline rate on that, in that field, is significant. We've also been very, very aggressive in drilling in that field. We, in fact, working with Hilcorp, 5 wells have been drilled per year since 2022. 5 Wells are planned this year.

3 Have already been drilled. There's 2 additional ones. Um, a very robust drilling program, and that's driving up, uh, production in the field. Okay. All right, thank you.

Thank you, Chair. All right, I see no questions. I'll let you move on. Okay, thank you. I'll go to the next slide.

Uh, this slide really summarizes some of the measures that we are taking on a proactive basis to manage our gas supply. As I just mentioned, we have really accelerated, uh, working with Hilcorp, the drilling program at the Bluegill River Unit gas field. That has resulted in surplus gas that we have available today that we're not using to meet our own generation requirements. That has provided opportunity then to take additional gas and place it in storage. In fact, last year we entered into a an agreement with Hilcorp to have an additional storage option.

Hilcorp Alaska Gas Storage. Right now we have 1.5 BCF of gas available for storage. Today, as shown on the right-hand side of this slide, we have 0.4 BCF in that storage facility. In addition to that, we also have Singza Storage, and we have 1.8 BCF in that storage, and these are as of last month, the end of last month. In addition, because of the successes with the operation of the field, we have been able to reach really banking agreements with both Hilcorp Alaska and Marathon Petroleum Company.

And with Hilcorp, it's called an underlift agreement where excess production that we're not able to use, we provide that to Hilcorp, and under our arrangement, then they will give us the significant portion of that gas back in the future period. And under our arrangement with them, that will start in 2028, in April of 2028, and go through March of 2032. Right now, under that underlift structure, we have 7.3 BCF stored away. In addition, we have been in— entered into an exchange agreement with Marathon Petroleum Company. And right now, we have 1.3 BCF of gas, and that's a one-to-one gas exchange.

This also allows, from a benefit perspective, Chugash to avoid storage costs. And there were questions earlier about the cost of storage, and that's a real— that is a real cost. When you look at storage today and you put gas in storage, it really is putting dollars under the ground and you're not getting any return whatsoever, if you will. It really is a securitization from a gas supply perspective. But it does save us a fair amount of dollars if we don't have to pay for that gas storage on that basis.

But yet, we still get the gas back into the future.

Importantly, when we look—. Moving on now to the next slide, diversity and storage and deliverability. When we look at gas supply, there really are two primary components. It's one is the storage container size itself. How much gas on a volumetric basis that we can get, but equally important is the deliverability of that gas.

And a good example of this is the challenges that we faced in 2024 with CINGSA. At that time, CINGSA was the only commercial gas storage facility in the Cook Inlet Basin, and CINGSA experienced operational challenges with sand and water in one— I think it was in two wells. Because of that, they had to pull back on the deliverability from that facility, which impacted Chugach operations, and we worked together with NSTAR. Those types of events, absolutely being realistic, can happen, and we need to make sure we design a system that we are— have redundancy that we're not relying on one gas storage facility in the South Central Cook Inlet area. Right now, we have 4 deliverability options that we rely on.

We get— we are designed our system, we're just about 95,000 MCF per day. Our peak is just under 60,000. If you see the difference between just under 60,000 And $95,000, that really is a contingency. So if we did have a failure in one of the storage facilities on a deliverability basis, we have other tools in our toolkit that we can draw on from a storage facility. So we get about $24,000 from our interest in the Blue River Unit gas field, $15,000 from our contract with Hilcorp, $41,000 from CINGSA, and then $15,000 under our gas storage agreement with Hilcorp.

As we look to importing liquefied natural gas, on the right-hand side we're projecting a 98,000 per MCF delivery, but we're getting— we're dropping off the Hilcorp gas contract and replacing it with Beluga River Unit gas storage that will provide additional deliverability, but because of the production declines projected on the Voluga River Unit gas field. We expect deliverability from that field to be about 12,000 MCF per day.

One of the things I want to point out when we talk about gas storage, it's also not just about deliverability and storage container size, it's also about geographic location and risk. The Beluga Storage Facility is the only commercial facility right now that's being pursued on the west side of Cook Inlet. And that provides greater, really, resiliency from an operational perspective. There's the pipeline underneath Cook Inlet, the SIGS line. There may be other options, but there is a risk there.

If something happened to that line, that could have an impact on utility operations. And that's something that We put really a tremendous value on the west side of Cook Inlet to mitigate some of that risk. As we look to the future— I apologize, the slide is not showing all the components that we have identified. I'm not sure what happened from a technology perspective, but I will talk about this. This really is a picture of the current gas supply structure in the Cook Inlet Basin.

On the left side is gas produced in state. And that— for Chugach right now, all of— 100% of the gas that we obtain is from the Cook Inlet Basin. That gas can go on the right-hand side either into storage, which is the bottom picture on the right, or it can go directly into our power plants for generation requirements. As we look forward and we look at the importation of liquefied natural gas, that structure becomes a lot more complex. We still have— and I'm looking at the middle part of this chart— we have two pictures, if you will.

One is, is the LNG import terminal, and below that is in-state natural gas. So we are structuring this, and how we're looking at it is making sure that our demand requirements are met. We are in commercial discussions with Harvest Alaska, and as Mr. Sawjay mentioned earlier today, this afternoon, that their capacity was 20 BCF. It certainly is our understanding that that capacity can be adjusted upwards to accommodate additional purchasers through that facility. On the left side, there are two pictures.

One is of an LNG tanker, and then in the mid— and then right adjacent to it with the handshakes, that is a special purpose entity. And what we are doing is we're creating really a, a buyer's club, if you will, where we take participants in the LNG import terminal. And this is open to everyone buying gas, who's interested in buying gas, and doing it on a buyer's club basis. So ideally, we can combine the demand requirements of all various entities. It could be Marathon Petroleum, it could be other electric utilities, gas utilities, but combining our work efforts or combining our demand requirements and going out into the open market through an RFP process and getting the cheapest possible gas we can get on the world markets.

It really is a— I think it's a buyer's club or a cooperative type of a structure is how we are looking at it. It gives us purchasing power. It provides economies of scale. It provides one point of contact. For the marketplace to contact and work with all the participants on a centralized location or a central point of contact basis.

We think that really is an outstanding way to go. We've seen other markets that have been structured this way. And we really want this to be a win-win and get the lowest possible cost of gas for our membership. And I think that's— it's The last thing we want to do is to raise prices, and we need to work together to keep rates as low as we possibly can without jeopardizing reliability. And that really is what we are focused on.

And this is open to anyone, large customer of gas utilities and so forth. And this is something that we're in the process of putting together.

To conclude, I just want to recap. One, we're in a very solid position on our gas supply between now really and when we start importing liquefied natural gas. Uh, hope that— we believe it would be starting in 2029. And, uh, but we, we really view this as a bridge solution and to a longer-term solutions as we look forward really for the benefits of Alaskans and our members and customers that we serve. I also want to know— want to note that we've been working really collaboratively with the other utilities.

We have reached a mutual aid agreement last year with Homer Electric Association. That's not only on gas supply, but it's also on electric power. So if either Chugach or Homer was in a shortfall situation, we would work together And that agreement was submitted to the Regulatory Commission of Alaska. We're working with Golden Valley Electric Association and looking for opportunities to purchase power through that mechanism. I think one thing I was remiss on that I didn't mention, and one of the supply challenges on running diesel generation is making sure we have a supply chain that can provide that liquid fuel on a robust enough basis to make sure we can to continue generating power.

That structure, we can do that today on a very short-term basis, but over a length of time, that would— additional negotiations really would need to take place. And I think we saw some of the challenges that Golden Valley experienced in having to truck gas from Belize last winter. So I think that those are real and they will really will need to be addressed. What's important, However, is that the sooner we know that there's a real issue and we need to do something, the more we can do and the more tools that we have in our toolkit that we can assist. As I mentioned earlier, we have reached out to NSTAR.

It's also our understanding Matt Nusca has offered 1.2 BCF of gas to NSTAR. But I just wanted to highlight that. And at this point, I'd be happy to answer Any additional questions? Thank you very much. Representative Fields.

Thanks to the chair. Yeah, not a question. I think there's been a lot of media attention on Enstar's gas supply, and I think that has sort of lost— Chugach has been planning ahead for energy security for a long time, and I just want to thank Mr. Miller and the board for looking at energy security holistically— more gas, more hydro, more solar, battery storage. And that— I think that holistic solution is right, and just wanted to thank the board for that. You know, whether it's getting covered in the media or not, it is important for our consumers.

Thanks. Well, thank you, Representative Fields. I would accredit people that were running Chugach Electric a decade or more ago— actually more ago— who actually invested in the Beluga field. It wasn't this particular board. Was done decades ago, and that was insightful.

Further questions for TrueGash? Yes. Representative Colon. Thank you, Chair. So, Mr. Miller, thank you for the presentation.

So I'm trying to understand, like you've said several times, that you feel good about where TrueGash is at, but what I'm seeing is really you're gonna get bailed out by imported gas, because even with the diversification, you're still 80% reliant reliable on natural gas, even with hydro and solar and a little bit of wind. And so I'm wondering what happens. I mean, it sounds like the harvest facility is happening. What happens if that doesn't happen? I'm just not— I guess I'm just— if you can explain your confidence about how you feel like everything's going to be okay.

But it does really rely on imported gas, doesn't it? Through the chair, it absolutely does. And I think that you make a very, very good point. And as much as we want to acquire in-state gas, that in-state gas is not available. No producer has come to Chugach and said, I can guarantee and provide gas supply to you beginning in 2029 over a number of years afterward, we don't have that option.

We hope and can support Mr. Hendricks in his efforts. He's doing a great job. Hilcorp is doing a good job, great job as well. We're trying to work together, but I do not see a situation right now that deviates from importing liquefied natural gas under the timeline that we are operating under. If we had another 10 years, I think that could be a different discussion.

You are also correct that looking at additional hydro facilities, the Dixon diversion— I'm sorry, the Dixon diversion and expansion of Bradley Lake will help significantly. But those are long-term projects. The Dixon project, Bradley Lake expansion, really is 2030, 2031 time period. Other hydro projects, we're looking at a 10-year time period out into the future. That will not solve our problem.

What we need to be looking at now though is ensuring that we have, uh, deliverability, uh, and gas supply through an LNG import facility, but also at the same time simultaneously continuing to support development of in-state gas and also expanding our generation portfolio to reduce our reliance on natural gas and increase our reliance on renewable generation. Follow-up? Follow-up, Representative Colon. So you said the imported facility could contract up to 20 BCF? Is that what you said?

Yes, I was referring back— Could be expand? Yes, it could be. Okay, so I think that's over what you guys actually need, but I guess my question is, if that is allowed to expand and get bigger and you're consolidating your customers, what happens to the producers in the Cook Inlet?

I think— through the chair, I mean, I think that it creates a new market clearing price for gas supply in the Cook Inlet Basin. And I think it really depends on the structure of the arrangements that organizations have with Harvest on their— the importation of natural gas and the requirements that they need on that. How much are they going to rely on imported gas versus are they going to rely on gas produced in Cook Inlet. So one more follow-up. Follow-up.

So you— so when I look at it, it feels like the imported facility, especially with the new structure that you were talking about pooling customers, that's going to be difficult for HEX and BlueCrest and others to compete with that kind of price if you're putting all the customers together and they're just selling on the open market. Do you think that that would be a problem? Or like, I guess my question is, could it be an unintended consequence of how you guys are dealing with the import facility? You may actually start to squash exploration and production in Cook Inlet. Through the chair, I mean, there's no question it's going to have an impact on the overall— on the market.

And I think it was alluded to earlier this afternoon is that we really have a monopolistic, if you will, market in the Cook Inlet Basin. Uh, two, two— really, a monopoly is one single producer. Uh, here we have predominantly one producer and then a smaller producer on top of that. The market is changing because of the conditions in the supply chain, and it— that's a fact. There's nothing we can do about that.

We need to make sure at the end of the day that we have gas to serve our members. And that really is non-negotiable. And I truly hope that we get continued success and that Mr. Hendricks and Hilcorp do— continues to be successful in their efforts in developing Cook Inlet gas. We want to support Alaskans, absolutely. But at the same token, we need to make sure that our generation requirements are met.

But our doors are open, um, and we want to make sure that they remain open over the long term. Mm-hmm. Yeah, I understand that. I will remind us that, uh, annual use is 70 BCF. So a 20 BCF import facility is definitely not going to meet the whole market.

And in fact, without NStar, I don't know how it would be economic since they're the big dog in terms of consumption. But we also have BlueCrest. While I realize they were not here today to present, nevertheless, they have an estimated 200 BCF under the Cosmopolitan lease. That DNR is applying appropriate regulatory pressure to get that behind pipe and to consumers. So, so, I think that's something we need to remember.

I wanted to go— I saw Representative Elam had his hand up a moment ago. Representative Elam, do you still have a question?

I do. Thank you, Madam Chair. And through the Chair, whenever I was looking at the gas delivery and the consumption, I noticed there was a lot of— whenever the Beluga gas lines and drilling was happening, you know, I could see where it was making some additional, you know, production. And I'm just wondering, What, what level of Cook Inlet production would you need to see to do any kind of delay in, in your demands for imported LNG? So if, if, if the Cook Inlet was producing, say, 5 more BCF a year, or 10, or 20, what would, what would that need gap look like to get past the, the, what was that, 20 '29, '30 dates that we were looking at?

Through the chair, I think that to address that, we would— right now, this chart, and I should have mentioned this earlier, assumes production drilling wells through 2027, and then does not assume additional wells drilled after that time period. So we would be basically moving gas— adding production to move gas from the out years to to the sooner— to the earlier periods. We would have to have really a significant material impact to push that out.

I mean, it's very speculative for me to say right now, could we push that out another year? Yes, I think that probably could be done with additional, more robust drilling in 2028, 2029. But then we get into a higher risk, higher uncertainty type of a planning structure. And we become really getting more uncomfortable in being able to meet our generation requirements. And this is something that as a CEO of Chugach, I'm very risk averse.

I am not going to take risk and say I roll the dice and hope that we have gas available to meet our generation requirements into the future. So I hesitate to go much beyond that, other than to say, with more robust drilling, even more so than what we have right now, beginning in 2028, we probably could bring some of the gas that's out there and bring it up to a sooner, earlier time period. I don't know that I would be comfortable moving that up beyond an additional year And even by saying even an additional year, I'm talking about additional year beyond 2029, I get really very uncomfortable.

Any follow-up to that? May I follow up, please? Yes, follow up. Yes. Thank you.

Through the, through the chair. So your assumptions are that there will be no drilling after 2027, but yet we're hearing that there's 200 BCF in the Cosmopolitan and we're actively trying to work through getting getting that behind pipe. And then I also know that PEX is also actively trying to do that. Is there any possibility of getting some numbers that could potentially show us what it looks like with some additional exploration? Through the Chair, I'm sorry, I thought you were talking about in the context— your question, earlier question in the context of the Blue River Unit.

I think Senator Giesel mentioned it earlier, the annual demand in Cook Inlet is about 70 BCF a year. There would have to really be significant increases in that production level to— and I think with what Mr. Sauget referenced earlier on the supply limitations from Hilcorp's perspective, I think I would look at it from that basis. And 200 BCF won't even get us 3 years from an overall supply situation, from an overall demand perspective, assuming 70 BCF a year.

Thank you. Thank you. Thank you. I see no further questions. I appreciate you joining us today, Mr. Miller.

I do join Representative Fields in applauding your diversification of energy sources with the solar, the wind, and certainly the hydro, your participation in the Bradley Lake field. It is up to us, of course, to appropriate the money that would match for that subsea cable to actually transmit the power efficiently here to South Central. And therefore divert some of the need of natural gas. I'll also add that in Fairbanks, Eielson Air Force Base is working with Oklo, a nuclear development company that believes they will be able to bring a micronuclear generator reactor online by about 2029. So 2029 or '30.

So there are options. Coming up that will defer some of the use of natural gas. So it's hard to tell what the future will bring. Planning is critical. You know, Eisenhower once said, "Plans are worthless, but planning is everything." And that's really what we're trying to do here and what you've been working on doing.

And so thank you very much. And thank you to, to HEX, who's been here, and of course, Hilcorp, as always. This concludes our meeting for today. Um, and so thanks very much everyone for joining us. Let the record reflect the time is 3:30 PM.