Alaska Legislature: Special Coverage - August 20, 2026 2:00pm

I call— I call this Joint Resources Committee meeting to order. Today is Thursday, August 20th, 2026, and the time is 2 PM. We are here in the Anchorage LIO. Please turn off any cell phones. I'll check mine.

Yes. Welcome to everyone who has come today. This is a hot topic, of course, for all Alaskans. I want to introduce the senators that are present. We have Senator Dunbar, Senator Clayman, Senator Rauscher.

Also online is Senator Myers and Senator Wilkowski. I'm Senator Giesel. I'll turn it— turn now to Co-Chair Fryer to introduce the House members. Thank you, Chair Giesel. Members from the House that are present are Representative Fields, Representative Colon, Representative Sadler, Representative Hall, Co-Chair Representative Daibert, and myself, Co-Chair Representative Freer.

Great, thank you. This is a great opportunity to have a joint meeting. I really appreciate everyone being able to come. We won't be conducting business today. We're certainly— this is an informational hearing, so it's not that we'll be taking any votes.

I appreciate Heather, who is somewhere in Juneau. Keeping the minutes for us, and the Anchorage and Juneau LIOs who are transmitting this. We will have a hard adjournment time at 3:45 PM, for everyone who's wondering. I also want to recognize Representative Holland is here in the audience, and Senator Elvie Gray Jackson. So welcome to other legislators who are here.

Today we're going to be hearing information about our gas supply for Southcentral. We have 3 presenters and, uh, another organization that is here for questions. We have NSTAR here, we have the Department of Natural Resources Division of Oil and Gas, and we have, um, uh, Mr. Curtis Thayer, who is the Executive Director of the Energy Authority. Also present is the Regulatory Commission of Alaska, and they are happy to answer questions, committee members, so if you have any. Senator Tilton is here.

Oh, hi, Senator Tilton. I'm sorry I didn't see you. And Representative St. Clair is here. Oh yes, thank you. Thanks for being here.

And is Representative Mears— there she is. Oh great, thank you. Thank you. I'm sorry I didn't see you come in. So we're going to get right down to business because it's important information.

We have a hard adjournment time. So first up, we'll have NSTAR present. So I will invite to the table the president of NSTAR, Mr. John Sims. There is a a PowerPoint presentation which will be put on the screen. You will see it on the screen now.

And for those folks online, it is posted on BASIS. Welcome, Mr. Sims. Thank you very much for the opportunity to be here. John Sims, President of NSTAR. I am not entirely sure what the committees would like me to go over.

I have some slides here, but they are more kind of foundational or informational. I thought what might be best would be to open it up to questions right away, because there has been a lot of information that has been kind of out in the general public, a lot of comments that have been made. So if it pleases the committee, I would propose that is how we start, by questions. And then if there are some things I can reference in my presentation, I am happy to do that. But I am available for anything that the committee has.

That would be great. When we invited you, the purpose would be to talk about storage. What is the critical element there? Sure. You are also working with Glenfarn related to an import facility, so that's another key piece.

And then just what the supply coming out of Cook Inlet that you're able to access looks like. Further questions from committee members? Other topics? Yes. Yes, Senator— or excuse me, Representative Sadler.

Thank you. Well, you want to let him give the presentation and follow up? But I just, I would ask that Mr. Sims, through the Chair, gave a very powerful presentation at the Gas Line Caucus a couple weeks ago. If you want to recap some of the high points of that, that might help set the stage for us. Sure.

So, through the Chair, Representative Sadler, what feels like months ago, I spoke to the Gas Line Caucus. I don't remember the exact date and probably the words you're referring to are the fact that at this point today, NSTAR is 18 days short of gas, which is the equivalent of 3 BCF. And that's for normal temperatures. And the rationale behind that and how we come to that calculation is we had a certain expectation of gas deliveries from the Cook Inlet at the beginning of the year. One of those— I guess one of those groupings of volumes was from Bluecrest.

Information that we have since received from them is that they do not plan on starting their exploration or their production.

Definitely, originally it was July 1st was the date that they were planning on doing those wells. It is no longer July 1st, obviously, and we're still kind of waiting for that to happen. Now, we did see in the petroleum news this morning. The DNR has made some statements about that, so I'm sure they'll talk about that, and that is welcomed. And I just— I want to say, even though they're here, I would say this if they weren't.

I have not seen a more supportive state agency than the Department of Natural Resources. They have done a fantastic job supporting NSTAR and all the utilities and our needs, whether it's in the attempt to get more storage or understanding the gas supply situation in Cook Inlet. So I just want to personally thank them. For all of their work. They are fantastic, and I believe really have the best interests of the state at heart.

So, Representative Sadler, those statements that I made at the Gas Line Caucus still remain true. Some other statements that I made is that the gas pipeline cannot help 2026, and it cannot help 2027, and probably not 2029. But the point of that is we need to start developing the long-term plan immediately so that we're not doing this year after year after year. So I'm assuming those are the statements you want me to revisit. We are still in the same circumstance that we were back then.

Very good. Senator Clayman. Thank you, Madam Chair. Just because it's the beginning of the school year, and when we talk about years, I know sometimes you all think about a year is a longer stretch. The 18 days that you're talking about, is that in the calendar year 2026, meaning by the end of December?

And that— yeah, that's the first question. Senator Klaman, through the chair. So we do view years a little differently. Uh, so, so thank you. When, when we think of a year, we're, we're thinking of, uh, the winter season, which is the 2026 to 2027 winter.

So if you want to think of what we need to have in storage, we look at September through April. That is sort of our season, and that is the duration of time in which we are short 3 BCF as we sit today. Follow-up, Senator Clayman. And for last winter, the— which would be the year from September '25 to April '26, what was the projection, and did you— how did that work out? In the same context.

Yeah, through the chair, Senator Clayman. So last winter, the 2025-2026 winter was one of the coldest that we've ever experienced at NSTAR. And I think that was similar across the state. Fairbanks is definitely aware of the challenges with the winter conditions. And because of that fact, the amount of gas that we withdrew from storage was significantly higher than anything that we've done in the past.

And I'm now looking brilliant because I've got a slide that talks about some of that. Um, so in the December gas storage usage, you can see what the 2025 consumption was for, uh, the month of December alone as it compares to, uh, the prior 8 years. So significantly more, 1.5 BCF almost was withdrawn from storage in the month of December alone. If you look at the month of March, uh, you can see almost another 1.5 BCF in the month of March alone, and you can see how that compares to prior winters. There was another winter where in March in 2017, we had to withdraw over a BCF of gas.

This is a great depiction as to the challenges that natural gas utilities have with the fluctuation of temperature. And so, you know, the statement that I made, again, referring back to that Gas Line Caucus, we're forecasted to have an El Niño. So that means a warmer forecasted winter. Does that mean it looks like 2025? Where we are actually injecting gas into storage, or does that look like 2024, where we're injecting and withdrawing?

Worst-case scenario, it looks like 2026, where we're withdrawing, you know, gas that we don't have. So this is the challenge that we're talking about, and this is also, you know, you— I've seen recently my name come up as a reference to fearmongering, and they're, you know, crying wolf, all those sorts of things. Well, if the temperature is warm, it will look like I am fearmongering and I'm crying wolf. If it is cold, we'll all experience the cautions and the concern that the utility has. So I hope that answers your question, Senator Clayman.

That's what we're dealing with. I also want to recognize that Senator Kawasaki is online as well. Senator Rauscher. Thank you, Madam Chair. Madam Chair, through the chair.

So Is there any plans to try to compensate for the 18 days? Great question. So there are a couple of things that we are hoping happen. And then there are a couple of things that we are trying to get in the works contractually. So as has been publicly noticed, we are in the middle of an arbitration with HEX to try and get the gas that we expected from them.

To start delivering again. We have not received any discretionary gas sales from HEX since July 26th. We are receiving 8 million a day from them, 8.1 million a day, which is their firm volumes. We were expecting more than that per what we viewed as our contract rights. So that's kind of step number one.

Um, as far as what we're working on in addition to that, we are working on an exchange agreement with Matanuska Electric. And this is really important to understand the current quote-unquote market that we have here in Cook Inlet. Okay? MEA has the benefit of having some gas that they have planned on putting into storage. And that is for the purpose of serving them the latter part of 2028, 2029.

What we are trying to do contractually is they will give us 1.2 BCF in exchange for us sending that same volume back to them by March of 2028. So we're not receiving gas that we get to keep and just, you know, use for our customers. We are taking it with the expectation that we repay it in volumes, not in dollars. So there is not extra gas in this market is the point. It is— it is a very tight commodity right now.

And those are the types of things that we're trying to do to get through this winter.

Is do those types of exchanges where we are kicking the can down the road and hopefully a better solution where we're not doing exchanges but actually able to buy and procure that gas. Hopefully that materializes. Thank you. Before I go to Representative Sadler, I'm going to follow up on Senator Rauscher and your comments. I also have a copy of the letter from August 17th from Chugach Electric.

Mm-hmm. Could you comment on that? So back in early 2026, the latter part of 2025, if I recall, Chugach Electric, uh, you know, we have been talking about these challenges for quite some time. Uh, and so Chugach Elec— Chugach Electric offered up the opportunity for us to do a similar exchange with them, uh, for about 1 BCF of gas. Um, they also had some ideas about, you know, having Golden Valley Electric burn, you know, energy, you know, burn fuel, send it down the Intertie.

That would relieve them of some gas. And quite honestly, in the first part of this year, we were still expecting Bluecrest and we are still expecting HEX to come along. And the price for those exchanges, for example, on the Intertie, as Representative Daibert knows, the costs in Fairbanks are expensive. And so to generate power and send it back down to Southcentral Alaska is significantly more expensive than the other alternatives. So at that point, we still had faith in BlueCrest based on the communications that we had with them that we were going to receive the gas that we were expecting.

That obviously has not materialized. We have restarted conversations with Chugach again, and we are waiting back to hear their proposal on what they can do in this different timeframe. You know, one of the challenges with the exchange, and this goes to like deliverability of the storage fields, is, you know, there is a certain daily volume that electric utilities can send that gas to us. So it's not like we can just say, hey, Chugach Electric, I need 1 BCF of gas and we get it. It doesn't work that way.

It has to come over a series of days because the deliverability that's available is not, you know, significant. So that's one of the challenges that we're dealing with and why time matters and why we asked for that emergency ruling from the arbitrator, because we need gas today so that we can gradually fill that storage as opposed to doing it all at once. That's not a thing. So there are options out there. We are exploring every single one of them.

If both Chugach Electric and MEA those exchange agreements actually come to fruition and we do that, we are still about a BCF short.

Thank you. Representative Sadler, you had your hand up. Thank you, Madam Chair. And through the chair, Mr. Sims, last winter, one of the— we had a little bit of a brownout question or scare when we heard reports that there was some sand getting in well bores at Sengse. I guess a granular question, haha, Sand Greens, is have those issues been addressed or prevented from We assume that the status quo, everything that we have had, we will have, at least in terms of functional infrastructure.

My question is this: Is there confidence that things will operate as expected and needed, irrespective of all the rest of the supply issues? So, Representative Sadler, through the chair, we are always expecting our facilities to operate. Storage is a unique animal. You're relying on wells that are, you know, thousands of feet deep, and a lot of things happen down there. Our expectation is that they operate as designed.

But as we know and experience, they can have challenges from time to time. So that's the worst answer I can give you, but we're expecting it to be the case, yes. Good. Representative Colon, you were next, and after you, I'm going to check in with the 3 senators. So Senator Myers, Senator Wielechowski, and Senator Kawasaki, if you have a question, if you would text me, I will call on you after Representative Colon.

Thank you, Mr. Chair. So I wanted some clarification on the shortages that you had spoken about regarding BlueCrest and Hex. So Hex continuously says that they have increased their drilling, they're doubling their capacity. BlueCrest sounds like there was a promise that didn't follow through.

Was the Hex— is something that you expected them to produce more than they are, or is it all centered around the argument that's happening around the discretionary gas? And is BlueCrest coming on board later and just not getting there in the time you need? Yeah, Representative Kollm, through the Chair. So really good question about HEX. And this is, again, really important for the folks to understand.

I think the preference, and I'm making an assumption here, but I'm doing it based on business knowledge. I think the preference from HEX would be to serve both Enstar and Marathon. But the fact of the matter is, because they don't have the gas available, they have to select which one they're going to serve. Now, Mr. Hendrickson, come up here and tell me that I'm wrong. I don't know, but that's my assumption.

So it's, it's a matter of who gets the gas and at what price are they getting the gas for. Um, so, uh, we had expected a certain volume of discretionary gas sales. They are delivering on all their firm commitments that they obligated under contract. But again, we know that those wells can deliver a certain amount over and above that firm volume, and we were expecting to receive that gas, which is what we're not receiving. Okay.

And just follow up on the Blue Crest situation. How much were you counting on from Blue Crest, and is that coming on board later, or is it just you don't see any end in sight? They're not going to— you're not going to be able to get any gas from them? Representative Cullen, through the chair, back in April when we spoke to a number of you down in Juneau, we were expecting gas to start flowing in our system by September 1st from Blue Crest, and we were expecting about 1 to 1.5 BCF of gas. We now know that's not possible for that September 1st delivery to start.

Now, maybe they get up and rolling, you know, in September, October, November, and that changes a little bit, but unfortunately history has shown us that they're tough to rely on. Yeah, okay, thank you. Thank you. I'll just inject, I have invited HEC to come and speak again to this joint committee on September 10th. We'll talk more about that later.

I have Senator Myers online with a question, and then we'll go to Representative Mears. Uh, Senator Myers. Thank you, Madam Chair. So, um, uh, Mr. Sims, um, you're talking a lot about the short-term stuff, and of course that's obviously a big deal, um, but, you know, anything that we're dealing with short-term is, is going to be a bridge. The question is, what are we bridging to?

Um, if the gas line, uh, does not get built, you know, we had hopes that it could potentially get built and we wouldn't need imports, if we'd been able to start construction this year. But if the gas line does not get built, what is your long-term plan? I know that your contract with Hillcorp runs out in 2033. I believe the electric utilities all have their contracts run out before yours. So what are we effectively— as, as we're going through these short-term issues, if we can solve them, what's the long-term solution?

Senator Meyer, through the chair. So our, our solution has not changed. We are still working with Glenfarn on developing an LNG import project with the hopes that that transitions over to the pipeline. It is the best long-term solution and again, the only one that has the potential to reduce the price of energy.

That requires a couple things. It requires us first and foremost to file and get approval of that contract with the commission. It, it requires us to have a storage solution in place, um, which we do not have yet. Um, and those two things are pivotal, and, and, and one has to come before the other, that we, we have to have a place to put the gas from the LNG import facility. Um, and right now we don't have the storage capacity to do so.

So that's step one. We need to have that storage defined, and then we can execute the contract that allows for the LNG import and for hopefully the pipeline.

There's a lot of discussion about, you know, long-term solutions. We have said many times at NSTAR, the focus needs to be on reliable supply. We have passed the time where we can start asking for a short-term solution that is at a low cost. I've said that a number of times. I've said that publicly.

There, there's no low-cost solution that fixes this short-term or midterm problem that we have today. So if you are searching for lower-cost solutions, they don't exist, um, in the short term. There are some that exist in the long term, and that's going to take some creativity, some support, and some alignment amongst the utilities, uh, the regulators, and the state of Alaska. But there are some challenges there on the long-term side for sure, and we need to address those collaboratively and be very open about those options that we do have. Follow-up, Senator Myers?

No, thank you. All right. Next up is Representative Mears. Thank you, Madam Chair. That's long-term.

I'd like to swing back to short-term a little bit. Through the chair, Mr. Sims, could you put up, I think, slide 6? 6 Has got probably the most realistic, what you're thinking, plan is for storage right now that's kind of out there. You mentioned earlier that the more we do what we do now affects how things are going to be for us in February or so. So the weather is certainly something that is dependent We know from the previous chart that year to year things look very different.

But for the next couple of years, we are relying on ourselves here in Alaska for our solutions. And it's a lot to coordinate utilities, to coordinate big projects. There's some of that certainly going on. We know in the electrical space, looking at battery storage and renewables helps defray those molecules of gas so that they can go into storage so that they're used for the heating. If you could talk a little bit about what are your big customers?

How much are commercial? How much is military? How much are individual residents? And what our opportunities are for us all to take some responsibility and looking at that chart and going, what can we bank into storage now so that we've got more for later? What can we conserve now in August and September and October, delay our heat coming on, turning back our thermostats, those little things.

Like, where are our levers, big and small, for putting more molecules into— or keeping the molecules in storage now so that we've got them in the winter? Yeah, Representative Mears, through the chair. So, that's a really good and important question. And one of the challenges when we're talking about conservation is folks understanding what summer consumption looks like versus winter consumption. And so, today, if you were to go and turn your thermostat, let's say it was at 75 and you turned it down to, you know, 70.

What's the ambient air temperature out there? It's not significantly cold, right? So the amount of energy that's required to maintain that thermostat is not as high as if it were 30 degrees outside. So the demand that's being used in the summertime, if you look at a day like today, we're maybe burning 40 million a day. That changes in the wintertime to 300 million, potentially, in a day.

And so let's say everyone turns down their thermostats, turns down their water heater, that the benefit of that in the summer months really doesn't move this needle. That's part of the challenge that we have. Now, that You know, we always want to talk about conservation. It is always a good thing. But as far as what we can actually do that changes this picture, that's not going to move the needle.

So that's a problem. When you talk about the large commercial customers, that could make a difference. But, you know, a lot of people that I've talked to don't even have their heat on right now. So that's the reality of the situation. It's really nice to be able to say, you know, conserve, but when you think about the actual impact, it doesn't do much.

All right. Next up on the list is Representative Fields. Thank you. Through the Chair, how full is CNGSA right now?

Well, do we have access to the internet? We could bring it up right now. It's public information. Through the Chair, is it full? I'm sorry.

Is it full? Is CINGSA for right now? Representative Fields, through the chair, it is not. It is about maybe half. I don't know the exact number.

And what is important is there are multiple customers in CINGSA. So, NSTAR is one of those. It has the largest capacity of that. And I think we are probably in the— standby.

Yes. What do we have in there? Right now? So NSTAR has 4.5 BCF in the facility right now. And total, it sounds like about 7.

So we have 6 available capacity. You can see on this chart, and just let me walk through this chart real quick because it's really important. You're gonna see 3 different shades of colors there. You've got 103, you've got 75, and 57. That is the deliverability that you receive at those balances in storage.

So as those lines drop into the different color, in the example on the bottom, in November, we drop from 103 million a day to 75 million a day in November. Um, and that's important because that's deliverability. That is what allows us to maintain pressure in the system when the temperatures are cold. And so again, going back to my $300 million a day scenario, we need every bit of deliverability that we can achieve to serve our customers. And that's the issue right there is we need that balance to be much higher so that through the winter we maintain that 103 as opposed to dipping down into the 75 or God forbid the 57.

Can I ask a follow-up? Yes, follow-up, Representative Fields. So there have been some multiple proposals for more gas storage, but since Singsa is a long way from full, how long would it take to both fill Singsa but then fill Kenai Loop, say, if it got built by Enstar or Hilcorp or other— I assume there are other storage proposals out there from other operators. Representative Fields, through the chair, very good question. So I think one of the unanimous conclusions that both producers and utilities have reached is that additional storage is required.

And so you see a lot of development of storage fields right now, and quite honestly, we can use all of them and should be using all of them. So back to the question of, let's say we built AIX storage right now today, we wouldn't have the gas to put in it, so it would be sitting there. Now, we have received an offer on the table as late as last night that said, I will produce gas, you will be required to take it at a certain rate. And in that scenario, under the offer that they proposed, we wouldn't have the storage to fit it. So, so it's, it's, it is used as a market attractor because they will have a place to put their store, their, their gas if they produce it.

But as we sit right now today, I can only take— and really, so here, here's important. See, see that 6 BCF level right there? That's where we want to maintain storage, 8 in the September months when we start pulling on it. And the reason why that's important is this right here. I don't know how much I'm going to pull in March and in December.

So you see in 2025, I had to have room in storage to be able to put it because I have contracts where it's requiring me to take it. So if I fill it up to that 13 BCF and we get a warm winter like 2025, I'm now buying gas with no place to put it. So that's, that's why more storage is required so that we don't have to worry about that balance of, hey, if you produce it, hopefully I can take it. So, so the contract, you know, again, is an opportunity for them to deliver on an interruptible basis. The utility to take it on a firm basis, meaning if they produce it, we have to take it.

It's not quite a balanced commercial agreement, but it might be one that we have to accept because there's nothing else out there. Can I ask one more follow-up? Yes, follow-up, Senator— Representative Fields. So the RCA did not grant preapproval for NSR's proposal for Kenai Loop, but my understanding is there are multiple companies pursuing storage there, and correct me if I'm wrong, those companies can continue to pursue the storage and then seek RCA approval for a reasonable gas sales price based on costs. Am I correct about that?

Uh, Representative Fields, for the chair. So, uh, the commission denied our initial petition for reconsideration— excuse me, our petition for, uh, determination of prudency. We have filed for a petition for reconsideration, hoping that, uh, you know, some of the information that we presented in that, uh, petition, uh, you know, whether they glossed over or didn't, didn't quite recognize it or something, perhaps they can change their mind on that. If they don't, then there are other options, as you pointed out. We believe that they're more expensive than what we proposed.

Okay, thank you. So let me interject a question here before I go to Representative Sadler. Is there— if gas supply becomes short during the winter, is there a list of companies, uh, organizations that you would ask to step back their consumption? Uh, Senator Giesel, so the— there is a defined, uh, curtailment plan in the tariff. Uh, it starts with large industrial customers.

Uh, so the electric utilities, uh, they're the first that we look to. Uh, and then you kind of go from there. Uh, the last on that list are residential, um, schools, churches, hospitals, uh, and You know, there's kind of— it's kind of common sense as far as who we would shut off. This would be a building that we would shut off, for example. It's a— you know, no offense.

You guys didn't do anything wrong. But, you know, it's a large-consuming customer. JL Towers. You look at those large-consuming customers that don't have residential units in them and they're, you know, not a shelter. Those are the ones you look to disconnect.

Certainly. And of course, this building isn't occupied in March. Right? Right. So, yes, that's rational.

Representative Sadler, you had a question. Thank you, Madam Chair. This actually is a question that was suggested by a constituent of mine, a neighbor. And it gets to this, to the question about contract for supply. Now, we're jumping a little around a little bit on the chronology of what happens when.

But we've understood you've testified previous that short-term importation of LNG is going to be necessary to bridge to what I hope will be gas line. So the sources— contracts take time. You have to negotiate, you have to get RCA approval, you have to get financing, et cetera, et cetera. But are you pre-negotiating any contracts for supply, and if so, from where? Representative Salazar to the Chair.

So as the agreement contemplates right now, we are actually not charged or tasked with finding the source. That will be up to the developer. So they will determine that based on availability, based on cost. And from my perspective, as long as it is reasonable, it meets the gas specifications that we require for our system, and it has the lowest cost possible, I could care less where it comes from. So you're neutral— just follow up— so you're neutral to where it might come from?

I am 100% neutral as to where it comes from, as long as it again meets those 3 requirements, that it's first off reliable, meets the gas specifications so it can actually go into our system, and then is at a reasonable cost as compared to the other options. Yes. Thank you. We have 2 more questions and then we'll have to move to the next speaker. Senator Clayman.

Thank you, Madam Chair. Just as a practical matter, you talked about who you would— you turn off this building, you turn off commercial operators that don't have residences. Is that something that's already set up and you sit in your office and push buttons, or is that you're sending people out? I mean, this is a practical thing. I'm getting questions from folks in the Yeah.

In my district wondering, like, what does that look like? Yes, Senator Klaman, through the chair, that is a very, very important question and one that everyone needs to understand. And there's actually an example of this that happened in New Mexico. So if you Google New Mexico gas outage, I believe it was 2017-ish timeframe, New Mexico Gas, they had a similar situation where in New Mexico they had a large spike in demand that was driven by significantly colder than expected temperatures. Uh, they asked for residential consumers to turn down their thermostat.

Instead of doing that, they turned it up, which caused a spike in demand, and they lost 30,000 customers, uh, in the blink of an eye. Uh, that is because there's no longer pressure in the pipelines that's able to be maintained. So what you have to do in that scenario is you have to go to each home and you have to manually shut off every meter You then purge the system because there is a combination of natural gas and oxygen that is explosive. So you have to purge the lines. And then you reenergize the system— I mean, repressurize it.

And then you go back to each and every home and you unlock every meter. That process in New Mexico took weeks. Fortunate in the fact that it was New Mexico and not Alaska. But it is a very manual process. We would absolutely have to call for mutual assistance.

We already have those contracts in place with utilities in Lower 48 and agreements with utilities in Lower 48. An example of when we exercised that last was in the earthquake of 2018. We called on some assistance from utilities in Lower 48, and they were within 24 hours of our service territory. So it is extremely manual. It is extremely— I'm going to use a word.

It's not inconvenient. It's significantly worse than inconvenient. It is a life-changing event that is very challenging, especially in a temperature climate like Alaska.

Brief follow-up. Slightly different area, but the price you buy gas price from producers is market-driven and not regulated, but the price that you sell heat to us is regulated. Am I getting that correct?

Senator Klaman, through the chair, so I get frustrated when I hear the word market because this is not a market. But to answer your question, we enter into a contract with producers. And we file with the Regulatory Commission of Alaska. So that is not regulated directly. It is an arm's length negotiation between us and the producer.

We then take that contract and the weighted average cost of all of our contracts, submit that to the commission, and they bless that weighted average cost of gas. That is what gets charged to the consumer. An example of that, is the Hilcorp contract is right now, you know, around $9. The HEX contract is $12.30 for the firm gas. Now, we buy significantly less gas from HEX than we do from Hilcorp.

Like I said earlier, it's 8.1 million a day versus the potential 162 million a day that we get from Hilcorp in the wintertime. So we are fortunate in that the balance of that weighted average is more towards the Hilcorp contract. As opposed to the HEX contract. So our weighted average cost of gas right now is around $10.80. Thank you.

I appreciate what you say about market. I agree it's more arm's length— on arm's length transactions, a better description. Thank you. Senator Roscher. Thank you, Madam Chair, through the chair.

So I was wondering, a lot of our constituents talk about importing, whether they like it, whether they don't like it. The ability to have that happen now, could you address that or not? The price if that was to happen and when it would happen.

Uh, Senator Rauscher, through the chair, um, so I'm going to be able to give you a very, very accurate price on what the cost for imported LNG via truck is, uh, because we're looking at that solution for the city of Whittier today. Um, that is the only way we're going to be able to serve that community, uh, given the challenges that we had on the, uh, 20-mile pipeline. So I'll, I'll be able to give you a very accurate cost. When we did a test run of this last year, I believe, uh, it was in the mid-$30 per MCF. Uh, the other ways that we can bring in LNG or CNG are by what's called ISO containers, which are very small, uh, containers of the commodity stacked up on a ship.

Similar cost, extremely expensive, and the volume that we can get is much different from an LNG full carrier, uh, like we're proposing in, in the full build-out of the, uh, Glenfarm project that we're working on. So, um, much different, uh, in cost structure, uh, significantly more expensive on the ISO containers, uh, and, and the volumes are difficult to come by. So for example, we couldn't get a contract for 4 BCF or 3 BCF of ISO containers. Uh, it would be unbelievably expensive. So last thing, since you brought up Whittier, it is my district.

Could you explain to the audience what you're referring to when you talk about the pipeline? I don't know that everyone knows. Yeah, no, uh, thank you, Senator Giesel, for that question. So on August 9th, uh, we received a call from a boater going up and down the Twenty Mile River that they smelled gas. We responded immediately, and what we saw in the Twenty Mile River was our pipeline oscillating back and forth, and a crack, obvious crack in the line.

This is an 8-inch line. It was built by the military maybe 30 years ago for the sole purpose of bringing fuel from Whittier to Jaybear. So this is a long 8-inch pipeline that goes through the entirety of the Anchorage Municipality. We converted it to a natural gas pipeline, and we currently lease that pipeline today Upon seeing that pipeline and the status that it was in, we sent out an immediate notice to the city of Whittier, uh, saying, heads up, this is not in a good situation and the potential for a rupture is high. On Sunday, this past Sunday, our gas control was monitoring pipelines in the system as they always do, and they saw an increase in pressure on one side of the pipeline and a decrease of pressure on the Whittier side, which is a strong indicator that there's something very, very wrong.

Uh, we obviously sent somebody down there. Our service technician found, uh, that the pipeline had completely ruptured, uh, which means for safety reasons and per our policies and procedures, we had to shut off that pipeline, which means every meter from that point on lost gas. That in this instance was the entire city of Whittier.

Back dating to August 9th, because we knew that there was an imminent problem that's going to happen, we started contacting LNG vehicles, trucks, IGU, who has a current, you know, setup, Harvest. Everyone was fantastic and great to work with. I can report that the LNG truck that we have procured has made it across the border. Which is a huge win, and we're hoping to have that LNG service in place in the very, very near future. We had originally estimated, given some of the challenges that we were dealing with, that September 5th was sort of the worst-case scenario.

We are now optimistic that it will be significantly sooner than that, but still a very, very challenging situation for the City of Whittier. As everyone knows, the City of Whittier is hustling and bustling with tourism, And they're having a very difficult time during this outage, unfortunately. They cannot cook, they cannot heat their homes, they can't heat water. So it is kind of a worst-case scenario for those citizens down in Whittier, which is why we are working around the clock to make sure that their service is restored as quickly as possible. Another shout-out to not only DNR but BLM.

Kara Moriarty has been doing an amazing job of helping coordinate The City of Whittier, the Alaska Railroad, uh, so many folks both on the federal and state level have done a fantastic job helping us get that, uh, solution in place so that we can get that service date, uh, a lot sooner than September 5th.

Thank you, Mr. Sims, for this— answering these questions. That was a great way to do it. I appreciate it very much, and you have a lot on your plate. Thank you for spending the time here with us today. Thanks to everyone on the committee.

Thank you. All right, we'll move on to our next speaker, which is the Department of Natural Resources Division of Oil and Gas, uh, to talk about what we see in the inlet. So welcome to Commissioner John Krother and Haley Payne, Director of the Division of Oil and Gas.

Yes, thank you. So, uh, unlike John, I will not be riffing freestyle. I do have a presentation that I would like to walk through with you, and so I think we'll have that up in just a moment. Um, but I guess just by way of introduction, um, for the committee, for the record, my name is Haley Payne. I am the director for the Division of Oil and Gas.

I'm very pleased to be here to continue to provide updates regarding the department's outlook on current Cook Inlet production, our forecasts, and I think in this presentation, we're going to be talking a little bit about storage, as that is obviously a primary concern and focus. And then lastly, just providing an update on the activities, drilling and activities we've seen so far for 2026. And I'm here with Commissioner. Good afternoon, Chair Giesel and Commissioner, co-chairs, members of the committee, it is an honor to be here and look forward to sharing information about this important topic. In the interest of time, we will leave it at that and move on to our presentations.

But of course, questions at any time, please feel free to pass our way and we will do our best to provide as much information as we can. Thank you, Commissioner. One of the key pieces we are interested in is the progress on BlueCrest. So, Ms. Payne, I will let you proceed if you are leading off. Yes.

Absolutely. So I'll just start the committee by revisiting a slide that many of us have seen before. This is something that we prepared at the beginning of the year, which is our Cook Inlet gas forecast. This here brings together the division department's understanding of both the continued development of existing and legacy fields, the required in-field activities, development drilling wells, and brings, uh, it back, uh, to combine with what we see as some of the newer gas that may be on the horizon. Uh, just to break this down by the colors that are shown on the chart here, 2025 is showing, um, our, our actuals and, and where they hit right relative to that 70 BCF, which is an average demand line.

Um, that's kind of a stable number from EIA. Um, but obviously there can be some fluctuations within that. There's also, um, denotations within here for the electrical and then the natural gas utility demand, and then Finally, at the bottom, we see the field and industrial demand comes in about 10 BCF per year. So the blue bars on the chart, as I mentioned before, this is really what we're seeing out of our sort of legacy production, the main fields that have contributed a lot. Think Nanilchik, think North Cook Inlet, Beluga River.

As you can see, that production in the future remains relatively flat, going up a little bit, and that is not a natural decline. That shows continuous reinvestment building of new pads and adding new perforations. In the orange on the chart here, we show what's called New Gas, and so I would characterize this as some of the newer developments that are coming in. This is a risked forecast, so what that means is that we have applied certain factors both from the subsurface risk, what we think might be an average well rate based on the last 5 years of wells that have been drilled, as well as economic factors which may contribute. So this isn't the totality of new gas that's available, but this was, from our perspective at the beginning of the year, what we maybe be expected.

And then finally, you're going to see the purple lines, and this is really where the story of storage starts to come in. And so per this chart, any production which comes in over the demand rate we're assuming is going to be socked away into storage and available to sort of meet that balance in the future years. One change to this slide from previous versions is we actually have included sort of a high and a low forecast. And for the benefit of the committee, that's just really starting to understand— we assume a certain rate out of a certain number of wells. And the high forecast is if we actually find ourselves in a position where those wells are performing better than we anticipated.

And so that's what that high forecast is. That doesn't represent a new total development. That represents just those same wells performing better than our mean case. Similarly, the low forecast, it doesn't take into account, you know, some sort of catastrophic event or major infrastructure going off. It's just if the wells that we've forecasted don't perform as well as we would have hoped.

So this is sort of the overall outlook for the department at this time. We are, of course, working on an update right now to this, which we'd have available by the wintertime. But given that this is the summer drilling season when everything is happening, the most robust data will really start to come in in the next few months to improve our forecast going forward. Any questions? I don't see any.

I'll let you move on. We do have limited time. Yep, I will, I will be more brief and concise. Looking forward, just so you can see how we're actually performing relative to the forecast, it's kind of helpful to see if we're coming in accurately. So the green line there is our actuals right now, and the dotted line is our mean case, which was shown in that previous forecast.

We were trending right along that line, actually a little bit above our forecast at this point in time. That's thanks to some positive outlooks or outcomes that came from the beginning of this year. Some of the legacy fields that went into that, specifically Swanson River and some more activity at North Cook. So we are on track for our forecast, maybe trending a little bit above our overall deliverability rates, looking closer to 210 on an average rather than 190 MCF last year.

So, and then moving on to, to slide 3, this is really just sort of another way to kind of understand the forecast slide that is seen in slide 1. This is what the department has been doing for over a number of years is, is taking a look at what are those high confidence reserves? What are those ones that we know can be drilled within the forecast period that have the commitments behind them? And then how does that compare on a year-by-year basis? And so you can see ever since 2009, we're, we're relatively consistent.

Those marks have trended up a little bit, but that's just because as new information has become available, new commitments for drilling have entered, we've unlocked a little bit more gas. Um, but we do have about 800 BCF remaining in those high confidence areas. Um, and that again mirrors the information that you saw on slide 1.

Very good. Next slide.

So here's where we'll start to talk about the gas storage picture. So currently within the inlet, we have 3 active gas storage facilities that the department is helping to manage. There is one additional facility that's actually on federal lands, and that's at Swanson River. So that's not included in that number 3. Swanson River is a, a pretty small storage facility.

It's not a utility-grade one, which means at this time it is only the actual oil and gas lessee that is storing their own gas in it. And that one is about a 4 BCF storage availability— or excuse me, total capacity. Of the 3 storage facilities currently that the state is involved with managing, 2 of those are now regulated facilities. Obviously, we have Singsa as one of those, and been a longstanding one since it was first approved back in 2012. And then we have Kenai Gas Pool 6, which has also been a gas storage facility for a number of years, but has only recently begun to become a part of taking third-party gas.

Both of those facilities have these really wonderful dashboards for yourselves, remember the public, to be aware of. On any given day, you can take a look at exactly how much gas is in there, what are their deliverability rates, what are some other constraints on that. And so I just encourage that as a really great resource. If you're curious. I definitely looked at it very often last winter.

And also, as has been noted, we are currently reviewing 3 new applications for gas storage. One of those applications is up by Beluga River, which is probably one of our more prolific gas fields at this time. And so we received all these applications at about the same time earlier this year. And we do have 2 applications in for the Kenai Loop area, one from Hilcorp and one from Enstar. And so right now we're currently in the process of the review of those applications.

Our public notice and comment period closed at the beginning of July. We're involved in our best interest finding writing process right now, holding technical meetings with the applicants and working with other lessors, AOGCC, and ensuring we're continuing to move those applications forward in a judicious manner. And I can pause here if there's any questions about existing fields or applications. Senator— or Representative Mears. Thank you, Senator Giesel.

So when storage facilities are getting planned, is there any guidance at all from the department on an ideal amount or range that there should be for different circumstances, or is that completely driven by private sector interest? Yes, Representative Mears, through the chair. So the department does not prescribe prescribe a certain strategy for gas storage. We do sort of take it on an applicant basis. And so I would say at this time it's really the— to use the term, the market— that is telling us, you know, when to go ahead and move forward with those.

So we are not prescribing a certain storage facility amount. Follow-up, Representative Mears. Representative Mears to the Chair, Commissioner Jon Krother here for the record. I just would also add that The Alaska Oil and Gas Conservation Commission, the AOGCC, does set parameters around the total volume, the deliverability rate, et cetera, based on the reservoir characteristics. A certain field may be suitable for a large volume but a low rate, or a high rate but a low volume, or somewhere in between.

And an applicant would have to receive an order approving a proposed volume based on geological and technical factors from them. Did you have a follow-up? Yes, please. Representative Mears. I think this is more of a comment.

So this is one area where I'm seeing, and I see this in multiple places throughout the state, is that if there's— we're not planning. And so if the state is taking a larger role in the planning what our needs are, it helps us meeting them. So if we're recognizing as a state state in a larger energy plan that storage is important and we need this much to be able to operate with these parameters, of course, in consultation with the utilities in the private sector, like, you know, where's production, where's demand, where's all that, that can help us with incentivizing things and making sure our processes are making things happen on the timeline that they need to. If this is entirely driven by the utilities in the private sector, It's a challenge when they're meeting internal barriers, which I think we're running into right now. So this is more of a plug for— I see space for larger energy planning, and this is one of those places where we can use it.

All right. We'll do very brief questions. All right? Okay. Thank you.

Obviously, I don't want to interrupt your slideshow, but we're limited in time, so I want to get this question out there. The issue of gas security and supply for South Central and the railboat is very sensitive, scary. It's emotional for people, and it's tempting to want to point fingers and find a scapegoat, someone to blame for this situation. We've even heard from some folks, some legislators who said there's no problem in South Central. We got 200 years of gas in Cook Inlet.

What's the problem? So is that true? Is there no problem? And if there is a— if there is that gas, why isn't it being produced? It's kind of a broad question, but to help answer public questions about gas supply, please?

Thank you. Representative Sadler, through the chair, John Krother here. Um, I appreciate the question, and it's, it's often hard for those of us who work in this every day to take a step back and frame these things appropriately and, and to, to communicate about them in that clear, that level. I would say from the department's perspective, we do have a problem, and that's why we're working to push and maximize development of everything we can today, because if while we have production, we have a well path, you know, wells that have gone in this year, production path that will meet our demands this year, there's no guarantee there won't be unexpected problems with the infrastructure, with the operations, and we could have a problem this year. Of course, we don't want that to happen, as John Sims with Instar said just before us.

There are response solutions to these crises like what you're seeing right now. Unfortunately, they're tremendously expensive, possibly unreliable. And so we have a problem with Cook Inlet gas supply, and we need activity in drilling today to, to keep that— pushing that problem one year down the line. What we've shown in our forecast on slide 1 is that with the activity levels we're seeing, we are pushing that problem out successfully a few years. That doesn't mean it's not a structural problem in the medium and long term.

And not to get into all the other energy solutions or challenges with energy solutions, but, you know, from the department's perspective, we think there's a lot of Cook Inlet gas that needs developing now to make sure we don't have a crisis today. We can't guarantee that there's Cook Inlet gas for 10, 15, 20 years from now. And so we— there is a problem. As we've heard, even the next 4 years, 5 years too. But thank you.

Representative Colon. Yeah, I'll try to be quick. Thank you, Chair. I just want some clarification on the Kenai Loop storage or pore space. From what I have dug out, it's not a very straightforward, simplified issue there.

To me, a lot of— when people talk about that space. Sounds like, oh, well, NSTARS just hit some red tape and, you know, we need to accelerate that. But it sounds like there's several issues. I'm not sure it's all geological, but actually the ownership of the space. I hear that AIX is still producing gas out of that space.

And so from DNR's perspective, maybe just give a little insight of why that one storage space might be a little more complicated. Sure, Representative Colom through the chair. Um, so as you pointed out, there is an existing oil and gas lessee there, and that is AIX. Um, AIX is currently under a suspension of production at this point in time, so they are not actively producing. They have represented to the department that they are pursuing gas storage, um, that they are currently working with NSTAR on that.

They've also represented to the department that, uh, should they not go forward with gas storage, they would restore production. That there is still some volume of gas there. And so obviously, as we are adjudicating applications for gas storage, we need to be cognizant that we're not unreasonably interfering with the property rights held by an oil and gas lessee. Um, so I would say this is a novel situation. We have not yet adjudicated an application where two folks are interested in the same region.

Um, but I, I wouldn't say that there's anything that's necessarily unclear, um, from the department's perspective about how to proceed on it. Okay, just short follow-up. Follow-up, Representative Colom. So, and this is a utility-grade storage facility. There's no— from the department, I haven't heard that there's an issue with storing gas there at the volumes that they want to.

Is that correct? Yes, Representative Colom. So this particular location and its storage volume is very well suited in terms of a utility deliverability rate. As I understand it, in order to meet those same sort of pressures like you see at Cingza, there would be a necessary necessary to sort of add gas, just like we did at Singsa, to keep that deliverability rate. But we do see this as a suitable location and are currently working on our finding, which will detail more of that for the public as well.

Thank you. Thank you, Chair. Very good. I'll let you proceed. I don't see other questions.

Great. And so on this slide here, we're really just kind of looking at gas storage volumes. So what this slide is telling us is what is the cumulative amount of gas that has been injected into storage net of production. So essentially over any given year, just like your bank account, you're gonna make deposits and you're gonna spend some. Um, and so what this is showing us is on a year-over-year basis.

So we, we have that June date there. That's because that's the most recent AOGCC activity. And so this is a bit of a snapshot in time. Um, so for each year from July 1st of the preceding year to June 30th of the year listed, This is showing you how much gas has been sort of added to that storage. Because I understand we're short on time, I won't spend a lot of time kind of breaking down each column, but if you just look at the sort of beginning of this chart, you see in 2012 when Xingzhou was first started up, there was roughly 3.5 BCF remaining in that depleted gas field.

It was necessary for them to inject, I believe, up to— they needed to get the base storage amount up And so they had to add about 7 BCF in order to get their deliverability. And then over the course of the year, they injected and depleted. And so what this is showing you is at a basin-wide level, this is including all of the different storage locations, sort of how has our bank account been doing through the years. And we've had years where we've had much more injection than we've had taking it out. And looking at the overall health of the basin right now, I think, uh, and Star has already discussed some of where Singza is at, and we can see the blue bar lower.

Um, but on the whole, if you look at all of the different storage facilities and total them up, we have injected a bit more gas into storage this year at this time than we had in the previous year. And so that is what this slide is showing you, and I'll take any questions as well. I don't see any questions. So that will take us to slide 7 for those of you online. Yeah.

Also, I will note that Representative Prox just signed a few— signed on a couple minutes ago. Great. So yeah, so we are on slide 7. Again, in the department's effort to keep transparency and the public informed, we have created our own Cook Inlet dashboard that we have linked here. This dashboard covers everything from production to current use to which wells drilled when are contributing to what part.

And the snapshot shown here on the screen is our look at gas storage. And so again, we are aggregating all of the facilities. We're not doing it at a facility-by-facility location. Our data is a couple months behind the real-time information that you would find from CNGSA or from CNI Gas Pool 6, simply because we're pulling our data out of AOGCC. The take-home message here, to kind of mirror what we showed on the last slide, is from a working volume perspective, we're at about 58% on our storage capacity.

And if you look to that little, we'll call it a rainbow chart there on the right-hand side, right now we have about 42.5 BCF between all of the different storage facilities. And if you compare that to our 5-year average at this time, that was 42.2. So there's been some ups and downs, but at a basin-wide level, we're pretty close or a little bit above where we have been historically at this time.

Very good. Slide 8.

And so from the drilling activity, it has been an incredibly busy year thus far. So up through August of this year, Hill Corps has completed 20 gas wells. They've been continuously operating a 2-rig program, be that one onshore and one offshore, or having 2 onshore programs going at the same time. We're very encouraged by the drilling activity that we've seen so far, and we also see that they have plans for drilling 7 more wells before the end of the year. Two of their recent wells were from the offshore using that Spartan 151 jackup rig.

They were able to— they'd planned 2 grassroots wells but ended up doing some sidetracks instead and were still able to hit their target and then hand the rig over for Hex to use for its drilling program. They have their full 100 days that they were seeking. As we understand it, those operations are underway. They're going very well so far. They've got 2 wells down— or 2 wells on the way, and weather permitting, hopefully they will get to a third.

So, and this is all in line with the plan of development that all the different operators submitted to us. So. Very good. I don't see comment here about Bluecrest. Yes, they have their own slide.

All right, I'll let you proceed. Oh yes, it is the next one. Looking forward to this one. Thank, thank you for the lead-in. Um, yes, so, uh, the, the next slide here, we're turning to Cosmopolitan.

Um, and so just by a little bit of background, the Cosmopolitan unit was actually first formed back in 2015. Um, the operator was pursuing the oil opportunities there Um, that first achieved production in 2016, um, and from 2016 to 2019, they drilled 7 wells. We do still have 5 of those wells on production today. And so in June of this year, they averaged about 500 barrels per day of production. Um, starting in about 2022, 2023 for the plan of development period, um, as the, you know, discussion between the utilities and Hilcorp and the, um, further understanding of how firm contracts would look or not look in the future.

Um, the rate in— at which Cosmopolitan Development was encouraged, we began to work more diligently with the operator to set continued timelines and expectations with regards not only to their H10 well, which was for oil, but also for pursuing the Tionic gas. Um, and so through the 2023-2024 period, you'll see in division decisions, um, sort of increasing expectations, lots more meetings and discussions and timelines under which we were operating. Um, when they did not achieve the last of those POD, uh, POD, uh, things in 2025, that is when we began to move the unit into a default status. Now, because this is a producing unit still, you have to go through a different sort of process with them where it's an opportunity to cure before taking your next remedy actions. And the default status is actually done through the Commissioner's Office rather than through the Division of Oil and Gas.

And so I will have the Commissioner speak to that portion.

Thank you, members of the committee. I know this is probably one of the primary topics to talk about here today, and I understand the urgency and the— I know members of the committee have spoken at length about the nature of this issue, and I appreciate those comments because I think they're right on. We do need action. We need it immediately from the operator, and it's a source of public necessity at this point. A couple prefatory comments.

You know, the first is that I want to be very careful to not prejudice anything in the state's position with comments here today, because quite frankly, the operator has a duty to produce and perform. To date, that duty hasn't been met, and we need to be poised to take every action we can in the state's interest. So I don't want to say anything to overly characterize a position, and I'm going to be very careful not to. But I do want to share as much information as possible given the public interest and need to see development here. Similarly, on confidentiality, you know, there's a lot of commercially sensitive confidential things, but we want to share as much as we can up— very much up to the edge of that line because at this time, we just need to see action.

The public needs to know what's going on. I'll probably start with the immediate status, and we can certainly talk through the timeline and the different considerations. They've been a source of tremendous focus of the department for the last year, year and a half. We haven't talked about it much, and as John Simpson, MINSR, said, we all hope for resolution much before now. There were signs that resolution was imminent, but here we are.

We don't see a well being drilled today, and that's a big problem, frankly. But the immediate status is, based on conversations as recently as this week, is you saw a recent letter from our office making very clear statements, very clear timelines. Blue Crest has communicated they will meet those and they will respond as we've requested. Now, as we described in our letter, we don't just need statements that will— that those responses will be met. We need to see action.

And so one of the things the department's looking for as soon as possible— this will be recorded and the Blue Crest folks can play this back, we've communicated it directly to them— the funding for rig preparation activities consistent with the timeline to drill the well as soon as possible. March 2027 at the latest. If they hit any earlier than that, that only improves their position vis-à-vis the state and everyone's position vis-à-vis gas supply. So we want to see as soon as today, as soon as tomorrow, verification that funds are made available by the financing group they represented is supporting their project to restart that rig preparation to get operations going to set a firm spud date. We—.

Their representations to us is that that's forthcoming and that we'll see that. So we're going to appreciate that representation and verify it as soon as we can. We're certainly, as a condition of our letter, we described the need for them to publicly affirm that, and we look forward to working with them to make sure that they do so, assuming that they are able to be successful and restart that, that rig work. And just specifically for the committee, that means folks working down at the Cosmopolitan unit, crews being there, trucks being there, supplies being brought in, the critical elements of the rig that are on site being returned to the rig in working condition. So that it can start drilling that well as soon as possible.

As I said, they've represented that that's underway, and we look forward to verifying that that is in fact the case. There are several other— you know, that's the first step. It's certainly not the only step. We need to see that plan of development submitted that shows support for full funding for that well, you know, not just the rig refurbishment, but the well to be drilled. We need to see an achievable timeline for that well to come online at the beginning of next year.

As INSTAR described, we all hope to see a spud date of July 1st, gas production this fall, whether that goes to CINGSA, whether it goes to industrial users, whether it goes to everybody, that was the preferred base case. We are not there, and that is a problem. And so we need to get that well online as soon as possible. It is my understanding, I am not a drilling engineer, it is a complex well, it is a technically challenging well, we need to see that attempt get started. So when it— when and if issues arise, there can be responses, there can be work to get that gas online and address any technical complexities that come up in the course of the drilling.

So it really, in sum, and I'm happy to walk through the full detail to the greatest degree we can of the history of what we've been doing with the Cosmopolitan unit, but we're really at this crux and precipice. Where it— as I said, the duty to perform has not been met. If that continues to be the case, the department will do everything we can to respond and every possible solution we can in the courts, with our own authorities, with partner agencies. We're still hopeful that we get a solution, we get verifiable proof that a solution is being worked on, and then we see the well going in. So that's where we are today, and we can talk a little bit more about the letter itself, the default notice from last year, or any other questions you all have.

But—. Commissioner, how much gas is estimated to be present in the Cosmopolitan Field? So I think a conservative estimate is approximately 200 BCF. There's reason to think it may be a little higher than that. You know, the truth is there has— there's been a fair amount of work in the overall reservoir.

These gas lenses that are at the top of the the unit that are the targets have not seen production. That's one of our core functional, technical, and legal issues is that we need to see not just oil from— as Director Payne referenced, the historical wells that have been produced, we need to see that gas produced. So on the order, I believe, about 200 BCF is the total resource. We also, as was talked about extensively by the prior presenter, the deliverability and rate is important. We do hope to see some of these initial wells being larger.

So having, you know, a given new well in the inlet right now, 5 MCF, 8 MCF per day. Were we to see a well of 10, 15, that would be tremendous. And so the resource potentially has a large volume in terms of— in our first chart, being able to add to those blue and orange bars, but also potentially has high deliverability, which would be a great, great asset, especially if we have more storage to put that gas in in the summer. Thank you. Further questions?

Representative Calom. Thank you, Chair. Through the Chair, so my understanding is BlueCrest got this lease 2012, and probably 2014 the tax credits were stopped. And so I'm trying to figure out why this company can't get financing to get this thing going. It sounded like to me that they were counting on those tax credits.

They didn't get those tax credits, and it's been kind of a quagmire since then. And then we did see that you guys granted royalty relief to HEX and has certainly improved production. And so, is BlueCrest requested any royalty relief? Is that a policy that would help this thing get going, or are we just under some heavy capital challenges?

Representative Collum, through the Chair, the— I can't specific— the potential status or not of an application for royalty relief is confidential in and of itself. All I can say is that we've worked with every operator who's applied for royalty relief. It's done under the statutory criteria and on the cost specifics of the field. Has to qualify. Has to be proven.

We—. The timelines in the letter are not contingent or dependent on any other action by the department. So we hope to see those fully complied with regardless of the status of any other activity. Do you have a follow-up? Follow-up.

Are you aware of any other operators that would be interested in that field if this doesn't move forward? Representative Collum, through the chair, I would say that were we to not see qualifying actions under the demand letters, the prior default notice, and the state's legal rights, we would work to consider every option in the state's interest to bring in other caretaker operators, facilitate commercial transactions, relinquishment. Everything is on the table. I don't want to comment on the particular status of any other company's plans, but I think the public interest is in production as soon as possible. BlueCrest has that right today, although their default has placed it in jeopardy.

Whatever solution we get, we need it as soon as possible, and we need it to be production-oriented. And so that's why we're hopeful that BlueCrest Representations, that they have that financing and we can and verify it immediately will come true. If that doesn't— if that's not the case, we will be looking for someone to begin production as soon as possible. Okay. Thank you.

Thank you, Chair. Representative Sadler, continuing on the BlueCrest questions. Thank you. Peripherally related, I guess, again, time being of the essence in more ways than one, I would ask in addition to the steps we're talking about with Casa Palatine, we asked some questions about can you loop and sings of storage. What are the other tools in DNR's tool belt that can help us to address the shortage of gas that I look around and count is affecting constituents in 9 of our districts?

So we have a very strong interest in this. What else can you do to help us meet this challenge, this crisis? Yeah, thank you, Representative Sadler. Through the chair, you know, I'll try and shift out of my Blue Crest rut. I spend a lot of time thinking about Blue Crest.

I haven't been dreaming about them too much, fortunately, but it's been a great area of focus, especially these last weeks that we've navigated some of these key crux times.

You know, we mentioned royalty relief earlier. We've provided that to HexFury. We've seen a very positive result there. You know, there's drilling underway at the platform. We hope to see potentially 2 or 3 wells this year.

We hope to see continued effort going forward. That's a condition of the royalty relief, frankly. And it's consistent with the other contracts that, that HEX has entered into. We've also had royalty relief for other smaller operators in the inlet. So that's a tool that we still have.

As Director Payne referenced, you know, we have the ability to make other gas resources available for gas storage. You know, many of the leases in the inlet provide operator storage. So the owner of those leases, in most cases Hilcorp, can store gas under their current rights. But we can work to modify leases for any operator that's interested or depleted fields to make them available for more storage. So, you know, we feel we're using pretty much every authority we already have.

And we, you know, we want to be leaning in to push and pull folks into solutions for this because the market, quote unquote, needs, it needs every bit of help it can to continue to function. Thank you. Very good. Senator Myers, you online commented that you had a question for DNR. Yeah, thank you, Madam Chair.

So, Commissioner Crowther, moving away from, from Bluecrest here, I've had for about the last year or so, I've had some people contacting me talking to me about a potential gas field in the Susitna area, out in the west Susitna area. I was wondering if you could comment on that a little bit.

If, you know, just kind of a— not asking you to be, you know, break any confidentiality or anything, but just kind of talk a little bit about what interest might be there, how far along people are in terms of like permits and financing and things like that? Yeah, thank you for the chair, Senator Myers, through the— or thank you for the question, Senator Myers, through the chair. Um, short answer is yes, there has been some party— there have been parties interested in exploring in those areas. The department supports that kind of frontier exploration, so we've been encouraged and tried to work with those entities as much as possible. I'll let Director Payne speak to the particular status of those authorizations.

The thing I would just note is that, you know, that's a very frontier exploratory type effort, and that's very positive. You know, Alaska has all sorts of frontier exploration opportunities all around the state. We at DNR have a mission to support those, but, you know, we need a near-term verifiable source, and we need long-term opportunity as well. And so I think right now the department, we don't have verifiable confirmed prospects that we put into our forecast, for example. Doesn't mean we don't support people looking for those, and if they find them, let us know as soon as possible.

We'd love to put them in there. But as of today, we don't have verifiable reserves that we're putting into our projections. Yes, for the director, this is Haley Pate, director. Yeah, you know.

So Senator Myers, we did receive an application for an exploration license. Exploration licenses are what we offer when you're outside of our regular hydrocarbon basins. Um, and so specifically, we moved through the process to issue an exploration license in the Susitna Valley area. Um, it did receive a lot of attention with regards to its preliminary finding. Um, we made some changes based on those feedback, um, and had moved forward with our final finding.

But I do believe that final finding was, um, appealed by some parties. And so We're— as that appeal process works its way through, the issuance of that exploration license is therefore stayed.

Very good. Further questions for DNR? I see we're on the last slide. Representative Fields, and then we'll move on to the Alaska Energy Authority. Through the chair, Commissioner Carruthers, you mentioned your ability to push more storage options, and I was hoping you could just just help us understand the full suite of storage options and your role in making sure there is enough storage available should, say, NSTAR get an offer to intake a bunch of gas.

What are those options beyond the applications for Kenai Loop and BRU that are on the table?

Thank you for the question, Representative Fields. If we could flip back to slide 5, we have a map that shows kind of the storage that's on the table today. You know, so we do have the two regulated facilities, Kenai Pool 6 and Singsha. You know, one option I think is expansion at Pool 6 because of its potential size. The AOGCC order we talked earlier, how that's one element governing the size of a facility, that's relatively limited for that facility, but it potentially theoretically could be quite larger.

There's also what's called the Pretty Creek Field, which is a relatively small facility, and there's a federal storage facility in Swanson River that's quite small and relatively de minimis today.

The adjudicating these applications for storage, both at Beluga River and at the Kenai Loop Gas Field, are our primary focus right now to get those out and done in the RCA's review, and I'm not trying to comment at all on on their review, but one of the things they noted in their order very naturally is that regarding the pre-prudency determination is that DNR had not yet acted. And so we want to act and resolve that in the interest of proceeding down that process. So that's our primary focus. As I said, you know, if any other operator identifies a suitable field, wants it to be regulated storage, we will work immediately to approve that vis-à-vis a lease for an existing operator vis-à-vis a new application if it's a competing applicant or a new field. So we're doing what we can on storage, and we do think that if we get Beluga River online, we get Kenai Loop online, and we potentially have an expansion of Pool 6, we would have a lot of storage.

I'm not here to represent that would meet all the utilities' needs or it would meet different scenario needs. But it would be a major step forward in capacity and volume and multiple options if we seek, you know, those problems at a particular well, sanding at Singsa, we would have multiple fields contributing to the storage mix. So we think that there's progress to be made in storage. Thank you. Do you have the staffing that you need to execute all of these approvals?

Senator Giesel, Thank you for the chair. Thank you for the question. I had a cold last weekend, so I'm a little bit below capacity here myself. My deliverability is low. But the— we have a tremendous team of the Division of Oil and Gas permitting, commercial, technical, and I think we have what we need to get these done, and we're throwing everything at it.

Very good. Thank you. Representative Sadler. To follow up to that, a question I often ask people is, is there any law that needs to be changed to facilitate DNR's authority to do what needs to be done to provide gas for our constituents? Any legislative changes that might be made?

Thank you, Representative Sadler. Through the chair, you know, there's no— you know, I don't— I know the governor's put forward his bill in the special session, and that's a critical part of the long-term energy solution. DNR's authorities today to provide royalty relief, to enforce plan of development obligations, to promote storage where applicants— and to approve necessary infrastructure, things like pipeline expansions. You know, we merc— blessedly may be in a situation where we need to expand or add some new pipelines depending on development at some of these fields. And we have those authorities today, so I think we're well positioned.

Thank you very much. I appreciate it. Very good. Commissioner, thank you. Director, thank you for being here today.

Next up, we're going to hear from Alaska Energy Authority.

What we are interested in hearing from them about is the expansion of Bradley Lake and how it might assist in offsetting the demand for natural gas in south-central Alaska. Also the Cook Inlet subsea cable. Welcome to Curtis Thayer. He is the director, CEO, and executive director of Alaska Energy Authority. Thanks for joining us today.

Thank you very much for the opportunity. Just a little bit as we walk through, and I know time is short, with the Alaska Energy Authority. We are the state's energy office, and comes that great responsibility, we have owned assets. We also administer the power cost equalization program, rural energy, which includes powerhouses, bulk fuel, renewable energy and efficiency programs. We have grants, loans, energy planning, RailBot transmission organization, and when you put us on paper, We're a $1.7 billion state agency, one of the larger ones in the state.

Uh, but today we're going to focus on our, what we call our owned assets. And, um, with that owned assets, what that consists of is Bradley Lake. Bradley Lake is 120 megawatt, uh, power plant, uh, it's 27 miles south of Homer. I happened to be there just yesterday with a FERC commissioner. And it generates about 10% of the power on the rail belt.

And what we're looking at doing— and there's another slide— but we're looking at expanding that by about 40%. In addition to that, we are looking at the Cook Inlet Power Link, which is a 38-mile high-voltage direct current subsea transmission line that would give us redundancy on the Cook Inlet that we do not have. In addition to that, we are upgrading what we call the SSQ, the Sterling to Quartz Creek line, which is owned by AEA. And then briefly touch on Susitna-Wontana, because in the last 12 months there's been a significant shift in that conversation that I think just needs to be addressed. We—.

The rail belt does supply 75% of Alaska. And there are 7 military installations on this corridor. And so when we talk about natural gas, we talk about power. 7 Military installations depend on, depend on us.

With Bradley Lake, Bradley Lake supplies, like I said, 10% of the power. We're hoping to do the increase, the expansion for another 5%. To put that in perspective, by a power sales agreement that was done when Bradley was built. 56% Of the power from Bradley goes to Chugach Electric. The second is Fairbanks gets 17% of its power— excuse me, 17% of the power from Bradley.

MEA, 14%. Homer Electric, 11%. And Seward, 1%. And so if we do an expansion, the utilities and AEA agreed that's the same percentage going forward. That is also the same percentage of what their cost will be in the overall expansion itself.

But by doing this, this 40% increase, it's going to power additional 30,000 homes on the rail belt. It would displace 1.5 billion cubic feet of natural gas. So as we talk about what one BCF, it's 9 days' worth of supply. One of the things with this one, if you are looking at low-hanging fruit, this is it. Because this is a shovel-ready project.

We are actually doing geotechnical up there. We have filed an amendment with FERC on it. They have been reviewing it. We have been, like I said, working with FERC. They hope to make a ruling on it or to give us the licensing by spring or early summer of next year.

And the estimated cost is $400 million. Now, in that cost is about $30 million of relicensing that we will have to do in the early '30s, but we can tag it on and actually save money by doing it the same time with the expansion. The expansion primarily will be funded by, like I said, by the utilities. We have been working diligently in the last 9 months on several packages. And when I say packages, and that is, is we've worked with the Department of Energy Loan Dominance Committee.

We have a loan pending with them. We also have one with the department— we're working on one with the Department of Agriculture Rural Utility Services. Both those loan programs are at Treasury rate. One is at 3/8, one plus 1/8. So then there's different ones.

And then thanks to Senator Stevens, this actually qualifies for tax-exempt bonding. Originally construction carries forward to this. And so we're looking at different avenues with doing this. We know it's going to reduce natural gas. It supports reliability that we need.

And what the picture here represents is where it comes off the toe of the Dixon Glacier, and it's a directional drill 5 miles through a mountain, 16-foot in diameter, and puts more water into Bradley, and we raise the dam 16 feet to accommodate that additional water. The original penstock from the lake down to the powerhouse is 13-foot, and that was done 35 years ago, so 16-foot is something that is not extremely out of the ordinary. The direction will be about a 1,200-foot elevation. Just a little side note, Uh, we are actually going to do the directional drill and run the heavy equipment through the tunnel, build the diversion, put the heavy equipment back through the tunnel, and then turn it on. Uh, so it's going to be kind of a unique way of, of, of doing this.

Um, but again, everything from our part is on track. The one thing that would hold us up is if the utilities and AEA are unable to come to agreements on terms as far as how we're going to finance it. Every utility is different. They all have their own independent boards. We all know what the common goal is.

We just need to get there. But again, our goal is 2031, and if we can keep the schedule that we're keeping right now, it could be as early as 2030.

The second item, and this goes hand in hand with anything that we do on the, on the, on the rail belt, and that is the Cook Inlet Power Link, as we call call it, SEPLINC. And it's a 38-mile subsea cable that will be up to 200 megawatts bidirectional power flow. We—. And with that, the target completion is 2032 on this. We do have a federal grant of $206 million that we were successfully awarded, one of the largest in the country.

And one of the— the large— one of the largest that also survived Doge. So we are moving forward. We have identified, but we need a matching $206.5 million. We have, through bonding with utilities as well as appropriations from the state, we have about a little over $60 million that we can match with against the federal, but we are short $142 million. However, this does not help qualify for taxes and bonding.

This does not qualify for the Department of Energy because they gave us the money, so they're not going to give us a discounted loan rate on top of giving us $206 million. And we are working with the Department of Agriculture, but again, we are in a queue with a lot of others. And so that is a conversation— I'll just be upfront— that we're going to have with Juno of where we can get $142 million, because really If we don't— we're upgrading Bradley, but if we don't upgrade the transmission lines, it doesn't make sense. And this also gives us the redundancy, which you'll see here, which is in green, which circles the Kenai Peninsula. So that means we can move power between Kenai and Anchorage and up to Fairbanks too.

And one of the things that, that happened in 2020 or 2019 is we had the Swan Lake Fire. And that took down that line that we had for 4 months. It cost the Northern Utilities about $12 million during that 12 months that they had— the 4 months that they had to get power from natural gas as opposed to having it come from Bradley. And so this is really key to moving that power, and if we have another problem, that we do have that, again, that redundancy off the line. The line that currently serves from Anchorage down to Homer is 50 years old.

Some segments are 60 years old. We have not invested in it. A case in point is Bradley Lake was built to be a 120-megawatt power line, or excuse me, 120-megawatt plant. And at the end of the day, we just used the lines that were serving Anchorage to Homer, turned around, went Homer to Fairbanks, or Homer to Anchorage, and still the same 75 megawatts. So if you have 120-megawatt plant, you're not getting the full capacity necessarily when you need it.

So that's one of the reasons, uh, for these upgrades. Um, in addition to that, we are incre— that we are updating the lines that we currently have from 115 kV to 230 kV. So doubling the size of them. And that's going to help with line loss and transfer capacity. The target for this is 2030.

We estimated the cost to be about $174 million, of which we've identified $90 million we have in the hand, uh, through AEA and through the utilities, through bonding. So we're working on this, but one of the challenges that we have on this project is we have to do the work in the wintertime because we have to go through the refuge. And that's what our permits have us. And so when we look at a shortage of natural gas on Cook Inlet in, in the rail belt, the need for Bradley to be available in the winter, and then also to do the construction, we need to take it down for about 8 to 10 weeks in the winter. And so that's a delicate dance that we need to have with Enstar.

We need to have with the utility partners and also have the contingency of how fast we can put the line back into service even at 115 if there's a need during that winter span. And so it's just, again, it's just one of those things we need to have these upgrades done to move the power more efficiently and to upgrade these lines, but at the same time, our window is the same time that we have challenges.

Now, the issue, one of the things that that has kind of come back to life a little bit is the Susitna-Wontana Hydro Project. And the AEA has the authority granted by the legislature, statutory authority to move the Susitna-Wontana Hydro Project forward. You know, a little bit about Susitna-Wontana is the Bureau of Reclamation did several hydro studies back before statehood, before we found natural gas, and had all these hydro projects. Bradley was one of them. Susitna was one of them.

Snow River was one. All across Southcentral, this is how we're going to power Alaska. We found natural gas. 50 Years, we weren't looking other than Bradley, looking at hydro potential. And back in the 1980s, the state invested again, looking at it, and set it aside.

2010, We had the renewable goal of 50%. We moved obviously past 2010. The legislature in 2011 moved it forward and authorized AEA to pursue it. The state invested through AEA $200 million towards a FERC license. And then the license was put in abeyance by the previous administration.

The current administration pulled it out of abeyance. For the project. However, no money has been spent on Sissetona-Wahntanna in FY 2027 fiscal. Just a little bit about the snapshot of it. It's 705 feet.

It's a 42-mile reservoir with a width of about 1.2 and an installed capacity of 618 million— or 618 megawatts. So when you put that into play, that's about 22 BCF of gas. So it will displace gas. It doesn't solve the problem. It takes the rail belt electrical utilities about 50% of their need.

You throw in Bradley with the expansion, now it's 65% of their needs. So it helps there. It doesn't help home heating. And that's something to remember. We're not building Susitna-Watana for home heating.

It's for electrical and also military would be a large customer. Construction jobs during that time to just to kind of show the capacity of us, 32,000 jobs. And the projected cost is about $8.7 billion. Why this has now come to the forefront by a lot of people is last year in the big beautiful bill, There is investment tax credits for hydro that if this is started by 2033, it could qualify for up to 50%. So it's half-price hydro, in essence.

And so at some point— and that's where we look for this opportunity— the state needs to decide, do we want to move forward and hope to— and help the cost be $4.3 billion, not $8.7, if the feds are going to pay for half of it? But those do have a lifespan.

One thing too with any hydro, this hydro, Bradley Lake, it's a 100-year hydro. You know, the best time to build hydro was 30 years ago. Bradley proves that at 4.5-cent power. The next best time to build hydro is today. And when you look at this project or we look at the cost of the Bradley expansion, we We carry costs for 30 years, 40 years, 60 years, it's free, other than O&M.

When we look at Bradley Lake and that expansion, after year 30, 35, our O&M cost is $500,000. So once it's paid off, $500,000 split among 75% of the population, it isn't even— it's a fraction of a cent. And so that's something that anybody has to look at. One thing also is, is the cost savings over 50 years on the project is $7.5 billion over what we are projecting to pay to what the savings would be. You know, one of the challenges, like in Fairbanks, they're paying over 30 cents a kilowatt.

If this had stayed on track, in the fact that it takes 11 to 15 years to build, we would be cutting a ribbon and Fairbanks would be having about 8-cent power. And we could have, could have, would have, should have, but that should be a bumper sticker, but it's where we're at today. We didn't do it, and so now we, you know, it's a missed opportunity in this regard. One thing with Susitna-Wontana just a little bit is we did do 19 completed studies. We have significant process in 39 of those studies.

This is just a map of where it is off the Susitna River off above Talkeetna. But here's where the project timeline is. So even if we decide that we want to pursue this, perfect case, we're a good 15 years away. This does not solve our problem today. And it's a long— it's a longer-term solution.

And it's a solution that, you know, is a 100-year solution at a set price. But again, it's 15 years. It doesn't solve our immediate problem.

You know, and really, just to be upfront, governor and the legislature need to decide the next steps. You know, we need to confirm our licensing statutes. And just to let you know, Department of Energy is very interested in working to help figure out where we are in the licensing that we did, because FERC and some of those requirements have changed. Now we got FAST-41, we have different procedures. And so we might— it might be cheaper to— it might be cheaper to do licensing— to complete the licenses than originally thought when it was put into abeyance.

We obviously need to update the project cost and estimates. One of the estimates that we used back in 2014 is that oil was going to be $105 a barrel, so we betted at that. Oil is less than that, so that's a cost factor we've got to look at. We need to update the economic impact analysis, review technical and environmental and the market data. And then we need to consult with FERC, landowners, utilities, and stakeholders.

So it's not saying we need to do this. We actually need to figure out is there enough here to move it forward to a point that yes, we want to go into FERC, or we just say no, we're going to put this on the shelf, keep it on the shelf, and it's not going to happen. But it's just the tax credits make it kind of that— gives us the push to look at.

And really, you know, with anything, you know, as far as AEACs, and that is for, you know, the rail belt as a whole, we primarily work with electrical utilities. But obviously long-term is going to be a gas line or something where we can monetize North Slope gas. Not only for the South Central but the rail belt because Fairbanks needs pipe gas. It's a lot more on their economy if they had pipe gas. It solves a huge problem down here.

And what AEA is working on, you know, we don't have a silver bullet. We have some options and we have positive options. But even our best-case options gets us to the 50%, 60% level, not to the 100% that we need. And so I just, you know, going into it, just a realized expectation of what we can do and what we're offering to do with what we see as low-hanging fruit. But with that, I will leave it there.

Thank you, Mr. Thayer. We have time for one question. It will be from Senator Dunbar. Sorry, Zach. There's an armrest.

I had sent a note. Thank you, Madam Chair. On the HVDC line, you'd mentioned $140 million. So there are— have been active conversations in Juneau about trying to get some of that money into the capital budget or finding a way to get it to you. And there's a disagreement.

Debate about whether we need to get it immediately, whether it can be spread out over 10 years. So I know the preference is to have it all at once, but given the fiscal realities in Juneau, how much do you need and how soon to keep the project moving forward? And sort of what's the drop-dead date by which we have to have $140 million additional in hand for you? By our— by the federal grant, the project has to be completed by 2032. 6 Years.

We have to have it done. We are on track with funding to meet the 2032 deadline. We have $60 million right now, so we can access $60 million of the $206 million. And one thing the Department of Energy wants to see is a line of sight, is because we have held— we have not found new funding in the last 2 cycles or 2 you know, fiscal years. And so really, if we had 2, 3-year lead time, that's what we need the money in, probably within 3 years.

And we can get you the exact cost estimate because we have enough funding for the next 2 years, but now we're going to have to make a deposit on the cable itself, and they require up to 30%, plus we got to get a ship in, and we're going to have construction. So we kind of have a a little bit of a low— a high peak coming up, low peak, back to high peak, transit down. But we don't have 10 years. We probably have a 3- to 4-year window of identifying the funding. Thank you for that.

It is a question that we've had. So we are at time. I do want to mention that next week in Fairbanks is the Alaska Defense Forum. I suspect the military— it's a 3-day forum. I suspect the military will have a lot to say about energy.

It's a big issue for them as well. We are going to be meeting again. I want people to know that our next meeting will be September 10th at 1 PM in this room. We are inviting Hilcorp, HEX, and Chuugetch Electric to the table to talk about their views of energy solutions. So at this time, thank you everyone for coming.

Thank you to the committee who arrived today. And at this time, we will stand adjourned. The time is 3:45. 5 PM.