Alaska Legislature: Senate Finance - June 16, 2026 1:30pm

Call Senate Finance Committee to order. It's 1:30 in the afternoon, State Capitol, June 16th. Present today, Chairman Olson, Chairman Steadman, Senator Keehl, Senator Merrick, Senator Senator Koffman, Senator Cronk, and myself, Senator Hoffman. We have Senator Wielekowski and Senator Meyer here as well. We have two items on our calendar this afternoon.

The first is the Department of Natural Resources' Cook Inlet presentation. And then we are going to go to the discussion of the Fairbanks Spur Line's wishes on getting a line there. So we start with the Department of Natural Resources cooking with presentation. I invite to the table Hallie Payne, the Director of the Division of Oil and Gas, Brian Fitzpatrick, Commercial Manager of the Division of Oil and Gas. Please introduce yourselves.

[FOREIGN LANGUAGE] Haley Payne, you can go ahead and get on the record and begin your presentation. Yes, thank you. Good afternoon. For the record, my name is Haley Payne. I am the Director for the Division of Oil and Gas as a part of the Department of Natural Resources.

I am joined today by—. Ryan Fitzpatrick, Commercial Manager for the Division of Oil and Gas.

And yes, we are here before the committee today to respond to discussions last week, um, where questions arose regarding Cook Inlet production, um, as well as the, the management of the life cycle, um, including end-of-field life for Cook Inlet assets, um, and specifically with the discussion around dismantlement, removal, and remediation obligations, also known as DR&R. Um, so I'll begin the presentation, uh, just by orienting the committee and the public with a little bit of information about Cook Inlet production history., and then transfer into a little bit about current activities. Um, and then, uh, my colleague Ryan will move us into some of the contract questions with regards to those specific contracts in place with utilities, um, and how that relates to our current, um, gas forecast for the inlet. Um, and then finally, we will talk about some of those contract obligations for DR&R and some of the bonding or other financial securities the department has in place to ensure those. Thank you.

So we're starting here on slide 2. This slide is gonna provide that historical look back that I mentioned. As you can see, a few points on this chart to note. There have been roughly over 30 different fields that have contributed to Cook Inlet production throughout its history. At any given moment, there's really about 5 that are responsible for the lion's share of that production.

We did have for a number of years agrium exports and LNG exports that really carried Cook Inlet Gas through some of its major production history. And then most of that came to an end in the 2010s. Another thing that I'd like to draw the attention of the committee to is if you look over the last 6 years, those sharp production declines that we did experience have really flattened out. Now we're seeing decline rates closer to 1% per year, which this isn't a natural reservoir performance. This is really just sort of emphasizing the amount of exploration, the amount of in-field development, and a tremendous amount of investment by those producers that are currently involved in the inlet.

We can even see some wedges where that production has increased. Notably, we have the Kitchen Lights field also coming into play as well. And if there are no questions, I'll take us to the next slide. Thank you.

So this slide looks over some of the recent activity, just to kind of give a sense of the current state of the state within the inlet. On the right-hand side of the slide there, we have a pie chart that shows those fields which are really contributing that sort of lion's share of production. Some of those are some of our older legacy fields like Kenai and Beluga River, where we're seeing a lot of new developments taking place. And then we also have on the left-hand side all of the well activity. So in 2025 alone, we counted 22 development wells.

On average, when we do our forecasting, we have an assumption of around 15. So this is showing even more activity than was maybe originally anticipated. Just to sort of walk around the inlet there, on the west On the inland side, there was a number of activity at Pretty Creek and Beluga River, 3 and 5 wells respectively. And then for the offshore, for the use of the, the jackup rig during the summer drill season, there was activity taking place at North Cook Inlet and at Kitchen Lights and at Granite Point for a total of 7 wells last summer. As we understand it, looking ahead, the producers are looking to put about 27 development wells online so far this year.

And there has already been 14 wells drilled thus far. All of those have been onshore. A lot of that activity again has been in the Niddlechick area and with future plans looking for Beluga River and Pretty Creek. And that is sort of the current status of activity in the inlet. Is there any questions?

Great.

So the next slide will likely be familiar to many of you. This is the the department's—. Identify yourself for the record, please. Oh, apologies. Ryan Fitzpatrick, commercial manager, DNR, for the record.

The next slide should be familiar to many of you. This is the department's fall 2025 gas production forecast for Cook Inlet. I do note that it's the fall 2025 forecast. As many of you may be aware, we had a rather cold winter— over winter in South Central. That did lead to more gas being withdrawn from storage over the winter.

This slide has not been updated for that. We do see in kind of the near— near-term excess production that we expect to go into storage. And so the additional gas volumes that are withdrawn from storage this past winter would likely show up in the early 2030s when additional gas volumes are required to be withdrawn from storage. In order to balance out Cook Inlet needs. I'll draw the committee's attention to a couple of things about this chart.

Number one, you see that green dashed line at the bottom? That represents a 10 BCF figure for gas use to support ongoing drilling and development within Cook Inlet. And so that's what's used to keep the fields actually on stream and producing. Mm-hmm. And then above that, the bars you see, the blue bars, blue part of the chart represents production from currently producing fields and wells.

The orange part of the bars that you see are projected new drilling and development wells. And so that's the additional gas that's coming on stream through those development wells. Some of that will have already shown up with some of the wells that drilled in 2025 and the 14 wells that were drilled in 2026. Again, just referencing the fact that this is a 2025 forecast. If the committee has no other questions, we'll move on to the next slide.

This slide presents information regarding the current state of utility contracts for gas in Cook Inlet I will mention the department is not the agency that administers these contracts. These contracts are overseen and administered by the RCA. We pulled this information from the RCA database in order to provide the committee with a snapshot of the current state of contracts for gas supply in Cook Inlet. You can see the majority of that gas is contracted to Enstar through 4 different contracts. There are two contracts for Hilcorp, the larger of which is a firm gas contract for 28 BCF a year that runs through March of 2033.

There's an additional option contract for additional gas for 4.4 BCF also with Hilcorp. Instore also has a long-term option contract with HEX. That's the operator that operates Kitchen Lights unit. For up to 9.1 BCF a year. That is more than Hex, I believe, is currently producing, but with some of the additional wells that they are planning to drill, they expect to get up to near or around that 9.1 BCF figure in the next few years.

And then finally, there is a contract with Bluecrest for all available gas from the Cosmopolitan unit. Right now, that gas is produced incidental to oil operations at Bluecrest., and so it's a relatively minor amount, but there is the possibility that, that unit could produce additional gas in the future. Um, going down the list, we see additional contracts for Chugach Electric. They also have a contract with Hilcorp, but Chugach is also a part owner of the Beluga Field and sources a large portion of its gas from its interest in the Beluga Field. That field is declining and it is an old field.

And so Chugach's ability to source gas from that field is declining over time, but it still produces a large amount of gas for their use. And then Matanuska Electric and Homer Electric have their own gas contracts. Matanuska with Hilcorp, and then Homer Electric with Enstar, and so they source their gas from the Enstar utility. Thank you.

So this slide goes back to the Cook Inlet gas forecast that we looked at two slides ago. What's different with this chart, you will see the line of black dots that start out in the near term, right around that black dashed line that represents the 70 BCF of approximate Cook Inlet gas demand. And those black dots represent the total of that contracted gas plus the, the 10 BCF of field use gas. And so we can see over the course of the next several years through 2028, those contracts do provide the, the 70 BCF number, or potentially a little bit more, through 2028. But those current contracts begin to fall off in 2029, and so you see the black dotted line begin to decline faster than the estimated decline rate in available gas.

So at some point, those contracts may be renegotiated or additional contracts let, especially as additional drilling takes place and those operators have a better idea of what's available. But it does indicate the state of contracts in Cook Inlet for utility gas. And then again, as I said, that also includes the 10 BCF of field use number. So the state of committed gas in Cook Inlet.

So again, for the record, my name is Haley Payne. Director of Division of Oil and Gas. This part of the presentation is really gonna start to look at how DNR manages the production in Cook Inlet. And so just to start the conversation, we thought we'd kind of point to those underlying agreements and contracts that we have in place with the operators. So development production is managed under our lease contracts.

The lease is what grants the producer the right to produce the state's hydrocarbons for a share of the royalty and associated rentals. Most often when it comes to production, you do not see production strictly at a lease level. The pools or fields are often quite larger than the lease itself, and so we unitize, or bring those leases together under a unit agreement. The unit agreement really echoes a lot of those commitments and requirements that are in the lease, and sometimes takes those to another sort of level and adds further requirements. A lot of what we do is managed through that plan of development.

Um, that is an annual requirement, uh, that comes with the, the unit agreement. And it's in the plan of development where our technical team really gets the opportunity to explore and dig into the data alongside the operators. Um, see how the fields are performing, understand what activities are planned, be that surface installations or further well drilling., and review and approve those plans, and when necessary, create modifications on those. And so it really is through our plan and development period, and right now we are, um, in our current POD cycle, really looking at Cook Inlet and a lot of those assets at the given time.

Any questions?

So we're on slide 8. Slide 8 is just kind of a look at the current Cook Inlet oil and gas infrastructure that we have at the moment. There are 24 different units and fields that produce natural gas thus far in 2026. We have 17 offshore production platforms, 6 of which are not in a producing state at this moment. We also have 3 active gas storage facilities, and then we do have, 3 new applications for gas storage applications at this point in time.

2 Which are gonna be close to the Kenai Loop area and 1 which is up in Beluga River.

Seeing no questions, um, here on slide 9 we begin to talk about what is the cessation of production sort of look like. Um, so DNR has the ability, it has a number of different sort of authorizations that it can use to manage the land. So discussed previously, we have the unit agreement, we have the lease contract, and we also have other tools that we work with, such as easements, which can hold surface infrastructure, and opportunities like suspension of production to work with operators as we continue to fine-tune and understand some of the dynamics that are going on the field. Thank you. So when you imagine sort of that end of field life, it often sort of comes as a bit of a domino effect.

You'll see the unit itself be extinguished or voluntarily terminated, and then we'll kind of get down to the lease level itself, and those leases may be expired or terminate, and then we do also have easements, which can preserve surface infrastructure which is remaining. Sort of an example of this that we have going on presently is if you look at what was formerly the Middle Ground Shoal unit, uh, that was closed back in 2023. And so a couple of those leases now remain and function as lease operations. And then we do have surface easements in place for any of the infrastructure platforms that are not currently covered by an oil and gas lease. And so it's sort of a phased approach where we continue to work with the operator, understand any future beneficial uses, and of of course recognize that there are other regulating bodies that are involved when you come to the end of producing life.

AOGCC, for example, is responsible for the plugging abandonment requirements, and so we would, of course, time and work with them to understand how the end of our lease coincides with their own management authorities. On the right-hand side is the example from our lease form for Cook Inlet, which is that sort of rights upon termination. Lots of words there, but it basically says that you have the duty and obligation to remove all surface improvements as directed by the Commissioner. And then there's a time laid out in the new form leases of up to a year to institute that plan. In some of our older leases, it's 6 months.

And then we also have the ability to require financial assurance instruments to sort of ensure performance along with those obligations. And our next slide will talk a little bit more about that.

So the next slide talks about financial assurances for oil and gas leases and units and other forms of bonding that either the department or other departments within the state may require. One of our principal bonding or financial assurance instruments is a financial assurance agreement. It's a contract that's negotiated between the oil and gas operator and the department that will require a certain level of bonding throughout the life of an oil and gas field during its operations. The purpose of that is to guarantee that at the end of field life, when it comes time for those DRNR obligations to be performed, that if there is a default on the part of the unit operator, that the state has access to funds sufficient to offset the cost of that DRNR, and essentially to guarantee performance. You know, if there is a default of any sort, those funds can be seized by the department.

In addition to that contractual financial assurance agreement, there are other forms of financial assurance that the department that the department requires or that other departments within the state require. So for instance, there are bonding requirements independent of that financial assurance agreement. DNR requires a statewide operator bond for all oil and gas operators. There are bond requirements that are put into place for surface access easements.

In part, some of those— sometimes when negotiating those financial assurance agreements or other bonds. We may require parent guarantees if the operating entity or the leasing entity is a subsidiary of a larger corporation. We may require a guarantee from the parent entity of that subsidiary. We can put into place sinking funds, so money is deposited over time where a unit is in operation, oil or gas is being produced and sold, and So the cash flow into the bond matches the expected cash flow from the units. We can look at insurance contracts or require specific forms of insurance as well.

And as mentioned before, we frequently interact with other state agencies, DEC and AOGCC, to coordinate our bonding requirements with their bonding requirements and make sure that the fullness of those bonds overlap in such a way that we're sufficiently guaranteeing performance for the state. Many of those come with periodic evaluations or reevaluations of either the— frequently both the state of the party itself, the operator or the lessee. If we find ourselves in a position where that operator or lessee looks like it might be financially distressed, that may be be a time where we have reevaluate our bonding and actually increase the bonding required of that entity because we perceive that entity to potentially be more risky at that point. Additionally, those periodic reevaluations will also look at the total cost of DR&R, and so we reevaluate that on a periodic basis, and that may also lead to an increase in the bonding requirements. Thank you.

So can you go over what an estimated remediation cost might be for a well? Timeframe? Um, the—. Through the chair, the specific costs of remediating a single well can vary dramatically in the state of Alaska. It depends on a lot of factors.

Is the well onshore or offshore? Is the well, you know, close to infrastructure, or is it an exploration well that might be off infrastructure? Does it require an ice road to get to the well? Is it something that you can drive a rig up to and plug and abandon as part of it? And so there's really not a good way to provide a single number in terms of what the cost of DR&R in a single well in the state of Alaska is.

When we go through that DRNR estimate, that's something that we definitely look at is what type of unit are we looking at in terms of the financial assurance that we're gonna require? What are the variations in cost that might be associated with that particular unit or development? And how are we protecting the state when it comes to requiring financial assurances for that? So, Senator Steadman. Thank you, Mr. Chairman.

Well, that's all well and good, but I think the concern here at the table is the viability of Cook Inlet. I don't think we're going to build an ice road out in the middle of Cook Inlet to get to a platform. So we need, I guess, a little more specific information on Cook Inlet and the operators. Is there discussion with the operators on the eventual termination of Cook Inlet, or is it going to— is it still a going concern with this gas line coming, or what— and what is the status, and how many operators are out there that you have to deal with, and which ones have, in aggregate, have posted bonds or parental guarantees or sinking funds or insurance? I mean, it's— we need more specific data to do our job.

Senator Sedman, through the chair, for the record, this is Haley Payne. So to answer your question regarding some of the future of Cook Inlet aspects and how the department views it, the department plays a very active role in continuing to work with the operators and manage the conditions of the fields. Where we're really focused is on that supply side. Our interest is in ensuring that the activities taking place are continuing to move forward. But these activities are going to take place within the greater market context, right?

And so where those different demands come in and the contracts which are approved for those rates are, as my colleague indicated earlier, more under the purview of the RCA. However, with that being said, you know, the department sees, you know, a lot of future in terms of the development of Cook Inlet gas. Thank you. In that we have not had any conversations with an operator that signals that X specific date this goes offline and things like that. We do see a role for Cook Inlet in terms of, certainly there will be some transition when it comes to bringing in either an alternative fuel source, be it a gas line or LNG import, and necessarily the way DNR manages and supports the development of those fields will match those market conditions at the time.

The sort of look outlook, we are not aware of any one contract that sort of prescribes all Cook Inlet demand into the future. And so were there to be contracts for Cook Inlet gas that can come in under that sort of marginal amount, I believe the bill before you has like a $16 sort of contract threshold in it, then certainly Cook Inlet gas would remain competitive with that, assuming that all of the demand of the future is not already under contract. Our forecast also does not necessarily account for other potential uses of Cook Inlet gas, you know, be that new demand things if it comes to mines or data centers, et cetera. And so these active conversations, these plans of development will be where we continue to sort of work with the operators under the market conditions, but we will not necessarily be the agency responsible for setting what that overall demand profile looks like. Senator Steadman.

So if I'm hearing this correctly, we shouldn't be concerned about the longevity and viability of Cook Inlet, that there's high likelihood that they'll be able to sell their gas into the very small market with a very big gas line coming down possibly? That's the concern.— some of us have that Cook Inlet, operators could get squeezed out, and then we face some economic issues dealing with Cook Inlet? Yes, Senator Sedman, through the chair. I mean, certainly, you know, as I showed on that sort of current Cook Inlet production profile, you're seeing a real sort of stabilization in terms of that decline rate, and that's because of a lot of investment. The operators understand that they have the opportunity to recoup to recoup that investment with the well plans that they're making right now.

And so were we to see a situation where the payback periods or the, you know, sort of incremental value of that production doesn't have a full clarity on the payback period, then you may anticipate some of those well plans changing or responding to that market constraint. And then that would exacerbate decline in those particular fields. So I think— Thank you. At this point in time, there's a lot of different sort of commercial negotiations and opportunities for that demand to exist. But DNR is not currently sort of privy to the review of those contracts and would not be setting those conditions.

It would be merely trying to support the operators as they respond to them. Senator Steadman? No, thank you. Thank you, Senator Steadman. Senator Kaufman?

Thank you. Kind of all around on the same topic. So I'm looking at slide 4, which has the gas supply and demand. And I'm just— I just want to kick around the modeling of this a little bit. So what I'm wondering is, you know, the supply is very activity-driven.

So you drill holes, you know, you get lucky, you find stuff, or if you're smart and lucky at the same time. That's kind of how that game works. So I'm wondering, is slide 4, is it real if you impose upon it the changing economics of the impending gas line? Are people going to— and I know you just said that the plans can change, but I wonder, have we as a state, have we explored it to the extent that we they need to, to get an idea of it, because there's a number of things that are involved. There's, you know, the investment, the employment, the— everything that went into developing and continuing to run and maintain and find gas, which is incentive-driven by the idea that that gas will have a market.

But if you know that the market's about to get obliterated by this, you know, this big thing coming at you, I think the activity set is— it's going to drop off. I think there's going to be a precipitous lack of interest that will occur. And I just wonder, do we have line of sight on it? It's awesome that we have a gas line coming and that it could potentially provide this huge supply and then, with the right economics, a huge economical supply. But I wonder, do we have line of sight of managing the change?

Yes. Especially in Cook Inlet, there's resources that we could potentially be stranding if we don't have the right change management plan for what's coming. Our models could be off if we're not looking at suppression of key activity. And then the next thing, there's storage plans that have been discussed, but the very skill set that will manage and develop and maintain those, those storage wells, that's the same skill set that's out there now, and that could dry up if there's not ongoing drilling program that's keeping that skill set and equipment there. So one of the things I've been wondering is against this— [FOREIGN LANGUAGE] —this big picture, you know, we think of managing the resources of Alaska for best benefit of the people, and taking that into totality, considering the magnitude of the change, the schedule of that change, the anticipated things that are coming, what can we do to avoid creating a place where curves don't cross at a comfortable level and we somehow crash a system and end up having to buy gas that— because we've somehow driven down interest in production and all that goes with it.

And we've also created a big capability gap along with the loss of employment, reducing the value of investments, and then creating this big decommissioning piece of the puzzle that we have to do. It just seems like a very complicated piece of this thing that needs to be managed through.

Senator Kaufman, through the chair. So I might start with a little bit of the underlying question regarding this modeling that we have here. What we have before us today is a model that's really just looking from a technical perspective. It's, it's just considering a certain plot, a certain number of wells, a certain return on those wells, and what we understand to be sort of a risk associated with that. This model before you today does not include something that would say that there is not a space within the market for these wells to go to.

That is not currently something that we have modeled. So this is just looking at the actual performance of the fields themselves.

To your point regarding the, the need for services in gas storage, certainly as Cook Inlet has become a more mature basin, I think other producers have come before the committee and testify, and, you know, we have seen declines in the service companies available. There have been changes in the amount of equipment and skill sets available to manage those. And so certainly it could be forecast that as that continues to shy away, then you would lose some of that capability. Again, DNR's sort of remit under this is to work with the operators under their sort of economic constraints in which they're working. Thank you.

We do not have the capability within our command to sort of set up if there would be space within the market to still allow that. But again, it shows as you look at— pardon me if I slide here to slide 6, we can kind of see those contracts that have already sort of been reviewed and approved. And so I think we know that there is necessarily demand for those, and then we can review that alongside what we understand the demand load to be be. And so ensuring that something in the future allows the space for Cook Inlet production to continue to be a part of that would be certainly a reasonable concern and focus. That is not, unfortunately, the purview necessarily of DNR under this current rubric, but we would work with the operators within the market constraints.

And, you know, there are other aspects of Cook Inlet. Cook Inlet isn't just— gas location, right? Cooking with oil is really important to the state. Marathon and their refinery, for instance, I mean, they have the refinery tool to that specific oil. And so in the last several years, we've had a lot of focus to be on gas necessarily for the heating of our homes and electricity, but we may see other instances where with the influx of gas, more affordable fuel gas, then we may be actually able to increase some oil production out of the inlet.

And so with some of that oil reduction benefits, perhaps we would see some continued support for those support industries as you referenced before. So yes, it is multifaceted, absolutely, and DNR is here to support how we can on that supply side. But some of those market constraints are things that we are not currently participating in. Senator Kaufman. Thank you.

I threw a lot of stuff at you. It's kind of a cloud of considerations. It's a high-class problem. I mean, if we're talking in one way about an abundance of potential coming from one direction, that's maybe going to stress the other. But with all the entities involved, what I've seen is that there's a bit of— there's silos.

So one group looks at something with a very specific lens. So, you know, RCA looks at with their little lens, and what I see in this— these little composite zones that people are looking at a bigger picture that I don't know how that gets managed for optimal benefit. You know, we don't want to somehow inadvertently strand resources. You know, we're trying to solve that problem. So somewhere there needs to be— and I'm not sure where it sits— that optimization plan that's a piece of what the state is looking at as we manage transition from Cook Inlet as the primary energy driver of the inlet or of the rail belt and now possibly this new thing replacing it.

So I just want to be sure that that's out there and we start to think about who's thinking about that because I think people are thinking about pieces right now but not the whole piece of it. As I said in a prior hearing, we've been where you have a lower price contract for gas and then that's infilled with higher price gas. Well, we're starting to get into the reverse where we might have higher price gas that is the base and where's the room for the lower price gas to squeeze in there and maybe come in, you know, under the price of the slope gas plus the tariff, you know, that's applied for transport. So I think we need to look at how that's going to be managed for to the best benefit. It doesn't necessarily have to be in this bill, but it is a piece of the puzzle that we have to think about, I would argue.

Comments, Ms. Payne? Yes, Senator Kaufman, I believe the department would obviously lend any support it can in terms of understanding and working outside of those silos, as you have indicated, um, and that this is a holistic picture, right? And, and none of us have the, the full line of sight of when these other alternatives may come on. But as you pointed out, that difference in price is really what sort of changes the viability of different fields. I mean, we have instances where a unit was closed within Cook Inlet in 2018 because it was deemed to no longer have an economic purpose, and then just this last couple years that Those leases were rebid on, that same operator picked it back up, and now we are currently in production on that unit again with 2 wells just this last year.

So changing economic conditions most certainly impact, you know, what is that, that field and what is that obligation. I would say at this point in time, uh, DNR is not sort of actively predicting or managing when what field goes in at what price, but we would of course support in any way we can our producers and recognize the constraints under which in which they are operating. Further questions by the Senate Finance Committee on the presenters? Seeing none, we'll take a brief at ease while we wait for the next presentation. The next presentation will be from the Alaska Gas Line Development Corporation and Glenfarm regarding the Fairbanks Spur Line.

We feliz.

Senate Finance Committee back to order. I'm going to change course a little bit here and take up the Regulatory Commission of Alaska.

Spur light presentation from contracts, tariffs, and process before the Commission. We have Mark Johnson, the Commissioner, Joy Gordagner, Advisory Section Manager, and Clara Knudsen Latta, Utility Engineer Analyst. Please go ahead. To come forward. Oh, they're online.

Please introduce yourselves and proceed with your presentation.

For the record and through the co-chairs, good afternoon. Presenting today from the Regulatory Commission of Alaska are Advisory Section Manager Joy Gordonare and myself, Utility Engineering Analyst Claire Knudson Latta. Commissioner Mark Johnston is available for questions if necessary. Please be aware we currently have maintenance ongoing in our building, and if the sound becomes difficult to understand, don't hesitate to speak up, and we will try and find a workaround. Next slide, please.

At the request of the committee, today we will be discussing the general —tariff and contract processes to provide a framework for any filing for the Fairbanks Spur Line that would need to be made to and considered by the Commission; what we currently know and what we don't know about the Fairbanks Spur Line that would inform a Commission decision; the impact of pending legislation on Commission consideration of the spur line; and at a very general level, the impact of— Uh-huh. And impediments to system-wide cost recovery. Next slide, please.

Through the co-chairs and for the record, this is Joy Bordenare, Advisory Section Manager. In the context of utility and pipeline regulation, a tariff is the legal document that defines all rates, including joint rates, tolls, rentals, and charges collected, and all classifications, rules, regulations, and terms and conditions under which utility or pipeline service is provided. Essentially, it is the agreement under which the customer takes and the utility provides service. The individual pages of a tariff are referred to as tariff sheets. A utility or pipeline carrier that is filing its initial application will typically file an initial tariff including inception rates, which is reviewed as part of the application.

Inception rates do not require the same level of cost support as is required under later rate revisions. See 3 AAC 48.275. A tariff advice letter or tariff filing is made by a utility or pipeline carrier to amend elements of its Tariff tariff filings are considered informal filings and typically do not receive a public hearing or require parties to abide by ex parte rules, allowing for open communication between the filing entity and Commission staff. Tariff filings are reviewed by advisory staff at the Commission who present their recommendations to the Commissioners. The Commission is required to act on a tariff filing other than an initial tariff within 45 days for utilities or 30 or 90 days for pipeline carriers.

Actions can include approval, rejection for form and filing issues, or suspension into a formal docket for further investigation.

Next slide, please. Questions on slide 3?

Slide 4.

I repeat, confirm. Yes, slide 4, please.

Fuel and power supply contracts and transportation agreements are filed by entities with the Commission with a tariff filing. Generally, the Commission reviews fuel and purchase power agreements to ensure rates charged are just and reasonable. Statutes provide specific guidelines for agreement review. AS4205-141(d) AS4205-141(d) requires the Commission, when reviewing a gas supply contract, to: One, recognize the public benefits of allowing a utility to negotiate different pricing mechanisms with different gas suppliers and to maintain a diversified portfolio of gas supply contracts to protect customers from the risks of inadequate supply or excessive costs that may arise from a single pricing mechanism. And two, consider whether a utility could meet its responsibility to the public in a timely manner and without undue risk to the public if the Commission fails to approve a rate or a gas supply contract proposed by the utility.

Precedent agreements and related contracts executed by pipeline carriers under AS4208 must be filed with the commission and, if it is determined that they were not negotiated at arm's length, be reviewed by the commission. AS4208.320(c) AS4208.320(c) provides a definition of an arm's arm's length transaction. Next slide, please. We have questions. For the record and through the co-chairs, this is Clerk Nixon Latta.

We have slide 4. Questions? Senator Keehl. Thank you, Mr. Chairman. Could you give us just a brief description of what it would be not to be an arm's length contract?

I appreciate the citation, but I don't have the statute book in front of me.

Thank you. Yes, Senator Keel, through the co-chairs, for the record, Joy Cordonaire, the definition provided at AS4208-320C is a contract is negotiated at arm's length if it incorporates the recourse tariff or if it doesn't incorporate the recourse tariff, is negotiated between two —state-owned parties or is negotiated between unaffiliated parties. The Commission can determine a precedent agreement or related contract is negotiated at arm's length if the parties are affiliated, if it is substantially similar to a precedent agreement or related contract between unaffiliated parties, and the formation of the precedent agreement or related contract was not affected by unlawful market activity or unfair dealing.

Senator Kiel. Thank you, Mr. Chairman. That gives me something to chew on. Thank you. Further questions on slide 4?

Slide 5, the Fairbank Spur Line.

For the record and through the co-chairs, this is Claire Kniepzen-Ladas. Significant questions remain regarding how any Fairbanks Spur line might be regulated. Having reviewed filings in the Federal Energy Regulatory Commission, or FERC, docket CP-17-178-000, it appears the application by the Alaska Gas Line Development Corporation, or AGDC, did not include the Fairbanks Spur, and thus, it is unlikely that FERC's May 2020 decision extends its jurisdiction over the spur. AS4205.711(s) AS4205.711(s) exempts AS4208 pipelines from regulation under AS4205. And AS4206.601 exempts the same pipelines from regulation under AS4206.

Thank you. Not knowing who will construct or operate the line means that the commission cannot answer questions about whether the spur will be economically regulated or not. Additionally, the commission cannot speak to whether the operator will seek certification under AS4206 or AS4208. At the last presentation, A question was asked about whether the contract or common carriage would be a better fit for the Fairbanks Spur Line. Both paradigms have benefits, but the Commission cannot take a position in favor of either to avoid the appearance of conflict in future filings.

Does anybody have any questions? Yes, we have a question from Senator Steadman.

I guess I need some help understanding all the fancy language. Mr. Chairman. Mr. Chairman. Here we're talking about Alaska statutes and rattling off numbers. A lot of us don't have the statute book in front of us, especially those at home are probably ready to jump out of their chair and run out the door.

So could you back up a little bit and put this more in common language when you reference a particular statute, what it is you're talking about, so people can follow what you're saying?

Yes, sir, my apologies. AS4206 pipelines are common carriage and AS4208 pipelines are contract carriage. So what that means is AS4206 pipelines are essentially open to all comers, whereas AS42— excuse me, AS4208 pipelines pipelines carriage must be negotiated by contract in order to access the pipeline. Senator Steadman. And can you swap back and forth with your filing if you decide to be a common carrier and you want to go into a contract carrier, if you're a contract carrier and you want to go into common carrier?

And why should the public or the legislature have any interest in what type of carrier it is?

Through Senator Steadman— excuse me, to Senator Steadman through the co-chairs, this is Clark. Sir, to the best of my understanding, the answer is no. You apply for a certificate under either contract or common carriage, and if you wish To to switch, you must reapply for— you must abandon your certificate and relinquish your certificate and reapply for a new one. So it is a fairly intense process to obtain that new certificate and provide a different type of carriage.

Senator Steadman, why should we have an interest in this? Why is it important for us?

This is Commissioner Johnston to Senator Steadman through the chair. I think that it is important in looking at whoever the owner is of the pipeline and the methodology that they determine that they want to utilize in order to have shippers on the pipeline. Pipeline. So if, as Glen Farn has suggested and the presentation that the committee had from Mr. Sims of Enstar, they have a contract, Glen Farn has a contract with Enstar. So that would most likely make this pipeline a contract pipeline because there was an article in the— Yes.

News this morning that Glenfarn is also in negotiations with Chugach Electric and that they are looking to have a contract. So it is going to be the owner or developer of the pipeline that determines under which statute that they apply for the certificate, whether it be contract or common carriage. And based on what we know at this point, that they are are negotiating a contract with Instar and they're negotiating a contract with Chugach. It appears that it will be a contract carrier certificate that they request. Senator Steadman.

And then help me understand some of the history because a decade or so ago or longer, we spent a lot of time dealing with what we were calling a common carrier, an open season access, when we were struggling trying to— open our basin for more competition as it evolved, our oil basin as it matured and production was declining. And also when we're looking at previous gas line proposals dealing with access into the pipeline on the slope, so when new entrances come in and happen to have gas, they would have potentially the ability to deliver it to market.

So can you help me with the top end of the pipe scenario? You were talking about the delivery end, but what about the input end?

Senator Steadman, through the Chair, this is for the record Commissioner Johnston. I think that as a developer looks at developing the project, project and over time the goals may change and as the developer changes. And when you have common carriage, you have a single set of rules for everybody. So if there's a single set of— much like the highway. You— everybody has to drive 55 or 65.

And so we all— commerce can come onto to the highway, but they all have to follow the same set of rules. And so putting the resource into the, I'll say, supply end of the pipeline, everybody has to file the same set of rules if they are a common carrier. If the developer, as the project changes, so there is a new developer, in this case Glenfarm— Yes. They determined that it makes more sense to allow for entry into the supply end of the pipeline to be done as a contract between initially South Central Utilities and then, as the pipeline evolves into export, but they would do the contracting with the suppliers. Mm-hmm.

On the North Slope, that they will put the gas in based on a contract that they have, and it will either be supplied to a utility in South Central, or it could potentially at some point in the future be exported to foreign markets. I don't know if that answers your question, sir. Senator Steadman.

Quite a ways. So— Then under a contract carrier, we could potentially squeeze out gas producers if we don't like them or got some other issues or we have capacity issues? How does that work?

Senator Sedman, through the Chair, for the record, Mark Johnston. At the RCA don't do anything related to that. The contracts are signed between the owner of the project and somebody wishing to use the project in the initial phase pipeline. That would be access to the pipeline to move products. So— Again, we don't have specifics from Glenfarm because we have not seen we're not receiving an application from them related to this pipeline.

But if somebody owns the pipeline and somebody wants to ship on that pipeline, what would most likely happen is that the two parties would get together to negotiate a contract. Now, as we mentioned earlier, with contracts, the terms don't necessarily have to be the same on the contract. [SPEAKING SPANISH] I don't know that there would be any incentive on the part of somebody that had capacity on a pipeline to not utilize anybody that wanted to ship on that pipeline to fill it up as much as possible. Senator Steadman. Yes, concern is if we have more capacity to ship gas than we have availability in the pipe.

It's just something we've struggled with in the past, but I'll go on to other things. Senator Steadman? No, I'm fine. Further questions on slide number 5? Please proceed.

Just— Senator Steadman? Just so I'm clear, 'cause this is— I thought we were gonna talk about the spur line. Do you regulate the spur line? Who regulates the spur line? Make sure we understand that issue.

And there's FERC, they do the main line.

Commissioner— Senator Steadman, through the Chair, this is Commissioner Johnson for the record. That is part of the unknowns at this point. As Ms. Knutson-Latta mentioned, mention that it was— the spur line was not included in the initial application filed with FERC. And as such, we don't know who will potentially regulate the spur line. We don't— we, the RCA, don't know who will construct the spur.

We don't know who will own the spur. And all of those things will go into determining who potentially will have regulatory authority over the spur. Senator Sedman, we were planning to have the presentation by Glen Farnon on the Fairbanks Spur Line and get some of those questions answered, whether or not they were going to be submitting another application to FERC, who would be managing it, and all of those questions. So all of those are undetermined questions to be possibly answered by our next presenters. Further questions on page number 5?

Senator Kiel. Thank you, Mr. Chairman. I guess just to make sure I'm clear about the, I guess, third bullet on the right-hand column, It's where it says IGU is exempt from economic regulation because it's owned by the North Slope Borough. Utilities owned by the public sector, their exemption from regulation isn't limited to their municipal area? I'm just thinking it— I live in Juneau, makes sense that the voters are the regulator of the the city water utility, right?

They got some pretty strong accountability standards. But if Juneau were to go provide PFAS-free drinking water over in Gustavus, we could just wring it out of them for whatever they'd pay? Is that how that works? Senator Keel, through the chair, Commissioner Johnston.

Let me give you an example. The municipality of Anchorage had municipal light and power. And because it was an electric utility that only provided electric service within the municipality, they could potentially have been exempt. However, they also had a water utility that provided water And at the time, the commission looked at the sum total of the utilities that were within the municipality and determined that they would in fact be subject to the Regulatory Commission of Alaska. Now, as to your example of Juneau, if the water utility for the city of Juneau went and began providing service to those outside of the city or borough of Juneau, then it is possible that the commission could determine that they were not exempt under our statutes.

Senator Keele. Can you just, again, in broad terms, explain that, how the commission Commission could determine that? Because I'm seeing this reference to a law that says it is exempt. What would be the factors considered?

Senator Keele, through the Chair, Commissioner Johnston for the record. I think that typically the exemption is if you have a utility that operates solely within the boundaries of the municipality or city, then in that instance, the city can choose to not be regulated. If they go to provide those services outside of the, the configuration of the city or the borough or municipality, Then that is when they potentially become subject to RCA regulation because they are— it is not just operating within the city, and as you mentioned, the citizens of the city represent or elect the elected body to oversee the city. It is then providing services outside of the city that are to individuals that are not subject to that city municipal government. Senator Keel.

Mr. Chairman, I got passed a note. There may be a typo that has me barking up the wrong tree. Is IGU owned by North Slope Borough or by Fairbanks North Star Borough?

I believe— sorry, Senator Keel, through the chair, Commissioner Johnson, for the record, it is owned by the Fairbanks North Star Borough. Sorry. No worries, Mr. Chairman. Thank you. I appreciate it.

Thank you, Senator Keel. Further questions on slide deck number 5? We'll move on to slide deck number 6. Thank you. And for the record, this is Claire Kunitsunlata.

Excuse for the typo on the previous slide. I also want to note that it should have been AS4205711B, as in boy, not D, as in— Slide 6. Both Senate Bill 2001 and House Bill 381 include provisions that address furlough cost recovery. Proposed statutory revisions with SB 2001 require that for a project to be eligible for tax abatement under AS 4359-010, it must include a spur line to the City of Fairbanks and Fairbanks North Star Borough. And the cost of that spur line must be allocated in a just, reasonable, and not unduly discriminatory manner across all—.

Kus—. All consumers statewide. The legislation additionally requires that costs related to financing or construction of the spur line not be allocated solely to the Interior. Senate Bill 2001 provides guidelines for a tariff filed for the spur line, including an explicit bar on allocating costs for financing, constructing, operating, and maintaining the spur line only to the Interior region. The legislation defines economically viable sales contract, gas pipeline, spur line, and system-wide.

In addition to provisions on cost recovery and tariffs, SB 2001 repeals the exemption from regulation for liquid— liquefied natural gas, or LNG facilities, at AS 4205711B. Any questions, please? No. No questions. Slide number 7.

Slide number 7. Unique to HB 381 is language added to AS 4205 that provides explicit pricing guidelines for gas supply contracts between between utilities and the owner or operator of a gas pipeline advanced, operated, or owned in whole or in part by AGDC. If passed, the price of gas sold in a contract approved by the Commission could not exceed $16 per million British thermal units, or MMBTUs, with annual adjustments for inflation. Additionally, the Commission would be barred from approving any gas supply contracts that required utility customers to assume cost overruns from construction of an Alaska LNG project or included provisions that would increase commission-approved rates if pipeline throughput decreased. Like SB 2001, proposed statutory revisions with HB 381 require that for a project to be eligible for tax abatement under AS 43, 59-010, it must include a spur line to the City of Fairbanks and Fairbanks North Star Borough, and the cost of the spur line must be allocated in a just, reasonable, and not unduly discriminatory manner across all consumers system-wide.

HB 381 further requires this to include export customers and customers in the area from the North Slope through South Central Like SB 2001, HB 381 requires that costs related to financing or construction of the spur line not be allocated solely to the Interior. Finally, HB 381 requires the owner of the gas pipeline responsible for construction of the spur line to file a system-wide tariff treatment for the spur line with an economically viable sales contract before the commission Commission. The legislation defines economically viable sales contract, gas pipeline, spur line, and system-wide. Under HB 381, AS 4205.711(b), 4205.711(b), the exemption from regulation for LNG facilities is left intact. Any questions?

Senator Stetten, can we do this? Can we have the Guys in Japan pay for our pipe?

Senator Steadman, through the chair, this is Commissioner Johnston.

I would say that the legislature can put anything in legislation that they choose to. Whether or not the people in Japan would be interested in paying for the spur line is another question.

You got your answer. Thank you, Mr. Chairman. But with that, if the people of Fairbanks and the legislature think that's going to happen and it doesn't happen, then where do we go with providing gas to Fairbanks?

This Senator Hoffman. This is Mark Johnson for the record. That is a very good question. If there is— if there was a challenge to a tariff, then it would have to be determined how the cost of that spur line was allocated. And I believe on the next slide, Ms. Knutson-Latta is going to talk about recovery and the cost-causer/cost-payer principle.

So, I think that may provide some additional information for the committee.

Senator Crockton. Thank you. Thank you, Mr. Chairman. Thank you, Mr. Chair.

I'm just going to ask the pointed question. Does the RCA view system-wide tariff treatment as a reasonable mechanism to spread the cost of the Fairbanks spur line across the broader project and avoid the undue burden on interior taxpayers?

Sorry. Senator Cronk, through the Chair, Commissioner Johnston, without seeing the specific specifics of any spur line, who will build it, you know, who will own it, how it will be controlled. The RCA has a difficult time in saying whether or not that's reasonable. What I will discuss is a similar situation, although not the same, that InStar faced in 2003. Okay.

Enstar had service to the city of Kenai and the city of Homer, and businesses and residents wanted to have access to gas as well. What it required were a producer to build a pipeline to Anchor Point, and then Enstar to build a pipeline from Anchor Point to Homer to be able to provide the service. In that instance, Enstar suggested that the pipeline that they built from Anchor Point to Homer should be paid for by the city citizens of Homer who received the benefit from that pipeline and the gas that came to Homer. In that particular instance, the commission reviewed the filings that were made by Enstar and decided that a surcharge that was proposed by Enstar was appropriate for the citizens of Homer, both businesses and residential, to pay until the cost of that spur line from Anchor Point to Homer was paid for. I don't know if that specifically answers your question, but that's, I think, a— Yes.

Example of something that has been discussed in the past and proposed in the past. I see that Mr. Kissinger and Mr. Prestige are in the audience. They said that they could implement HB 381, so it will be interesting to hear their response to the questions that are being raised by the Commission, and they said they could implement them, so we'll be looking forward to the magic they're going to perform. Senator Kiel. Thank you, Mr. Chairman.

Commissioner, I think I said the last time we talked, I don't do gas. I got electric here in my district. But a lot of electric utilities have postage stamp rates and they cover the infrastructure.— when my local utility has to completely rebuild a substation out at the end of the road, you know, 28, 30 miles from where I live, it's in my rate just like everybody else's. So is the precedent you mentioned something that you think of as binding, or is the availability of things like a postage stamp rate, and especially in combination with the way Section 25 of the bill is written. Do those give the Commission guidance on the legislature's intent?

Senator Keele through the Chair, Commissioner Johnston. I think the example that you used that if someone outside or within your district but they wanted an extension of 3 miles or 30 miles typically the electric utility will have a line extension policy, and that line extension policy segregates a portion of the cost associated with that line extension to the person being served. Now, the electricity that they receive will be on a postage stamp rate, but the cost of extending the line to that particular individual will be in some part paid for by the person requesting the service. So I don't know if that answers your question, and if not, please tell me what else it is that you would like me to try and address. Senator Keele.

Thank you. I think that, that gets to the first half. The second then would be In terms of the language that's proposed in Section 25 of the bill, you see that in that middle bullet on the slide here.

But I guess it's not in Title 42. Do you read that as guidance to the RCA from the legislature, or would that need to be made more explicit somewhere? Senator Keele, through the Chair, Commissioner Johnston for the record. I believe that the particular provision that we have been discussing are related to the property tax abatement for the project. And that, I think, is something that the committee needs to take a look at.

While it's not explicit direction to the commission in 4205, 42-06 or 42-08. It is something that we would consider as to the legislative intent. But not having a filing in front of us, I can't tell you sitting here today how we would incorporate that into any decision specific to the allocation of costs related to the spur line. I appreciate that, Mr. Mr. Chairman, I was not trying to trap the commissioner. Thank you.

On Section 19, AS42.05.438 requires the commission not approve contracts that require a utility— utilities customer to assume cost overruns from construction of Alaska LNG project.

I would expect, highly expect that there are going to be cost overruns. What happens to the Fairbanks spur line given the language in Section 19 that I referred to?

Chairman, Again, for the record, Commissioner Johnston, I think that the cost overruns are a component that perhaps Glyn Farn and AGDC will address in their presentation because those are, as we heard from Mr. Sims of Instar in his presentation to the committee last week, that those are built into those agreements. We at the Commission have not seen any of those agreements, so we can't really comment on how that would be incorporated into any Commission decision. As to the spur line, if there are similar— is there similar language that is put in whoever builds that line, if there is similar language that is incorporated, then, and then it was presented to us, we would take that into account. But having not even seen a proposal for the construction of or the ownership or operation of that line, I think that it's difficult to determine how any cost overruns might be handled related to the spur line. At this point, we have seen estimates of cost But it's difficult to, I guess, try and analyze something that we don't have the information in front of us.

Further questions on the impact of the Commission-related provisions in HB 381? I don't know if it cleared things up or made things worse. Make things more complicated.

Slide number 8. For the record, this is Claire Kunitsun Lada. At a very basic level, spreading the cost of the spur line across the entire system acts to decrease the rates related to the spur as costs are spread over a greater area. However, in utility and pipeline regulation, there is a well-founded principle which appears at 3 AAC 48510 that the causer of the cost and consequently recipient of the cost benefit should also be the one to pay the cost. System-wide recovery would be contrary to this principle as not all users of the system are causing the cost or receiving the benefits of the SPUR.

Additionally, statute requires costs to customers to be be just and reasonable, a concept in line with the cost-causer/cost-payer principle.

Any questions? Any questions? Senator Steadman. So help me with that 4206.730 that requires the common carrier pipeline rates to be just and reasonable. What if it's not a common carrier?

Contract carrier? Senator Steadman, through the chair, this is Claire Knudsen Latta. If it's a contract carrier, it is addressed under the subsequent bullet point, the 4608 requirement that— the 4608 requirement.

Senator Sedman. Sorry, 4208, my apologies. Well, the main line looks like it's gonna be a contract carrier. Can you branch off and have a spur line that is then a common carrier from a contract carrier line? Can you even do that?

Senator Sedman, through the Chair, Commissioner Johnston, you can, yes. And since Typically, I mean, what we know sitting here today, it is going to branch off potentially of the mainline and go to Fairbanks. And so if the service was just for the city of Fairbanks, then it could be a contract, it could be a common carrier. If the line has capacity to serve not just the the city of Fairbanks, but some other potential user, it could be done either as a contract carrier or a common carrier. The difference would be whether— or how the rates were set up.

So with the common carriers we discussed before, everybody has to pay the same rates and play by the same set of rules. With a contract carrier pipeline, each individual that utilizes the pipeline has a potential contract, and those rules can be different as long as they are just and reasonable and non-discriminatory.

Senator Steadman? Senator Kaufman? Just wanted to offer a helpful thought on piping systems. When you have a piping system, you can have what's called a system break that delineates the system boundary. And so System X over here, and then even though it's all connected, and if you're just looking at it all, it looks like the same thing, but you can have a system boundary in piping systems that defines the difference between the two.

I don't know if that's applicable here, but I know when walking, you know, systems down against the drawings and looking at them, you're often looking at the system breaks for what you should be seeing in each system. Thank you, Senator Kaufman. Further questions on slide deck number 8?

Any further questions of the Regulatory Commission of Alaska regarding the Fairbanks Spur Line? With that, we'll take a brief at ease while we switch presenters.

Going out of order, I think that may have caused— we're back in order. May have caused some more questions. Maybe we can get those answered. We have before us regarding the Fairbanks Spur Line, a presentation from the Alaska Gas Line Development Corporation and Glenfarm. I invite Matt Kissinger and Adam Partridge to the table to identify them— themselves and give us the answers we've been looking for.

Thank you, Chairman Hoffman. This is Adam Prestidge from Glenfarn, Alaska LNG. This is Matt Kissinger, Commercial Director of AGDC, via a contract through HAWC.

Very good. Mr. Co-chair, thank you for the opportunity to return to the committee today and provide some answers and some important points about the content of HB 381 regarding the Fairbanks Spur Line, and also some of the important points about Glenfarn's role on the Alaska LNG project and our relationship with AGDC. So I will be covering a few of those things as well as a couple of other topics in this presentation.

Before I get into the content of the Fairbanks Spur Line, what I do want to provide is a little bit of a context for how we arrived with it. Again, I have talked about in this Committee a number of times the significance of the Municipal Working Group that preceded this drafting of the governor's bill and any other version of this bill. There were a lot of conversations with the— with each of the mayors, including Mayor Hopkins for the— of Fairbanks, about the needs of the communities, the needs of the municipalities, each of the unique attributes that led into how we could accommodate and provide a project that served the communities in the best way possible. One of the ways that we determined through this working group to— that the project can be the best for Alaskan communities is to include the Fairbanks Spur Line. So that's really the genesis of having this included here.

It wasn't only Mayor Hopkins, it was also a very collaborative effort, I would say, with the entire Interior delegation. So many, many rounds of meetings with— some of them attended by the entire Interior delegation to discuss how to put this together. First and foremost, what this bill does— what this provision of the bill does is it makes a commitment that there will be a Fairbanks Spur Line. There are questions. I think it's pretty clear there are questions of regulatory jurisdiction and regulatory process.

Some of those questions will persist. They are not all going to be answered here by this bill, and I can't answer them all today. Because part of what we have here are commitments to undertake the spur line, recognizing that undertaking a project development is an effort that takes time and takes— and takes time and effort to come together. What we do— what we do have the benefit of is a significant head start. So we are not the first party to take a look at the Fairbanks Spur Line or study it or have a desire to build it.

And so if— With your permission, Chairman Hofmann, I would like to ask Matt Kissinger to speak just for a moment or two about the historical work that AGDC and others have done into studying and evaluating and estimating the cost of the Fairbanks Spur Line. This is Matt Kissinger for the record. When AGDC was formed, of course, there were sort of two phases in the enabling statutes. And the first was really focused on an in-state gas line, and that was called the ASAP effort, the Alaska Standalone Pipeline. And this is being ahead of my time, but be— as the ASAP engineering was progressed, the Fairbanks Spur was included as part of that.

And so there was a cost estimate built up as part of the ASAP efforts. When the Alaska LNG project came around, The pipeline became just an integral part of the LNG facility, same with the gas treatment plant. And so the Fairbanks spur was never permitted as part of the FERC authorizations. It always stood to the side. We had the cost estimate.

Everyone always knew it had to be built, but it was just never part of the regulatory environment of the Alaska LNG project. More recently, in discussions with certain in-state utilities, we've talked about ways to reduce the cost of that line. So when it was designed as part of the ASAP line, it was to follow its own right-of-way coming off of the mainline pipeline into Gold Stream Valley, if you're aware of the Fairbanks area, and then down by the university and into the system. More recently, If we were to include a utility partner, then we would be able to access a utility easement, a utility right-of-way that parallels, I believe, that's Murphy Dome Road through that same area and could result in considerable cost reductions. We did do a cost estimate update on that, basically just a CPI adjustment to the old— what would be now considered quite old— cost estimate.

Thank you. Estimate, but what we don't have is a new built-up cost estimate of the reduced cost in utilizing that utility corridor.

Continuing, this is Adam Preswells for the record. Before you proceed, is that utility corridor— who owns that corridor? It is a utility easement, so I am not sure. I believe it is the Department of Transportation owns it, but I'll have to double-check on that and get back to you, Chair Hoffman. And can you check on why there's a corridor there?

What was the intended purpose? I will check with that too. I believe it's power lines. Senator Keele. Thank you, Mr. Chairman.

Just a brief baseline diameter of pipe, maximum volume it could handle. Senator Keele, through the Chair, I don't have those numbers on me at hand, so I'll have to deliver those to you. But we can do that this afternoon. Please proceed.

Senator Kyl, through the Chair, when we talk about the Fairbanks Spur Line, we are— and again, we will give the specific final numbers, but just for frame of reference for this conversation, approximately 30 miles with a diameter of 12 to 14 inches in diameter. So significantly smaller in every respect when it comes to the the scale of the overall project.

The Fairbanks Spur Line is incorporated into this bill as a condition of eligibility for the overall project to be eligible for the tax reductions set forth in the bill. And the way it is set out is that there is a commitment by the developer to undertake the conditions and the commitment and the requirements related to the Fairbanks Spur Line. With that commitment, the Department of Revenue Commissioner would make a determination that the eligibility has been met based on the project developer's commitment to undertake. And that's— so that's how it's set up. What those commitments include is a number of things.

One is that the project, the Fairbanks Spur Line, needs to be incorporated into the overall project plan for the Alaska LNG Project. And so you think about how that gets incorporated into the overall cost, the overall engineering plan, the construction execution plan. Essentially, the Fairbanks Spur Line becomes part of the technical plan of the overall project. I will note, however, that it is not an integrated part of the project. The Fairbanks Spur Line remains as a separate infrastructure project.

And so what that means is that Ultimately, it is an eligibility matter for the Alaska LNG Project to make sure that these commitments and these conditions are satisfied. But if it is Glenfarn that builds the Fairbanks Spur Line, or if it is an Alaska Native corporation, or one of the utilities, or a joint venture that includes all of those parties or some of those parties, it doesn't have an impact on the eligibility of the Alaska LNG Project. So long as these conditions are satisfied. And so again, we would be happy to be very involved in that. We've spent a lot of— had a lot of— have had many conversations with other parties that might be equally interested in building and developing this project.

And so that does not matter for eligibility under HB 381. The commitments and the conditions, one, are that we would seek to obtain— we would use good faith to obtain all necessary permits and all regulatory requirements for the construction of the spur line. This is a point that we spent quite a bit of time on because it is not a firm commitment that all of the permits must be obtained because that is outside of the scope of the project developer's control. That is outside of 8 Star's control. At the end of the day, if there is a regulatory agency that for some reason declined to issue permits for the Fairbanks Spur Line, we wouldn't want that to jeopardize the tax treatment for the overall project that benefits the entire state of Alaska.

So that was a condition that was carefully worked on with the Interior delegation, recognizing nobody wants to put the entire project at risk over this— [FOREIGN LANGUAGE] to the spur line. The second is that the developer would initiate a tariff proceeding with the Regulatory Commission of Alaska and file for, as has been discussed, a system-wide tariff treatment that would allow the cost of the Fairbanks spur line to be spread across to other customers. And just taking a step back, kind of the concept there is that the cost of the Fairbanks Spur Line would be spread across other gas buyers from the domestic pipeline. There is a technical amendment that we think would be the right thing to make in this bill, which would be to remove the portion of the language that says that the cost would be spread to export consumers also. I take note that in the prior presentation, the regulatory commission explained the concept that the causers of the cost should bear the cost.

Extending it to all of the ratepayers across Alaska stretches that concept a little bit. Extending it to global LNG buyers extends it far outside of the bounds of commercial sensibility. And so we recommend removing that. I think it also opens up a number of questions of jurisdiction over the LNG project and LNG sales and— [FOREIGN LANGUAGE] becomes quite complicated. So we recommend removing that as one of the technical cleanups to the bill.

At the same time, the question might come, why would we want— why would other ratepayers in Alaska be willing to accept this additional cost? And the reality is, having Fairbanks have access to gas and being a buyer and consumer of gas off the pipeline is good for everyone. And we've talked in this here, in this committee, about the ramp down in pricing as more gas flows on the pipeline. One, it produces more tax revenue, and two, it gets to those thresholds, 500 million cubic feet a day, faster to result in that price decrease. And so bringing on the Fairbanks market, the gas consumption has multiple benefits in that respect.

Lastly, is the—— or the requirement that if the conditions above, receiving all permits and having an RCA-approved system-wide tariff, are satisfied, then the project owner, the developer, would begin construction on the spur line within 1 year after receiving all of those permits. So those are— those are the primary requirements, and then the target timing would be that the Fairbanks Spur Line would be in service, in operations within 2 years after the operational start date of the pipeline, of the main pipeline. So if, I'll pause there, because that's the main outline for how the Fairbanks Spur Line is set up. When you talk about spreading the cost among users, is that current users in Alaska, or potentially other users that may come online in the future? Chair Hoffman, the way we envision this now is that it would be the users, the buyers who are regulated by the RCA, who buy gas off of the Alaska LNG mainline pipeline.

—Currency. Well, it's a future event because it would be all those customers, NSTAR, others who sign up to buy gas off of the mainline.

Questions on this slide? Senator Kehoe. So thank you, Mr. Chairman. Mr. Prestidge, I guess, is the vision here that We're gonna have a fourth LLC on this thing? Are you gonna sell it to somebody?

Are you gonna give it to somebody? Once it's built, what's the plan? Senator Kyl, through the chair, it's a good question. I don't anticipate selling it, but it could be. I think it most likely would be a separate LLC.

It will be a separate project entity. It will have its own permits. And authorizations, and so that will most likely be housed in a separate LLC. And that LLC could have different ownership from 8STAR specifically. As I mentioned, there could be ANCs or other utilities that have an interest in partnering or even taking on the project itself.

Senator Kiel. Thank you. So the— to tease out from on that, it sounds like we don't envision the same concept of the, for instance, AGDC starting out with 25% equity in it. Maybe that's a question for Mr. Kissinger. Senator Kiel, through the Chair, no, we have not carved out a position in the spur line.

Okay. Thank you. Further questions on slide number 2? Chair Hoffman, if I may. Please.

Senator Kehoe, to be totally blunt, we're not looking at the Fairbanks Spur Line as the profit generator, as a major profit generator. It is a small additional component to the overall Alaska LNG project. We want to make sure it happens with the right partners, and that's going to be our priority is how do we, what's the best way to make it happen. So you said you did, a cost adjustment to the last construction cost using inflation. Do you have that number?

Chair Hoffman, if I may ask AGDC President Richards to join us. I believe that he has actually better information on that to provide. Mr. Richards.

Good afternoon, Mr. Chairman. For the record, Frank Richards, President of the Alaska Gas Line Development Corporation. As Matt described earlier, the work that we did as AGDC under the direction of the legislature under House Bill 4 was to include a spur line into Fairbanks as required in our enabling statutes. That cost estimate was conducted after completing FEED for the project back in 2015. And what we've done most recently is look at updating that cost, again, essentially taking into account the cost of inflation.

So what Mr. Kissinger provided was, again, an inflation-adjusted cost estimate. As Matt described, the opportunities to optimize this project Or the spur line would be to look at the utilization of the existing right-of-way that the Department of Transportation owns on Murphy Dome. By that, what I mean is that if a smaller diameter pipeline was built in the DOT right-of-way as a utility, then you would have likely a very easy right-of-way acquisition at significantly less cost. And it would be able to come in at the diameter that the Fairbanks and the Fairbanks North Star Borough demands will be. When we originally designed this project, we were looking out at the time to the future expansion and growth of Fairbanks.

So I believe we were looking at almost 80 million standard cubic feet a day to transit through that 12-inch diameter line. Now we see that the actual needs within Fairbanks are significantly less. [FOREIGN LANGUAGE] But when you add on the opportunities with the military bases and with the mines, then you're still going to have some growth. As Adam described, that growth then is a benefit to all Alaskan consumers, as— because as we see the rates in— or the volumes increases, then the benefits to Alaskans are lower-cost energy. So I think that the long story short is there's optimization.

That can look at this project, meaning the Fairbanks Spur, for a smaller diameter to meet the needs of Fairbanks, and it will be significantly less than what we have projected it to be. Thank you, Mr. Richards.

Senator Steadman. What is it? Through the chair, Senator Steadman, we do not, and we have not done a cost estimate on this optimized line. However, We, as AGDC, in conjunction with our statutes, we have looked to work with interested partners to be able to do that. And they've now taken on the work that we provided to them, meaning the design concepts and the right-of-way, as well as the initial permitting, environmental permitting processes that we had gone through.

They've looked to optimize that, and they have developed a cost estimate. I'm told, but I've never seen it, it's less than $150 million. Understood. No, I think that's helpful because we've heard numbers from $150 to $200 and then $240, so we should be thinking in the range of the $150 range. Through the chair, Senator Steadman again, and I believe that that includes not only not only the initial 38 miles, but also extensions out now out to North Pole and potentially out and beyond into Eielson.

Senator Kaufman. Thank you. A little bit of a coming from a different angle. All this talk of easements and just considering the corridors that are to be for this line. Is there any secondary purpose with data transmission?

Is there— has there been any conversation about it being a data transmission corridor?

Through the chair, Senator Kaufman, are you speaking specifically to the Fairbanks corridor or are you talking about the entire mainline? The entire mainline. And then since, again, you know, over to Fairbanks, I just— I don't know how that may play into a very large data transmission play. Senator Kaufman, through the Chair, that is certainly something we have looked at, is the feasibility of incorporating data transmission within the same easement. I would say it is part of ongoing studies right now.

Okay. Senator Kaufman. And just to clarify, I don't mean for purposes of the telemetry on the line itself and sensing, acoustic sensing, all that sort of, I mean, like separate for purely for data transmission purposes. Understood, Senator Kaufman. Further questions on slide number 2?

Seeing none, we'll go to the next slide. This next slide is a bit of a recap. Again, the Fairbanks Spur Line is something that we, 8STAR, Glen Farr, and AGDC are very supportive of. We've worked hard with the Interior delegation, with Mayor Hopkins and others in Fairbanks to come out with something that we are confident would resolve result in a high— in the highest probability of successfully building and putting the Fairbanks Spur Line into service without putting the entire project at risk over this condition. And so it is something that we stand behind as the developer and the commitments here to undertake it in good faith, to pursue the permits, the regulatory filings, and ultimately to to initiate and complete construction of the Spur Line.

Further questions? Senator Cronk. Thank you, Mr. Chair. From my perspective, the Fairbanks Spur Line is definitely not an optional side project.

It is a key part of this entire project.

Just looking at the— obviously South Central has been blessed with gas for since the whatever '60s, right? So they've built their infrastructure out, you know, and Fairbanks is trying to figure out a way to lower their energy costs. So they have IGU on board, they truck gas down. So you have customers, you know, about 3,500 customers, I believe, right now. So when we talk about cost, spreading the cost out, so right now if we just built the mainline, got it right down to South Central, tied into the existing line, What is the cost for those people besides just buying the gas?

Is there an added cost into their bill?

Senator Koffman— excuse me, Senator Cronk, through the chair. That additional cost, if the RCA were to approve a tariff that spread the cost across all of the users, would be a a very low additional cost to Fairbanks consumers on top of what would be the $16 tariff. I can't speak to what the utility transmission and distribution costs would be once the gas left the Fairbanks spur line, but when we're talking about the incremental cost that would be spread across customers, you're looking at, you know, something— 10 cents. I can't pin down an exact number, but in the range of 20 to 30 cents per MMBtu of gas would be the amount that would be spread across all buyers. Senator Cronk.

Mr. Chair, so I guess I'll rephrase my question. So if there was no spur line, there was no cost spreading, would the people that are benefiting from this main line, South Central, have any other cost adjustments or they just get to go into contracts of buying gas from you. I guess my point is we're gonna build a $16 billion, $19 billion gas line that they get to take advantage of the gas, yet Fairbanks is sitting up here 30 miles away and all we're asking for is, hey, can we get these costs covered so we can get that spur line built? So the 90,000 people that live in, per se, I'm not saying all of those would be tied in, would have access to that gas.

This is Matt Kissinger for the record. Senator Cronk, through the chair, there are the equivalent of spur lines. There are transmission lines in south central Alaska. So it's— the mainline pipeline doesn't go any closer to Anchorage than it does to Fairbanks in reality. It's on the other side of the Susitna River and it ends there.

Eventually goes over underneath Cook Inlet for phase 2.. But it will tie into existing spur line or transmission line infrastructure. The difference is that that's all been paid for. That's all very old infrastructure. You know, this is a new piece of infrastructure.

But it is, if you look at it on face value, it is very similar.

Mr. Chair. Senator Cronk. I appreciate that. I guess my point is that we're going to build a 16 $20 million or billion dollar line and bypass Fairbanks and we can't figure out a way just to— what we're doing, cost spreading to pay for it, right?

Yeah, I have. I mean, 'cause the people in South Central are going to have advantage of all that gas coming down that line. So my point is, is that we're this little chunk here that we just want this amount of money to get this spur line built so those people can access that, right? And if we have a vision for our state, it's even bigger, right? Harvest came down with their plant at Fairbanks, could we possibly spread that out on a barge down the Yukon River?

Could we possibly truck that down the road? So I'm just saying there's a bigger vision. I know there's not money to make that happen overnight, but we have to have a vision for our state, and this line does that, and the Fairbanks Spur Line is key to doing this. So I have supported what you guys are saying, but what I'm saying is you have to spread this cost out. You can't put the burden on 3,500 customers to build 100 $150 million gas line.

So this is a statewide project that benefits the entire state. So we should all have to have a little bit of, you know, a bite into that to make sure it happens. That's my point. Senator Cronk through the chair. That's exactly right.

The difference is that by building the spur line now, you don't have the customers in Fairbanks, but you know that they're there and you need to provide that avenue for growth. That benefits all the ratepayers, even in south central Alaska, which wasn't the case when they built those spur lines, obviously. Thank you, Governor Cronk— I mean, Senator Cronk. Brief eddies. Brief eddies.

Come back to order. Um, point What is the expected surcharge of all utility customers to pay for the spur line per MCF and per year? [FOREIGN LANGUAGE] Chair Hoffman, as I stated earlier, it would be somewhere in the range, and this is still subject to finalization and feasibility studies, but our current prediction is that it would be in the range $0.20 to $0.30 per MMCF of gas. And on an annual basis, I would need to revert with that annualized number for consumers. And that would be increased if there were cost overruns?

Senator— Chair Hoffman, the language around cost overruns, it has not been applied applied to the Fairbanks Spur line. It hasn't been a request. Quite frankly, it would be a very, very early stage in the process to do that. The project hasn't been— hasn't applied for permits or had a FEED study conducted on it. So I couldn't say that that could be considered responsible development.

Senator Keel. Well, thank you, Mr. Chairman. It's a great conversation. It's just always of interest to me. Senator Kaufman talked about making sure we pick our head up out of our silos.

So, you know, 20, 30 cents is a portion of the roughly 80 cents off on production tax that anybody who burns cooking gas in-state gets, right? It's capped at less than 18 cents in MCF. Instead of 13 cents— or excuse me, 13% of the gross. So in terms of— Thank you. What we do to benefit the state's economy, what we do to benefit Alaskans, what we do to benefit our military bases that may get access to affordable energy.

It's good to keep our heads up high enough that we can see the whole picture instead of focusing too much on one particular sliver.

Do members of the Senate Finance Committee have additional questions on slide number 3? Senator Steadman. Maybe just— it would be helpful if somebody could just run some annual numbers. If it costs $150 or $250, you know, just kind of the impact per resident or per household or whatever, customer bill that you send out or something, so we have an idea what it actually— we are looking at. Is it $20 for everybody that is going to get gas off the system or $10 or $5 a month, I have no idea.

But that's about the range of debt that Sitka has on their dam. So I think they're over $100 and some million for 8,500 people. And there's probably— I don't know how many utility hookups there are that spread that out, but it sounds like a fairly similar size. So— [SPEAKING NATIVE LANGUAGE] It's probably doable at the Fairbanks level, but it's probably not as much fun as having some assistance.

Senator Steadman, through the chair, those would be numbers we could put together very quickly. Yeah. Be happy to do so. Thank you, Senator Steadman. Final call for questions on slide 3.

Move on to slide 4. Thank you, Chair Hoffman. I'll continue and I'll talk about the financing of the Phase 1 pipeline, the pipeline-only phase of the project, with specific reference to Department of Energy federal loan or through the more traditional private financing through infrastructure lending banks. Before I get into the details, there's a few things that I I would like to say. First, it's been very publicly acknowledged by numerous members of the Trump administration, including Secretary Chris Wright of the Department of Energy, how much the Alaska LNG Project is a priority to the administration and is a high priority to the Department of Energy.

They want to see it go forward. And I can tell you that from our personal experience, working with them, we think that's true. It is a priority. [SPEAKING GERMAN] I will also say upfront that I am bound pretty carefully by confidentiality between myself, Glenfarn, and the Department of Energy given our discussions. And so there may be questions where I have to default to respecting that confidentiality commitment that I have to the federal government.

And then lastly, I will say we've spent a lot of time on this. We've spent a lot of time with the Department of Energy's Energy Dominance Finance Office. It was a— it has been and continues to be a very good relationship. I've— Senator Maric brought up a concern, a rumor about a lack of information. And what I would say is we have had a nearly year-long working relationship with the Energy Dominance Financing Office, an extraordinary flow of information at a very detailed level, data rooms full of information, and literally every bit of information regarding the project-level asset, the Phase 1 pipeline that could be provided was, and So that's our, you know— Beyond that, I'm not aware of issues.

With that said, I will talk about some of the comparisons and, as I mentioned, our focus and our prioritization on pursuing private financing versus making the primary plan to obtain a DOE loan. One thing I'll recognize is that we're not saying that this is the path forward for the entire project. The LNG facility, the pipeline, the gas treatment facility are going to be independently financed and have different financing sources. And so regardless of whether the Department of Energy participates in funding the Phase 1 pipeline, it does not mean that they will or will not be involved in the LNG project or the gas treatment facility. So those are separate conversations.

Those options remain open no matter what. What we did experience and what we— some of the considerations that we took on as the developer with our goal to deliver gas as quickly as possible to Alaskans, address the energy crisis, and to do so at a price that's as low as possible to actually allow the project to be economically viable. We took these factors into consideration. One is that the federal loan— the federal loan program has a meaningfully longer timeline to go from start to funding, basically. And so when we talk about the urgency to get this project in operation to deliver gas to South Central and to the interior, and and to go through construction, working through the process of the Energy Dominance Finance Loan Program would add significant time to the pre-FID timeline for the project.

There is also a different kind of— if you can imagine a federal agency level approval process, of working through the approvals necessary to fund this. And so it's not just working with the DOE, but the DOE needs to take its authorization to other agencies within the government, the Office of Management and Budget, for example. And that all contributes to the longer timeline that goes— that is required. Contrast that with banks that do these transactions, you know, on a day-to-day basis. They are, you know, they have a more streamlined approval process.

They have funds that are allocated and ready to be deployed for projects like these. And when we look at our objectives to deliver this project quickly, we definitely see that as an advantage to going through private financing. At the same time, we have spent a lot of time talking, and part of the reason that we are here is that this is a challenging project that requires the most— that requires somewhat complicated structuring in order to deliver the project and make it all work. We've— the federal loan process is obviously constrained by rules and regulations and policies that limit, if you will, the creativity and the structuring options that can be applied to project finance like this. However, working with private finance, finance banks is more of a commercial negotiation.

Parties can sit down, figure out what works, and pursue that structure without the restrictions of federal policies around structuring. I mentioned earlier that on a cost comparison basis— [LAUGHTER] —ultimately the difference in cost of capital and the difference in cost to the project is not that significant when you take all things considered together. And so when you look at the Department of Energy interest rates and then the additional fees and premiums, risk premiums that are attached to them, as well as the operational costs that would be the result of having federal funding, our takeaway from from this comparison was that they were very close in terms of cost and that the cost itself was not the determinant factor in choosing which avenue to fund the project with. Then lastly, one of the things again, when we look for certainty of the project, and this is somewhere where the State of Alaska and Glenfarnon and AGDC are all very aligned, we want the certainty that this project will go forward and that things won't change. And so the reality is that the Department of Energy and the Energy Dominance Finance Office is an institution of the federal government.

The administration changes on a 4 or 8-year basis, and when that happens, personnel change, policies change, and even in the last— the change in administration, some of the projects that were funded that were funded under the prior administration are no longer funded under this administration, and so you— there is a bit of a risk in terms of a change of administration, and nobody wants to see that, and I'd consider it an outside risk, and I'd reiterate our gratitude for the support from the federal government that continues to be very strong. However, that is a theoretical risk that needs to be considered. Compare that to working with private financing where you're spreading that risk across 20, 25 different banks, you basically diversify that risk itself. So those are some of the main considerations that we as the developer have taken into account as we consider the right way to finance this project. Questions on slide number 4?

Senator Steadman. I have got several.

I recognize this is a tough project financially, and it's a project of national interest and, frankly, international trade balances and go on and on, why the federal government has come around over a decade ago with loan guarantees and packages and tried to help push this project forward. And even till today, they are standing by. And they are— so it is a concern that when we are asked to give a concession to help a financially challenged project, which this is, I think we all recognize that, so we are looking at— [FOREIGN LANGUAGE] changing our property tax structure to assist the cash flow. Then we look at the federal loan guarantee and having a guarantee against default and a few things is pretty comforting for somebody that's going to put billions of dollars on the table for a project that's challenged. And then with the interest rate spread, whatever that is, 50 basis points or 75 basis points or 100 basis points or whatever it is, it's a significant dollar amount.

And it, you know, and I recognize there might be some advantages in the right-hand column. It's not all one side. But, you know, if— You know, we could be looking at, if it's an $18 billion project, 80/20 debt to equity, we could be looking at $80 million a year in additional debt service and $3.3 billion in added costs over the length of the project. That's $3.3 billion, and if you lower that rate a little bit, maybe you're down to, you know, $2.5 billion. That's significant financial impact on the project and who has to pay for it.

Mr. Mayor. So they may be cumbersome and there is always political risk, but through multiple administrations they have not pulled the loan guarantees from this project. It goes back a couple of— 3 presidents. So that is a concern.

I just want to put that on the table, Mr. Chairman, that this is— I look at it this way. That this is a significant cost increase, yet we're being asked to give up a concession to decrease the cash flow. And I've even contemplated and talked to a couple of my colleagues, and I don't think I got quite the support. I'd put a requirement that you have to go through the loan— the federal loan guarantee program for two reasons.

One, I want the lower cost, and two is I want the federal oversight and the review of the project. Thank you. Personally, that's my own personal opinion. It may slow it down a little bit and there may be strings attached. And one of those strings attached, as referenced earlier, was Davis Bacon.

I think there was a comment earlier possibly about wage scales and stuff. And I—. Mr. Chairman, See, the benefit in my district, which are island communities, when we have DOT road projects, we have, you know, capital projects, sometimes small ones, $2 million project, having livable wages in the community makes a big difference. And this project is just on steroids.

And when I think back of the— of TAPS, when they built that, and the wages being paid and the workforce, it gave opportunities for the workforce that they would have never had in their entire life if we didn't build that project. And they lived the benefits. So I've got those concerns.

Project labor agreements need to be put in here. We need to pay a man's livable wages for a day's work. I'm not interested in having this project built on right-to-work next to slave labor. Not interested in it. Yeah.

And I—. So if I could get the support to require that, forcing you guys through loan guarantee, I'll do it. I think it's in the best interest of the state.

I think everything is pretty good.

Senator Sedman, through the Chair, thank you for that. First, in response, agree with you on the importance of this, of workers and having fair wages and particularly prioritizing Alaska labor. Last week we signed a comprehensive MOU with the building trades councils in Fairbanks and Anchorage comprising over 15 different unions each for major roles to deliver both Phase 1 and Phase 2 of the project. And so we're very proud of that commitment that the project has made. HB 381 also does include a requirement to have a PLA executed with the unions along the same lines.

And so that is a priority to us as well. Certainly what you lay out in terms of comparing these two options are very significant important factors. I can tell you that the— what you see here on the slide, you know, our job as a developer is to take decisions on how we can move the project forward the best way possible, and these are things that We've spent months and months— everything that you articulated are things that we spent months thinking about and trying to come to the right decision on how to do this with the highest probability of success of delivering gas at affordable cost to Alaskans. So I take that very seriously. One thing I do want to flag, in case it was not clear, are the ongoing costs beyond just the cost of capital, but the operational costs.

And so for example, it's not just the Davis baking wage rates, which, you know, again, I don't think are that significant of an additional cost considering our commitments to pay prevailing wages under our MOU with the labor unions. But one of the additional costs that is significant is the requirement to comply with the Cargo Preference Act if we were to have federal loan— federal financing funding this. That requires a majority of the inbound imports and materials to the project to be shipped on U.S.-flagged carriers, and because of the limited availability of carriers that can actually handle the volume of what we need, that would present a very significant cost increase to the project. And so, again, it's— Multi-factors that need to be considered, and at the end of the day, a decision why we are prioritizing going through private markets, but I certainly recognize each of the the importance of each of the factors you identified. Senator Steadman.

Yeah, I, you know, well, we're not privy to the numbers of the increased cost for basically the Jones Act issue, I think, that you're referring to roughly.

So it makes it kind of hard to respond. But I know the federal government is very interested in this. When we go off to our energy meetings, it's a subject that comes comes up with the Department of Energy when their folks come in and talk to us. This including the— at the cabinet level of the President. They want the project.

They've got— Department of Energy has hundreds of billions of dollars sitting there looking to go to work, which is kind of surprising when they stand up and put out numbers like that and we got a project sitting here that could absorb tens of millions— tens of billions of it. So it's just— it's just— to me it's disappointing, you know, that we don't secure that. Sure. And I think it's expensive not to do it. Thank you, Senator Steadman, for Any further questions by Finance members on slide deck number 4?

Seeing none, we will move on to number 5.

Thank you, Chair Hoffman. With your indulgence, this next slide is just a bit of a recap and putting into writing for the record the commitments from Glenfarn on this project, again, to undertake We take the development at our own risk and expense. All of the activities of the project, the personnel, the engineers, the legal work that goes into it is being done at Glenfarm's expense and risk. There is not a reimbursement mechanism for Glenfarm if the project fails or if we abandon the project. There is no backstop.

That we can call upon. The state has not put anything at risk at this point that would have to be paid to Glenfarn. And again, as I mentioned, we actually turned down a reimbursement offer that had been presented to us by ADA when we were coming into starting the project. And so those are core principles— those are core principles of Glenfarn in undertaking this project. And again, we are doing so on the basis of our commitment to undertaking this project, our confidence that we can find ways to make it work if we work together, if we work with the legislature, if we work with our partners, if we work with utilities, we can figure out how to make this project work.

And that commitment and that developers, if if you will, that ingenuity that we have brought to the project has resulted in bringing this project further along in its development timeline than ever before in its history. And so that is something that we have accomplished in a little bit over a year of actual ownership, and I think speaks volumes to not only our emotional and financial commitment, but also our capability to actually deliver this project, and the proof is in the results and the things that we have delivered in that short period of time. And so just a bit of a reiteration of some of what we discussed earlier this morning. Questions on slide number 5? Senator Steadman.

Just for added background on the $50 million request, I think the administration had put that on the table here a year or so ago, and there was— resistance on that appropriation. And then there was discussion that those funds then could be attained through ADA. And we had those— that dialogue, and it was, I think, correctly concluded not to pursue that avenue just because of the political— [FOREIGN LANGUAGE] concern with that and we went on to where we are today. So I just, there's a little bit more in the background I thought the public should know about the $50 million request. Thank you, Senator Stegman.

Further questions on slide deck number 5?

The next slide is a short summary. There was a question in the prior session regarding Glenfarnon's ability to transfer its interest in 8 Star. What we have in our agreement is what I refer to as a traditional lockup period that restricts Glenfarnon and prevents Glenfarnon from transferring its interest. That lockup period, that transfer restriction, restriction exists for a defined period of time that runs until the earlier of either 10 years after the effective date of the contract, which was March of last year, or the later of 1 year after achieving the commercial operations date on the pipeline, or 1—. FID.

—Or achieving FID on both the LNG facility and the gas treatment facility. And so you have got the principle here is making sure that Glenfarm does not and will not transfer its interest until we have delivered meaningful accomplishment on the project, actually delivered the project past its, if you will, kind of its risk point. And so that is the concept of this lockup period. I don't know if— Yes. If you want to add anything to that, Ms. Kitzinger was on the other side of kind of working through this structure.

Questions on slide deck number 6? Senator Steadman. Just if the effective date, I missed that if you mentioned it on bullet 111 there where it says 10 years. What is the effective date? Yes, Senator Steadman, apologies for that.

Yes, for the shorthand, the effective date would be March 28, 2025. Okay. And then just so I'm clear, because we're in the process of writing this statute, right? We're working on this bill. So we need to understand some of this stuff, even though it may not be even relevant to what we're putting in the bill, we need to understand it.

So this includes— if you wanted to sell out of 8 Star as a gold and subsidiary, the 3 subsidiary units. So if you hit the 1 year after pipeline phase 1, which is our in-state gas line, after that hits commercial operation, 1 year later, you can liquidate if you so choose your position in 8 Stars of Gold and the other— Yes. Entities. Senator Sedlmayr, yes, that's correct the way this is structured. And so that's a period that would be achieved.

We would have to obviously FID the pipeline, construct the pipeline, put it into operations for a year, and at that time we would have that option. Right. And if I could— Senator Sedlmayr. And then at the same timing sequence, if it had— Final investment decision is what we're talking about. In the statute, there's some time elements.

Final investment decision on the whole enchilada achieved with both the LNG facility and the gas treatment plant so that basically the entire project would be under FID. Then you're free to market your, your, your position in any of the subentities or the— or its sort of gold, correct? Senator Steadman, that's correct. What I will say just to reiterate to the committee, Glenfarm currently owns and operates over 60 infrastructure assets. We're not in the business of selling out of them over a short period of time.

We don't have a fund or public money that requires us to exit investments, and so we intend tend to be in the projects that we own, including this, for the lifetime of the project. But I will say that these are highly standard provisions that you would have in a joint venture agreement like this, and so our joint venture agreement does include this. Senator Steadman. And if I could, let's go over the dilution of 8 Star. Because I asked the question earlier today and you wanted to think about it or get a lifeline or clarify position.

So my understanding is that AGDC has an undiluted 25% interest in 8Star. For those watching at home, that's the holding company that will hold the gas line, the liquefaction plant, and the treatment plant. Your 75% interest in 8Star, walk me through how that can— how you could sell out of that or have that voluntarily or squeezed out, diluted your position? Senator Sedlmayr, through the Chair, it's fixed just like the AGDC 25% is fixed. So that's, you know, the only way out of that would be under these, under this, as permitted under these transfer restrictions on this slide.

Okay, so there was earlier confusion, so you people or an investor would not come into H-Star Gold with an option then to invest in either the pipeline, the treatment plant, or the liquefaction plant. Let's clarify that old issue up. Senator Simpson, that's correct. That's correct. Any investors that wanted to come in to fund the construction of the projects would come in at the project level.

The ownership split at the holdco, 8-star holding company level, would remain 25-75 between AGDC and Glenfarm. And the equity issuance and the additional investors would come in at the lower asset level.

Okay. Senator Steadman. No, I think that clears it up. I think there was some confusion on the potential of you guys selling a portion of the 75% holding of 8 Star and diluting that, and then who would be our partners in the holding company if you changed to whoever sold out to part or all of your interest to somebody else? Sure, Senator Steppenwolf, I understand that concern through the chair, and that's recognizing that concern to the state.

To be able to know who its partner is. That's why this is structured the way it is. Okay. Thank you, Senator Steadman. Senator Keogh.

Thank you, Mr. Chairman. So then, a little clarity on as we move down the structure into the LLCs. I just assume— you're welcome to correct me if I'm wrong— that you will seek some level of equity carry if possible. As the dilution happens with more equity investors, you'll seek to hang on to some slice of that. Can that dilution happen differently between AGDC and Glenfarm, or are we tied at the proportion of any carry?

Senator Keogh, through the Chair, we're tied at that. So that portion doesn't change. You're right, we want to hold on to a carried interest. We can't guarantee what that will be because it will be the outcome of a lot of things and a lot of negotiations with financing sources. But we want to maintain as much of that as we possibly can.

And the split of that will remain 75-25% to the state. Senator Keele. Thank you. Helpful to know. Thank you, Senator Kiel.

Further questions of Senate Finance members on slide deck number 6?

Slide deck number 7. Slide 7 is my last slide to present today and again it's a follow-up from some of the earlier discussion this this morning about what are Glenfarnon's obligations. I've talked about how we are willing to undertake this at our own risk and expense. What does that mean? What are we undertaking?

What are we committed to do? At all times, we are— that we are a partner in this project. We're committed to use diligent development efforts to progress the project to FID and to execution and completion. What that means at a at a very basic level is we are obligated to not sit and do nothing. And so if we were to stop working on the project, we would be in violation of our agreement to use these efforts.

They are efforts-based, and so just to reiterate what is here on the screen, we are obligated to maintain active and prudent development, which is continuing to pursue project Objectives under industry standards. Again, it should go— well, it doesn't go without saying, but I will say it because it's very important. Our highest priority is to deliver this project safely, and so applying safety standards and prudent industry standards at all times is critical to us. Committing the investment of capital, time, personnel, and effort to advance towards FID, continuing to progress Commercial and technical progress, the execution of agreements, the engineering studies. As I've mentioned earlier, we conducted the front-end engineering and design study that was completed in December at our own cost, conducted by Worley Engineering Firm, that resulted in a— I'd say a highly reliable Class 2 cost estimate on the project.

Governance and compliance. We're committed to adhering to all of our contractual obligations. And then very importantly, I'd ask Mr. Kissinger to comment a bit on transparency, because a core part of our obligation here is on the way that we interact with AGDC, the way that we maintain a formal dialogue and information flow, and provide AGDC the oversight as a partner to make sure this project is being done and being done in the right way. So I will turn to Mr. Kissinger just to outline what those mechanics look like. This is Matt Kissinger for the record.

With respect to the transparency and just the relationship in general between AGDC and Glenfarm, we have these requirements. So we have the monthly report. We also have the monthly Development Consultation Committee. Which I sit on, as well as my colleague Brad Chastain from AGDC. And that's where we go through the details of all the elements of the project, from the technical aspects to the commercial and agreement aspects of it.

Further, we have the board. I think it's been established earlier, but I'll say it again. The board is really more of an oversight function. Where AGDC actually gets its core powers in the agreement is through AGDC approval rights on specific items that we've talked about. So AGDC has kind of, you know, carte blanche veto rights on certain things such as any contracts, key contracts that do not comply with the Alaska Advantage principles.

I think I've laid out those Alaska Advantage principles before, but it is using Alaskans for the project, Having an Alaskan business, building it as an Alaskan business, delivering gas to Alaskans, 500 million standard cubic feet reserved, expanding the project should we grow beyond that, using differential rates, but only where they achieve the lowest possible utility rate. And that was crafted very carefully, not to say a lower utility rate, but the lowest possible utility rate. In addition to all that, though, and this is really important, is we've built a relationship built on trust over the last couple of years as we moved through the negotiation of the agreements and then on towards executing these agreements and operationalizing them. So there's a vast amount of information, project information, and consultation that is done beyond those requirements. And this is one of the things that we really wanted to safeguard in this process.

[SPEAKING SPANISH] success. We want to be able to walk that fine line between oversight of Glenfarn and being a true partner and contributor with Glenfarn. And I think that we have achieved that.

Mr. Richards. Mr. Chairman, again, Frank Richards for the record. As AGDC's president, as Matt described, I sit on the board of H-Star Alaska— and I take that role as the state's representative to look at the efforts that Glenfarm is doing in compliance with these diligent development efforts. And so that is key to us to make sure that as a developer they are moving this project forward, they're meeting these requirements and reporting to us so that we have the ability to, to make those decisions on whether or not they are achieving these development efforts. And as Senator Coffin has talked about previously, you know, looking at a dashboard.

This is our dashboard that we measure the progress and the efforts that Glenfarm is doing to be able to assure ourselves as the state's representatives that this project is continuing to advance and move forward in the timelines and as well as within the goals that we have set forward from our Alaskan Advantage principles to the lowest price price-cost to Alaskans. Senator Steadman. Just a couple quick things. I think you'd mentioned you're at Class 2, but I think on your cost review, but Class 2, isn't that just the pipe? And you're at a different class on the liquefaction plant and the conditioning plant?

Senator Steadman, through the chair, that's absolutely correct. And so there's a Class 2 estimate completed on the pipeline in December. We're relying on more historical Class 3 and Class 4 estimates on the LNG facility and the gas treatment facility. And for those at home, what is a Class 2? A Class 2 estimate, Senator Simon, through the Chair, is an estimate that has a range of between plus 15% and minus 10% of accuracy.

Okay, and then maybe on the Class 4, I think the other ones are at Class 4, Class 4, what kind of ranges are on those roughly? Through the chair, Frank Richards. Again, Class 4, from memory, I believe is plus 30, minus 25% in terms of accuracy. Okay. As again, for those at home, when we talk about the classes of estimates, these are standards that were set by the American Association of Cost Estimators.

So Class 5 is feasibility, Class 4 is Class 3 is feed level of effort. Class 2 is again essentially with construction bids. So as the numbers get smaller, the accuracy and the definition get tighter. And so your consideration of the costs are that you are getting close to that point of what it's actually going to cost to build and execute the project. Okay, thank you.

Senator Steadman. And then just help me with this, 'cause earlier we were talking about common carrier and contract carrier pipes. Common carrier has open seasons. People come in, express their interest, more or less bid on the volume. You get the volume, you build your project or you pick out who you enter.

Contract carrier, you got to cut the deal. Each deal could be different. We have 3— we have a conditioning plant, a pipeline, and liquefaction plant, and we got 8 stores of If I got a bunch of gas, who do I haggle with to get my gas in the pipe? Explain how that works. Mr. Smith.

Because there is— we've struggled for years, just in preference, we've struggled for years with a virtual closed basin that we are now— is being opened the last decade or so with oil. This is a different direction with the gas line. It's going to be restrictive. So help me with that process. Senator Sedman, through the chair, the Alaska LNG project is permitted under FERC Section 3, which does allow it to be, which does structure it as a contract carrier.

It's structured as a FERC Section 3 because of its association and connectivity to the Alaska LNG export project. Because it is essentially an appurtenance to an LNG export facility, it's permitted under Section 3, which is a contract carrier structure. So then who does, if I'm Senator Steadman's gas company on the North Slope, who do I haggle with to get my gas in the pipe? How does that work? Senator Steadman, through the Chair, ultimately those would be contracts between Senator Steadman Gas Company and the 8 Star Alaska Pipeline Company.

That's 8 Star Gold? That's the parent? That's the company that they haggle with? Senator Sudman, through the chair, ultimately those contracts would be with 8 Star Pipeline. Okay.

And so the whole thing, you know— The lead developer team would lead the negotiation of those contracts. Senator Steiner. So it's the pipeline portion, Phase 1, that would control the pipeline access for gas. Senator Steiner, through the chair, yes. Okay.

And then there's contractual provisions because you got to get through the conditioning plant and there's 45Q credits and all kinds of other things involved up there. That's a whole different issue that we'll, you know, to work on. And then the liquefaction plant. Plant, so there must be some form of agreements to connect all those. So one group can't hold hostage the other one?

Senator Sedman, through the Chair, there will be agreements. Effectively, the gas treatment facility will provide a tolling service that will be a service to treat the gas before it goes into the pipeline. The LNG The facility itself will effectively— will contractually operate as a customer to the pipeline. And so you will have some— you can call them— you will have some agreements across these three projects to make them all work, as would be, you know, very standard in any kind of, you know, infrastructure project with different components. Okay.

Thank you. If I may just add a little more context to that. Please. Senator Steadman, through the chair, the important difference between this and where you'd normally see your common access is that, again, this is project finance with these really long-term contracts. So it's going to be 20-year contracts that you have to have lined up upfront before you achieve an FID.

But what we've done to accommodate future customers— so all the customers of the pipeline initially need to be signing up now, and we're talking to everyone who will talk to us, of course, for that gas. 30 Years. 30 Years for the pipeline, excuse me. As you move forward, that's when you'll get into the Alaska Advantage principle. So if there's no customer on the downstream end of the pipeline, that's very— going to be very difficult for them to come in.

But if we have Alaska customers and the pipeline is full, that's when we would invoke this Alaska Advantage principle that the pipeline needs to be expanded to accommodate those customers. And when you get into some of these old discussions around rolled-in rates or not rolled-in rates, it's all about the objective of getting the lowest possible cost to utility customers, whether that would get rolled in or whether you'd have differential rates. But that's the only goal to differential rates and the only use of them. Mr. Chairman? Nope, that's good.

So Class 2, for the power Pipeline plus or minus 15%, what is the base that you've given us before? What is $16 point— what billion dollars and over/under 15%, what's that cost again? Senator— Chairman Hoffman, one of the things I will— I want to make clear is that the ranges that we're provided earlier weren't necessarily direct correlations with the range for the estimates. The FEED outcomes and those ranges were inputs that inform us. But for example, while we have a Class 4 estimate on the LNG facility, that's a data point.

We also have our own experience of actively bidding out components and construction and labor for LNG facility in Texas, so that's another input. We're talking to banks on multiple projects, and so that's an input to the cost. And so all of those things are inputs to those cost estimates. But can you provide the committee with what the cost of the pipeline would be at Phase 2 or Level 2? For 15— plus 15%.

Senator Chair Hoffman, if I'm understanding, if you're asking what is the range that we provided earlier, or—. Well, you had the range that you provided Senator Steadman and I when we had a private meeting with the Governor. And with Class II, do we have a number at 15% for the pipeline? It's 1.15 times the 16.6. Right, right.

So, Chair Hoffman, the range that we presented to you to the co-chairs of this committee is the same range that we presented publicly to this committee earlier in this special session, and that does incorporate, I guess, the fluctuation that comes with a Class II estimate. Yes, and can you go over those, please? Just for the pipeline. Sure. The—.

So $16.8 billion? That was the high end. Right, so at 10% less is $15.2 billion? Yeah. So, and you'll have to pardon me if I misspeak.

I got it. I believe we gave an estimate that was $13.8 billion on the low end and $16.8 billion on the high end. That was the range that was presented here as our expected cost for the project. Senator Steadman. Yes, thank you, Mr.

Chairman. I went and grabbed it. The low end is $13.2 billion, the high end $16.9 billion, mid-range at $15 billion— $50 million rounded off— $15 billion. Then you have to add 15% contingency, so you are up at $17.3 billion. That is the mid-range plus 15%.

The high range plus 15% is $19 So that's why we've been talking at the table, making comments. It's $18 billion pipeline or $17 billion pipeline. We'll know when it's built how much it costs. Obviously we hope it's lower. But $17 billion to $18 billion.

Would you concur? Thank you, Senator Sudman. Apologies for straining my memory and not wanting to misspeak. I concur and appreciate— what I do want to be clear is that the range that we presented is the expected CAPEX, actual construction costs, and there will be contingency added to that, and that's reflective of numbers that Senator Stabenow said. Thank you.

I just wanted to end with that so people know that the numbers that we're looking at for the pipeline, which is very important and it's still a very large number. Senator Steadman. Yes, I'd just like to add, you know, when we had our presentation a few days ago on cost overruns from the— I think Pegasus or— cost overruns start after the 15% contingency is added. So the cost overruns would start somewhere around $17, $18 billion. $1.5 Billion.

Anything north of that would be cost overruns. So if they can come in without the cost overruns, this would be very, very successful. Because the odds are not high. And we hope that they could come in lower.

Further questions or comments? Senator Kelly. Thank you, Chair Hoffman. So if these key requirements are not met, can you explain logistically what will happen?

Senator Merrick, that's something that we would need to come back to you on. That's something we need to talk to my partners about. It's part of our agreement that hasn't been disclosed. Senator Kelly. Thank you.

Earlier today you you discussed arbitration. Can you explain what circumstances would trigger that? What I can say, Senator Merrick, is if you were to have a dispute in a joint venture like this, almost always, and including in ours, those types of disputes would ultimately be determined through the arbitration process. Senator Kelly. Thank you, Mr. Chairman.

So can you give me an example of What the disputes would be?

Senator Merrick, example would be if AGDC decided to breach material obligations and Glenfarm decided to sue AGDC, we would resolve that through an arbitration process. Senator Kelly. Thank you, Mr. Chairman. Thank you, Senator Kelly. Further comments or questions on the presentation?

Senator Cronk and then Senator Keele. Thank you, Mr. Chair. I'm going to roll back on my pitch about this Fairbanks spur line. I think we have to highlight some of the important parts of it.

Thank you, Senator Hoffman and Olson, for the PCE program because I don't think people realize that rail-billed electricity price goes down, we in rural Alaska also benefit. Because I know we've heard a lot of things that, you know, rural Alaska is not going to benefit from this. And I just wanted to highlight that because the lower we can get these costs, especially electrical costs, the better off we all are. And I just want to, you know, just say the importance of, you know, maybe the spur line from Fairbanks isn't going to immediately affect as many households as we want, but if it does get that electrical rate down, that is a huge huge benefit right off the bat as they build their infrastructure out. I know half of my constituents live in Fairbanks, half of my constituents are very rural.

They use Fairbanks as their hub. Senator Hoffman and Olson's constituents use Anchorage as their hub. So to single anyone out, which is not more important, right? Our hubs are important. Our urban areas are important.

So I just want to highlight the fact that urban Alaska is important to rural Alaska as rural Alaska is important to urban Alaska. And this project, this is why I support this project, the whole line and the Fairbanks Spur Line, because this is gonna be very beneficial. So when my constituents travel to Fairbanks, your constituents travel to Anchorage, hopefully with these lower energy costs, that there's more money in their pocket. Maybe that hotel room's $20 cheaper. Most, all of our constituents go for medical care there.

For the most part, serious medical care there. So this is a big deal. Energy is the key to Alaska's future. And so I just— that's why I'm saying I'm just gonna throw my pitch out there of how important this project is to Alaska for my kids, my, you know, my kids, my grandkids, your kids, your grandkids. This is it.

This is the project that is going to push us forward for the next 50 years, 100 years. So I think that's my pitch. Thank you, Senator Kaufman. Thank you for those comments on Power Cost Equalization, but Power Cost Equalization only deals with the high cost of electricity, which in rural Alaska, the largest cost to individuals is heating their homes. Many people in rural Alaska are spending 60% of their disposable income on utility costs.

I talked about on Senate floor what a report was given that rural residents may see costs of fuel, heating fuel, as high as $20, $25 a gallon. So there are tremendous differences in energy costs for people in rural Alaska. [FOREIGN LANGUAGE] versus people on the rail belt versus people in Southeast and out the chain. But I don't think anyone can even fathom spending 60% of their disposable income on energy. Senator Kiel.

Thank you, Mr. Chairman. Sorry, I'm still on that heating fuel price. I wanted to To go back, though, to Senator Merrick's line of questioning a little bit, we talked a little bit at the earlier meeting about the concept, heaven forfend we end up not having a project of the need to repay the value added to the project. We talked about whether a a tax concession added value to the project. But the other sort of concept that when Senator Merrick asked what sort of thing might go to arbitration, if there are— if there's work being done at reduced rates now by contractors on the hope of future work, hope or commitment, either one, would that be reimbursable at— the price paid or at the market value?

I think that's more for you.

Senator Kilther through the Chair, in that I'm not sure I have an answer to that hypothetical because I think it would be as negotiated.

If that hypothetical existed. I don't know.

If I may, Mr. Chairman. Senator Kiehl.

A lot of good arbitrators everywhere. If it ended up in court, that'd be in Alaska court? Senator Kiehl, through the Chair, I need to double-check the rules. Geography of the arbitration. It wouldn't be in a court, it would be in arbitration.

Senator Keel. Fair enough. Working under— but under Alaska law, I assume. Senator Keel, through the chair, I believe it's been publicly testified by AGDC, it would be under Delaware law. So the Delaware law governs the joint venture agreement.

For an LLC, which is, I'd say, what you would see in virtually all agreements of this nature at this scope.

I missed that testimony previously. Thank you for bringing me up to speed. Anybody got the difference for me? Senator Kiehl, through the Chair, do you mean the difference between Alaska law and Delaware law in this matter? In this matter.

Not all of Alaska, just this. I'd have to have legal counsel provide that. Can't speak to it confidently.

Major elements. Again, Senator Keel, through the Chair, I'm not really aware of any particular differences, so I would have to have legal counsel explain any differences.

If you're asking the general differences between Alaska law and Delaware law as it relates to an agreement of this nature, I would just say that Delaware law has the most robust corpus of corporate and business transaction precedence and the most detailed body of law on on how corporate transactions and corporate partnerships are structured. That's why it's the predominant form—. Thank you. —The predominant forum or choice of law for contracts like this. Senator Kyl.

Thank you, Mr. Chair. They also have a weird corporate-only court of unaccountable folks, so— which forms its own microbar association and writes its own laws. So there's a— it would be good to understand why it was important, but I appreciate it. Thank you.

With that, that concludes the hearing today. Do any one of you or all of you want to have any closing comments at this point? Mr. Hoffman, thank you very much. Just to express the— our gratitude for the hard work and for the collaborative— for the constructive dialogue. Again, we're committed to undertaking this project.

We can't underscore enough that it is a challenging project, but we think that the economic picture that's been put together here could deliver a viable project, but also need to caution that material changes to the economics, if they don't take into account the full picture, particularly the impact on the price cap, could put the project in a very challenging situation. So I appreciate your consideration of that point. And as discussed earlier, we look forward to providing more detail about the— I guess the sensitivities to adjustments in a hypothetical mill rate, which we'll do. Mr. Kissinger. Yep, Chair Hoffman and members of the committee, I would just reiterate that the bill that is before us has had a lot of good work in it.

It's a well-balanced bill. We look forward to making it better with this committee and moving it forward. Thank you, Mr. Kissinger. Mr. Richards. Mr. Chairman, I think what you heard from us today, and not only in the sectional analysis but in today's discussion about the Fairbanks Spur Line, is that there is great opportunity for Alaska to benefit from this Alaska Gas Line.

And that a lot of the discussion that we've had in this building over the last 3 to 4 months has moved, um, again, with the concurrence of the developer towards what we feel is a more achievable outcome that will allow for the economics of this project to actually be achieved. We've all talked about how marginal the economics are of the Alaska LNG Project. Having in place an alternative volumetric tax as opposed to the existing oil and gas property taxes We did work that in conjunction with the mayors, and that was actually one of their priorities, that it was a switch from the millage rate then to the AVT. That's the outcome of what the municipalities that will be affected by this project are looking at. So I compliment the committee as well as the broader legislature and the work that has been done.

We are at the precipice of this project advancing forward. And it, as we've described and Senator Cronk has described, the transformational benefits of this project to Alaska. And I think that we all are in the position to be able to make that happen. And we'll position Alaska then to not only be a place that folks will again want to move back to because we'll have lower cost energy, but there will be an economy due to that lower cost energy. [SPEAKING NATIVE LANGUAGE] be that will allow us to progress into the future for not only this generation, but the next generation, but the one following that.

So I ask for your, again, diligence and working positively to achieve this lofty goal. Thank you, Mr. Richard. That concludes this afternoon's meeting. Our next meeting is tomorrow morning at 9:00 a.m., June The 17th—. Committee.

—That we are adjourned.