Taxes and the Alaska Gas Line: The Fiscal Questions Behind AK's Energy Future

Today we're looking at one specific question: how tax and fiscal policies shape the prospects for North Slope natural gas pipeline. Not whether the line should be built— that is not ours to decide. What we want to understand are the tradeoffs and what different fiscal structures would mean for the state, for ratepayers, for local government, and for the economics of the project itself. Our speakers come at this from very different angles, and several are directly involved in advancing the project. What they represent reflects their own views and data, not the positions of Commonwealth North.

So some housekeeping: we will run from now until 1:30. We may push a little past the hour depending on our speaker availability. Please keep your audio muted throughout. If you have a question, put it in the chat as we go on, and I'll be watching and pulling from it. We will start with short introductions, then each speaker presents in turn.

After the presentation, move into moderated Q&A where I will mix my own questions with yours from the chat. At the very end, I'll put up a poll. It helps us shape what we do next. Our speakers: Brett Watson— and this is the order that they'll be speaking— or Brett Watson, he's an economist at the Institute of Social and Economic Research who will set the table on the fiscal and economic framework. Matt Kissinger, commercial director at the Alaska Gas Line Development Corporation, the state corporation behind the project.

John Sims, President of Enstar Natural Gas Company, on the rural built's natural gas needs. Peter Machichie, Mayor of the Kenai Peninsula Borough, on what this means for local government and the community where much of the infrastructure would sit. And Senator Cathy Giesel, Alaska Senate Majority Leader, with her view from the legislature. So with that, let's get started. Brett, the floor is yours, and you can start sharing your screen.

Me get my slides up here.

Sorry, folks.

Ross, I just presume that that was not my slides that was displaying, right?

On my end, no. Yeah, okay.

But it did say that you were screen sharing a second ago. Okay. There we go. Those look like slides. All right.

So Ross asked me to share some perspectives on the AKLNG project. Ross, I appreciated something, a feature of your introduction. You talked about many people can approach an elephant and come away with different perspectives of exactly what they're touching. This is an enormous project, and there's an old adage about how to eat an elephant, sort of one bite at a time, right? And so these are kind of the bites that I've been thinking about related to AK LNG lately.

So I've been thinking about this project from the standpoint of the various impacts that it will have on the state, the state's economy, Roughly speaking, I can kind of break those impacts into 4 broad categories. There are impacts to the state's energy system, particularly on the rail belt, but because of our state's power cost equalization program, there's going to be important linkages between what happens on the rail belt and what happens to rural Alaska, right? That linkage through policy. There's also important inter— economic interactions that happen between urban and rail belt Alaska and rural Alaska that will also have an impact on energy prices in rural Alaska through this project. This is also a tremendous economic development project, private sector economic development project.

There'll be thousands of— potentially thousands of construction jobs sort of on the front end as we build the project, and then operations and maintenance will lead to hundreds or even thousands of jobs associated with the operating and maintenance, particularly at the LNG facility. And through, through the project delivering lower energy prices, this might also induce additional industrial demand, thinking about opportunities like the restart of the Aggram fertilizer facility, new mining opportunities, thinking here particularly of the Donlin mine, or some types of investments that the state hasn't seen in the past, like data centers. The project also represents represents a potentially very significant source of new state and local tax revenue. That's another important impact of the project. And then the project also has sort of a number of what I would call more ephemeral impacts on state and federal strategic goals, maybe thinking principally here of energy security for our state's military bases.

That's an important federal goal, and one that the project might meaningfully contribute to. So the main focus of my remarks this afternoon are actually going to be on this first category of impacts, which have been occupying a lot of my thinking lately around the project's impacts for rail belt utility prices. I want to focus my remarks on this topic specifically because I think that this conceptualization of the Alaska LNG— or the conceptualization of the Alaska LNG project today is really predicated on this idea. In past iterations of this project or other ideas about how to monetize North Slope gas, the things that differentiate those potential projects from this one is this project's ability to deliver energy to the rail belt. And so I think that when we talk about this project specifically, focusing on that feature is important.

Um, I want to frame this conversation by thinking about 4 potential futures for AK LNG. Um, the first future is one in which the project is successful. And when I say successful, I mean that it's completed on a reasonable schedule and budget, sort of consistent with the proposal as it's been outlined. So what would success look like? Then I want to think about a future where the project is partly successful.

And when I say partly successful, I mean the completion of a Phase 1 pipeline without that Phase 2 LNG export infrastructure receiving a final investment decision. What would that future look like for Alaska? I want to imagine a future in which there's no project, in which this project goes away. No longer kind of lingering in the wings, but sort of disappears from our consciousness. And then I finally want to imagine a state of the world or a future in which we remain in limbo.

And when I say limbo here, I mean a world in which we take short stopgap measures in order to meet our energy demand as we wait for phase one, but a world in which phase one is sort of, is a project that we're always chasing and not necessarily seeing achievement from. So let's imagine those four states of the world and how they would play out. So the status quo phase of the world, or the state of the world, is this no-project alternative, right? No LNG project is delivered and developers walk away from it, um, and the state is left to find alternatives. Um, so what do those alternatives look like?

Um, so as contracts with Cook Inlet producers expire for the South Central utilities over the next 6 to 7 years, Those utility companies are going to have to find new gas supply. That new gas supply could really come in two forms. It could come from new development of Cook Inlet energy. Um, after all, there's tremendous gas resources in the Cook Inlet. The question is whether or not that gas can be delivered at a price that consumers are willing to pay.

Um, or it can be met through some combination of new Cook Inlet development and LNG imports. We don't know exactly what that combination would look like in this no-project case. But suffice it to say, it would be some combination of those two. So what would energy prices look like in this scenario? So over the last 10 years, Pacific LNG prices, which is the market that we would be purchasing gas from, have ranged between about $5 to $15 per thousand cubic feet in what I would call sort of normal time periods.

There have been aberrations, though, during the COVID pandemic, particularly in the initial COVID pandemic. Prices fell to as low as $2 per MCF in the Pacific, but were around sort of $4 during those first couple of months. And then recently, we've also seen big spikes in Pacific LNG prices. After Russia's invasion of Ukraine, Russia— LNG prices spiked on the daily spot market up to like $70 an MCF, but sort of averaged over this time period of the initial phases after the war started around $30 an MCF. Today, prices sit at around $19, and it have been for the last couple of months due to the closure of the Strait of Hormuz, the disruption of energy supply chains coming from, um, uh, the Gulf, uh, and, um, and some destruction of Qatari LNG export infrastructure.

So estimates from NSTAR suggest that in addition to the purchasing the commodity on the spot market, we'd need to pay an additional dollar or so per MCF to ship that gas an additional $3 to $5 on top of that to build the infrastructure to receive that gas and regasify it from its LNG form. So kind of all-in costs from this no-project case represent gas prices somewhere in the neighborhood of $9 to $21. So that's a big range, and there's also potential for significant upside to that range. Again, these are— this is a cost or a price estimate sort of in normal time periods. But if we were looking at sort of abnormal time periods like the one that we're living in today or during Russia's invasion of Ukraine, there's significant upside risk for those prices.

Under the no-project case, we also might have some opportunity to develop some alternative energy infrastructure projects. Most of these projects, as they're proposed today, are relatively small, save for maybe the Susitna-Watana Dam or the TerraCoal Energy Project. Those could deliver more significant demand offsets, but their timelines are sort of uncertain, and it's not totally clear what the cost would be compared to these other alternatives, but certainly something that you could think about in this no-project scenario. So I want to plot prices. These are historical prices, prevailing prices in the Cook Inlet Basin since 1992.

One of the things I think it's important to emphasize about the no-project case is where we are today is not where we will be in the future. We can look at the crystal ball, see when these contracts are expiring, look at those Pacific LNG prices, and come up with an estimate for what this blended price might be over this period of time when contracts are sort of rolling off in the Cook Inlet. So you can see here that we're going to be phasing or marching toward around a $15 price point, right? In 2033, when all of NStar's contracts have expired,, we're probably facing around $15 per MCF gas. I want to emphasize, though, that there's considerable volatility in these LNG prices.

This is a plot of LNG prices with that $5 premium added to them. So how much would it cost to actually get gas landed, uh, and regasified here in Anchorage added to the LNG spot price in Asia? So you can see that there's a lot of volatility there. I've taken this 10-year average and extrapolated that as maybe the fixed price term. But I think it's important to emphasize that there's just a lot of uncertainty about exactly what these LNG contracts might look like.

We might price our LNG gas on some index, so we might expose ourselves to that volatility. This is how some LNG contracts are written, where you peg it to some index price like JPM or JKM. We might price it to like a Henry Hub index or a Brent index too. It's all a matter of negotiation and timing of negotiation. If we're in a— negotiating during a high price period, we might face a higher price.

If we're negotiating during a lower price period, we might face a lower price. How much volatility we expose ourselves to, all a matter of sort of the specific terms and timing of the contracts. Um, so considerable uncertainty here, I think worth emphasizing. So this is what the no-project future might look like. Contrast that to a successful project.

Um, so a successful project would occur in sort of 4 phases. Um, we'd have the phase that we sit in today, in between now and when we start importing LNG. We would sit in that LNG import phase or stage up until the point that North Slope gas starts to be delivered into South Central, and then we'd sit in that phase up until the point that the complete project is delivered and export volumes are leaving for Asia. So you can see in this table, I've sort of broken down those impacts that I described on my first slide kind of based on the stage that we would sit in on the various phases of the project. So, you know, today we have relatively our gas sits at around $10.

During this LNG import phase, there's considerable uncertainty about what prices we would face. During the North Slope Phase 1 phase, we would look at $16 per MCF gas according to the contracts that NSTAR has recently started to describe. And during the full Phase 2 project, that price would drop down to $5 per MCF. Across these different stages, there's important impacts to state revenue, which I've described in this table, and sort of broader socioeconomic impacts, which are also kind of noted here.

So here's that same figure that I showed before, but now overlaid with what the successful project trajectory prices would look like. So that yellow line is the trajectory for Phase 1 prices. Those start at $16 per MCF and would escalate by 2% or inflation per year, whatever's lower, um, uh, until Phase 2 is achieved, and that's that blue line where prices would drop to $5 and then escalate by 2% or inflation, whichever is lower.

Um, and so you can use— you can see here that this successful project represents a potential trade-off for us. We'd experience slightly higher prices in the near term, significantly lower prices in the longer term, again conditional on the full project being developed.

A partly successful project actually doesn't look that much different than the successful project. Um, we basically just crop off that last stage of the full development. And essentially, we sit on this yellow line, right? Instead of being able to drop down to this blue line, we sit on this yellow line. Prices slowly escalate up.

But again, you know, prices for at least the first couple of decades that the project would be delivering gas into South Central, sort of within the range of natural gas prices that we've seen that we would experience through LNG imports. And then finally, the last future that I can imagine— again, there's variations and combinations of all of these scenarios— but the last future that I would imagine is some stage of limbo where we have to use sort of short-term, high-cost solutions, for example, buying natural gas imports on the spot market or kind of having undersized import infrastructure, kind of large storage requirements associated with that. We sort of limp along waiting for Phase 1, which is always sort of right around the corner., but we do that for sort of an indefinite amount of time. And what that does is it deters investment that we might want to make in alternative or lower-cost energy sources. And so this limbo scenario is really what I think of as sort of the worst-case scenario, right, is we sort of limp along in a state of purgatory, uh, until, um, until we finally decide to cut bait or something.

And, uh, Brett, appreciate it. Uh, we are at time. Oh, yeah, sorry, Ross. Oh, no worries. So, hopefully, we'll go into Q&A and answer— come to your other slides.

And forgot to mention that we have about 10 minutes, and I will thoughtfully interject when appropriate. Next, we have Matt Kissinger. Matt, if you would like, you can kick things off.

Okay, thanks. Thanks again for having me here. My name is Matt Kissinger. I'm the commercial director for AGDC as well as for H-Star, which is the project company owned by Glenfarm and AGDC. First thing I'd like to do is just bring people up to speed on the project.

Going back in time, we started looking at building a pipeline to the US market. Shale gas revolution happened and the producers pivoted to LNG. This is sort of 2011-12 timeframe, and that's what began the producer-led effort, became an equal sort of consortium of AGDC, BP, ExxonMobil, ConocoPhillips, primarily led by Exxon. But the project wasn't economic under that framework. And the reason for that, as Wood Mackenzie provided to us in a 2016 competitiveness analysis, is it was just structured wrong, relying on project-sponsored debt rather than using what's called project finance.

And not following what had become a more developer-led model that you'd seen in the lower 48 along the US Gulf Coast. In late 2016, the producers stepped out and they handed their 75% to the state, to AGDC, to carry forward. And we ran it as a state-led project for several years. And this is where we were over in Asia trying to find the buyers, but really focused on government-to-government relationships, a lot of focus on China. But also on Japan and Korea and on the state-owned enterprises in those countries.

The problem was the project was not really viable under that framework because AGDC was never really in a position to take the project forward as its own developer. It didn't really have the faith of the market, to be honest. So finally, we pivoted to— and this would be in 2019— to a developer-led model, again, very similar to what you see in the lower 48. And the first— and we follow stage gates, bringing discipline into the project and use structuring with— structuring it with project finance, basically taking the advice of Wood Mackenzie from their 2016 report. And one of the first things that we did after restructuring it, etc., is we did an economic stage gate within AGDC.

And in that economic stage gate, we were comparing our ability to deliver LNG to Asia with that of all the competitors. And we found that it was economic, but moderately economic, sort of middle of the pack. And, and the problem is this is a big project. It's a complicated project. And so being middle of the pack was really not the right position.

And so we needed to optimize it further and we identified several optimizations, but 3 of them really stood out. And that was pursuing the loan guarantees with the federal government, getting lower gas prices and addressing the property tax imbalance. With respect to the loan guarantees, there were loan guarantees provided to the pipeline concept to the lower 48. These were provided in 2004 by the federal government and they're inflation adjusted, but they could only be used for pipeline to North America until the bipartisan infrastructure law came around. That's when our congressional delegation helped amend that law and allow these to be used for this project.

And during that time, they had grown to be worth $30 billion. That has the impact of lowering your cost of debt, which has a sizable impact on the project's cost of supply. The next thing was lower gas prices. Just to remind people, this gas is raw, untreated gas. You can't use it.

You can't even use it for utilities. You certainly can't liquefy it because it has CO2 in it. Quite a bit of CO2 if you're talking about the Prudhoe Bay gas. And so we worked with the producers to find the right gas price to move the project forward. But finally, we had the property taxes and we really didn't know where we sat with respect to property taxes.

So we brought in Gas Strategies to benchmark it. And what they found was that other jurisdictions generally had some sort of tax relief, property tax relief. And we were sort of 10 times order of magnitude higher than any of these other jurisdictions.

This was supported also by Wood Mackenzie's review, as well as Gaffney Klein, which is the legislator's advisor. We brought in Glenfarn in 2025. We worked for several years looking for developers. And we created a model where we're very much aligned as AGDC with Glenfarn in getting developer economics out of this project and moving the project forward, as well as giving the state an opportunity to invest, but no longer a requirement to invest as we had under the both the producer-led model and the state-led model. But we still hadn't really addressed property tax.

And of course, now we are. I'm going to shift now. This is talking a lot about how this project's been marginal, all the barriers to this project. But let's talk about what this project has going for it. And to do that, I'd like to compare it with LNG Canada.

So upstream, we are producing an enormous amount of gas. We produce enough gas and re-inject it into the ground just at Prudhoe Bay to supply all of Germany's needs or all of Japan's needs. Whereas LNG Canada, they have a shale gas that they have to keep drilling and drilling and drilling for years and years and years. Plus that shale gas is connected to a market, so they have volatility in their pricing that we don't have. Land rights.

We have our land rights resolved, thankfully. When they built TAPS, they resolved land rights through the Alaska— through the Native Claims Settlement Act. They're unresolved in Canada, and that has led to delays and it led to cost overruns on their pipeline. We avoid the coastal mountains. We go around them.

These were the hardest part of building TAPS, and they are a formidable problem for LNG Canada. Our terminal site is this beautiful gravel site. I see Mayor Maciekian here. I'm sure he can confirm that. It's sited right next to Kenai LNG and Agrium.

Kenai LNG sent and delivered LNG to Japan for around 50 years without a missed cargo. So it's a proven site as opposed to carving your terminal into a mountain in an unproven site. And then just that track record of delivery, the fact that we were able to deliver for 50 years and the unproven track record. So why was LNG Canada able to move forward? And one of the big answers is that they found alignment with the government on the proper fiscal framework.

And they're now paying around $27 million a year in property taxes. If you compare that to the relief that we're looking for, at full volumes, we would be paying around 5 times that much. So even with relief, we'll still be sort of 5 times higher than LNG Canada in our property taxes. We have spent a lot of time in front of the legislature I think that has been a very meaningful conversation that we're having, and I would say that everyone has got the same focus. Everybody is trying to do what's right for Alaska, and I believe that sincerely and across the board.

But we have just a few weeks left in a special session. There's a lot more work to do, and hopefully we can find our way through it. That's all I had. All right, thank you so much. And one thing to note is that this is, this was This was a form that we put together in 3 days, and the amount of preparation everyone has done has been remarkable.

So really very much appreciate that. Now on to John Sims. I will share my screen. And John, if you just want to tell me when to move forward, I will. And sure.

Well, it's got my face on it. That's not fun.

Good. I think so. Okay. Yeah, thanks, Russ. So first off, I want to thank Commonwealth North for putting this together.

Obviously, NSTAR views this as one of the most important issues facing the state here. My name is John Sims. I'm the president of NSTAR. I've been at NSTAR for 21 years, been in the president's role for almost 9, so had the fun opportunity of dealing with these gas supply challenges and working to find a solution. So, Ross, if you go to the next slide, please.

I want to start off, and Brett, thank you for the great walkthrough on some of the economics there. That'll save me some time on mine. I wanted to start off by talking kind of foundationally about cooking production and what we've seen in the past. And probably for a lot of you folks joining, you've seen similar pieces of information. This, you know, gas supply is really a function of 3 different things.

First, it's you have to have the annual volumes in place to serve customers. And this represents the gas that has been produced from the Cook Inlet on an annual basis. You can see back in the glory days of the late '80s, early '90s, we had over 300 BCF of gas that was produced on an annual basis. So how does that relate to NStar? Back in the '90s, NStar was probably right around 25 BCF of gas that it was consuming on an annual basis.

So more than 10 times the Cook Inlet production was as it compares to NStar's annual needs. Now, you can see as some of those long and large legacy fields dropped off, the annual production drops significantly. And right now we're hovering right around 60 to 70 BCF of gas that's produced out of Cook Inlet on an annual basis. And when you think about how that relates to the Cook Inlet utility demand, We consume anywhere from 60 to 70 with some additional demand used by Marathon, the refinery plant there, and some, some of the other production for, for oil. Next slide, please.

Again, looking at the Cook Inlet, the previous slide was looking at annual demand. This is looking at specifically what's produced on a daily basis. Looking over a much shorter time frame from 2010 to 2026, you can see that that's dropped from about 350 million cubic feet a day down to right around 200 million a day. Again, how this relates to NSTAR in the wintertime when we need it the most, NSTAR's annual— or excuse me, daily peak is right around 320 for gas that we have to make sure that we have available to our customers. Now, that would be a 40-year, 50-year weather event where it's sustained 25 below here in Anchorage.

So obviously the Cook Inlet is not producing that today on a daily basis. That's where you see the importance of storage coming into play. We're not going to dive into that here today, but storage is a critical component to how we serve customers and also one of the most valuable services that Hilcorp provides as well. So next slide. And just for everyone's benefit, and I typed it there in the chat, I brought these slides to House Finance.

I'm going to skip over some of these because we have a shortened timeframe. So we're going to, we're going to skip this one right here. You can go back and watch the House Finance on June 1st to hear the information on that one. But if you could skip this, this slide, Ross, and go to the next one, please, for me. Okay.

So this is not the first time that we've been dealing with gas supply challenges. If you look back 2009, Chugach, ML&P, and Enstar were also having a hard time getting gas supply contracts with then Marathon and Conoco who were operating in the inlet. So we hired Petrotechnical Resources of Alaska, or PRA as they're known, to look at an analysis of what's required from an activity perspective to actually meet Cook Inlet Utility customers' demand. And to sum it up really quickly, What PRA said is that in order to meet demand starting in 2010 through 2020, up to 185 wells would need to be drilled over that timeframe. That requires an estimated $1.8 to $2.8 billion and would need about an average of 13.6 wells completed per year.

If that doesn't happen, the shortage of a gas— or excuse me, if that happens, the shortage of gas will likely occur sometime after 2018. So big key points there. We need 185 wells to make sure that we can meet demand in the next 10 years. It's going to require about $2 billion, we'll just say. And that's going to happen over the next 10 years to make sure customers have gas.

So moving on to the next slide, what's happened since then? I pulled these directly from a January 28th presentation from Hilcorp to House Resources. Here's a look at what Hilcorp has done since 2012. Well, they didn't do 185 wells, they did 192 wells, and they've spent over $1.5 billion over that time frame, again, to make sure that Cook Inlet customers, both on the natural gas side, on the electric side, had energy. That required a significant lift and somebody with a significant balance sheet to come in drill those 192 wells, and Hilcorp, from day one since they've been in the Cook Inlet, has done a fantastic job of ensuring that there was enough gas into the Cook Inlet to meet customer demand.

Next slide. Again, this was taken from Hilcorp, just showing the difference between what Hilcorp has done and what all the other Cook Inlet Basin operators have done from a number of wells perspective on an annual basis. You can see over the last few years here, there have been 2 other entities in 2024, 4 other entities in 2025, and 2 wells drilled from other entities during that time frame. The predominant activity is from Hilcorp, which is one of the reasons why NStar is so concerned about them kind of slowing down production and moving their investments other— other places is because there's no one else in Cook Inlet that has the balance sheet to be drilling 192 wells over a 10-year period. Next slide, please.

This kind of tracks some of what Brett was saying as far as the pricing. This, this was again from Hilcorp's presentation with one slight modification, which is that Hilcorp star there at the top. Because of the cold temperatures, NStar was short on gas. And so we reached out to Hilcorp and luckily they were able to deliver an additional half BCF of gas during the month of March. That came at a cost of $16 per MCF.

So, you know, we're kind of seeing these prices are escalating significantly. The Hillcorp contract is down there at $8.36. There is an annual inflator, so it's not going to stay at that rate for the entirety of the contract. We expected about a 1.5% increase over the duration of that contract. But still, to Brett's point, the prices are going up in Cook Inlet.

Let's skip over this one. This was just kind of the delivery profile. Hopping into HEX. So, this is kind of an important point. HEX is the second largest producer in the Cook Inlet.

They've been doing a fantastic job of bringing investment into the inlet. And I think they made some history or some news last year when they doubled production on a daily basis. That doubling of production went from 10 million a day to 25 million a day. So again, NStar needs 320 on that peak day. So just, just to give people perspective on, on what the second largest producer in Cook Inlet can do, it's, it's a a far cry away from what we actually need to make sure our customers have gas.

So that's one of the reasons why we've gone out. We can skip this slide. That's one of the reasons we went out for the RFP that we did from an LNG import perspective. This slide here shows our annual demand and the different contracts that make up how we meet that demand. So the black line represents customer demand.

All the other colors are the contracts or storage that are able to make sure that we ensure that we have gas for customers. All of the green that represents the Hillcorp contract. So in 2033, that green is going away and we need to have another solution in place so that we can meet our customers' needs. I think, Ross, the rest of the discussion is really on sort of our agreements with Glenfarm and some of the pricing. Which has already been discussed by Brett.

So I think I'll defer the rest of my time to Senator Giesel. And then one of the most important things I think about these kind of presentations, the opportunity for folks to ask questions. So I'm gonna stop and let the Senator go ahead and take over. Well, I'm gonna defer, I'm actually gonna have Peter Macici, Mayor Peter Macici speak first and then followed by Kathy. So Peter, if you wanna unmute, you can take it away.

And thank you, John Sims, for such a detailed presentation. Thank you. I need to get you one of the mugs my wife designed that has an M-I, a chick, and a key on it so you'll stop calling me Machichi.

But— Thank you. Commonly mispronounced name. Thank you, Peter Machicki, Kenai Peninsula Borough Mayor. Thrilled to be here today. Many know my history in the LNG industry for for decades.

Um, I, uh, a little bit about the history of the Kenai Peninsula Borough. So this portion of the chat is about kind of local impacts to ground zero, and you can take ground zero negatively or ground zero positively. We see it positive. Um, the bottom line is we— I'm not sure statehood would have occurred when it did without the discovery of oil in Swanson River in '57. Been very active since.

We, in the '70s, produced 250,000 barrels per day of oil in Cook Inlet. Our annual celebration in Soldotna is still called Progress Days, and Progress Days is when we got natural gas to Cook Inlet. It was amazing, right? So very active in the community, in the industry, very supportive of the industry. I have to say that I did the opening for the recent Glenfarn and AGDC trip of investors, approximately 70.

I had a lot of historic photos. I chose purposely not to do a presentation today. Sometimes we overuse slides. Some of your presentations require it. Mine doesn't.

It's about a conversation on the impacts on a community. So, um, there's a reason for property taxes. And I will just say the original bill that was dropped by the governor left us short. We think initially and for the long term, we're going to have about $30 million plus a year of impacts to the Kenai. That one isn't fluffed.

It's not a real number. That's working through the worksheet from AGDC on the impacts to communities during construction and afterward. Um, so we hear a lot of comparisons to property taxes elsewhere, but an apples-to-apples comparison has been very difficult to find. It talks about all government take associated with projects around the world. And if you're accurate about those apples-to-apples impacts, I will tell you that the original bill left us short and with a worrisome potential outcome for our local taxpayers.

Things are tough in Alaska right now. People can't fill their vehicles with fuel. Expenses are very high. Those fuel costs are translating throughout communities on Product prices, inflation. I think I'm looking for the next inflation numbers.

I think we're going to see they're fairly extreme. So what is my job? I put my hand on the Bible for 62,000 people that I represent to fight for them to make sure that they're not subsidizing a very large project that's going to happen right in the middle of our community. And that's going to occur. We are relocating our highway.

There will be a strain on our emergency services, our hospital, our landfill in accordance with the AGDC study that was put forward. We're not making this up. I've heard some fluff from different communities. This is the one community that will be living with thousands of workers for 4 years in a very large facility in perpetuity. And we can say 30 years, but I ran the Kenai LNG facility for decades.

That went 20 years longer than we expected. That's a good thing. I don't want those comments to be taken negatively, but there's a dramatic difference on impacts from the Kenai LNG facility, which will have between 47 and 50% of the value of this impact, um, the value of this project, and other communities. For your pipeline facility, they're going to bury your pipeline 36 inches below the surface, and periodically you'll see a drone fly overhead to do an assessment on whether or not there's a leak, right? This one is relocating a highway, the borough reconnecting those communities to the road, um, and I talked about all the other impacts later.

That's fine. We're, we're ready to go. We're ready, willing, and able and capable to meet the demands of this project. But just give you a few examples. I'm not sure the project's well aware of the partnership that occurs with things like emergency services.

49 CFR Part 193 requires advanced LNG firefighting. We drill together. We'll have a lot more traffic on the waterway. That's good. But the reason for property taxes is that everyone pays an equal share somewhat.

Of the services they've received. This is a condensed facility that will receive every borough service at a very large proportion to the neighboring neighbor, to the neighbor next door who's going to be paying $9,000. Okay, first bill is $2,000, quarter of what the neighbor's paying. And what we've been proposing for a higher take is simply making sure that we're not paying for part of the project. If they become a good neighbor, we're in agreement with Glenfarn at the apparent rate that we're at right now.

Hopefully it survives through the legislature. There will be impacts. That's not a complaint. We don't have our ham— hands out for large volumes of income. We simply want to know that our costs are covered.

So I'm not— this started off very awkwardly, as Matt said. I was involved in earlier iterations of this project. I've been in the LNG business around the world for 40 years. I get it. We always knew that property taxes were an issue.

Always. And we should have begun these communications and negotiations much earlier, should have never gone to the legislature to kind of throw it to the wind without coming to agreement. We should have had our arms linked. I today have the authority to negotiate this under Title 29. So if you don't know, the other large facilities on Kenai Peninsula, in the Kenai Peninsula Borough, like the Marathon facility, the LNG plant, the nutrient facility, are all under Title 29.

They're not 4356 properties. We probably would have come to a similar agreement. We work with those facilities. We want to reduce the holding costs so they not only build here, but when market conditions are challenging, they remain here so that they can come back into service, right? So if this project works, largely dependent on the ultimate price, contract price available to those facilities, Nutrien's may come back into service.

That's really important to us. For those still observant of the Paris Accord, hydrogen is created through ammonia. That's what our plant does. That's a big deal. We want them to come back.

We want the old LNG facility to come back. We want Marathon to have availability of competitive natural gas prices in the future. So they remain here. They can refine for a lower cost in the Lower 48. We're blessed that they're remaining.

So we're fighting for them as well. What I don't know is how 45Q, 45V carbon sequestration and hydrogen production dovetails into the value of this project. I'm kind of looking at it on kind of a pure LNG play. So we're very interested, but just for you to note, we're partners in this project. The construction estimates that we've seen published are $23.6 to $28.4 billion for the LNG facility.

Okay, that means the Kenai Peninsula Borough would be taking from $212 million to $255 million in if they paid the same rate as their neighbor next door. We're giving up between $132 and $175 million with a 75% reduction in property taxes, and we're okay with that. We're not okay with anything lower. We must cover our costs in this community, and we might have to be able to explain to our neighbors who are paying 9 mils the value of a much lower take because we're, team players with the industry. So we're hoping for peripheral value.

Again, that's largely dependent on the ultimate price of natural gas on this side. There is serious peripheral value on Nutrien, the old LNG facility, as I talked about earlier. It's very difficult to determine the local job value going forward. When Cook Inlet production is eventually replaced, you think about the jobs that went away with Nutrien. New facilities require far lower counts of employees just due to automation and the improvements we've done in the industry.

We would like to see at least a break-even, hoping for a significant increase. But the impacts during construction, most difficult thing to deal with with increased student counts in the future is temporary increased student counts, right? That's significantly more expensive. So there are trade-offs. We're excited about this project.

As long as we remain whole, we will be partners as we've always been with the industry. And we're really looking forward. This site is by design, as you know, the water depth, the gravel base, The location in the inlet, it is the perfect location for this export terminal, as the others have been successful since 1969. The community is prepared, skilled, ready, willing, and able. Keep us whole and we'll have a long, beautiful relationship together.

And my last closing comment is, please wrap up Phase 2 ASAP with Phase 1. That divorce has made us very nervous, I'm sure as it does the rest of the market, and Cook Inlet in south-central Alaska, anyone on the rail belt. And we hope that we get to that point by working together. If so, you will see us as everyone else has since 1969 as reliable partners going forward. All right.

Well, thank you, Mayor Michiqui. And without further ado, Katherine Giesel to close. Thanks, Ross. Senator Kathy Giesel. Thanks, Ross.

Yeah, so I'm Senator Kathy Giesel. I'm gonna give you my perspective of this elephant. I love that story. I've been here since territorial days. I was born in the Territory of Alaska.

I've lived here a lifetime. I've been through earthquakes, floods, and significant recessions, and I was here during the building of TAPS. So that's the Trans-Alaska Pipeline. I was here paying the state income tax at that time, as well as the education tax that we had, along with the huge workforce that came in, who was also paying the income tax we had and the education tax we had. I was working in a critical care unit in Anchorage.

That hospital was eventually purchased by the Teamsters Union. That's how much money the Teamsters Union had. That's what the wages were like during the building of TAPS. They went on to build what is now Alaska Regional Hospital. Some of you in Anchorage know where that is.

That again was built by the Teamsters. That's how much money was flowing through our state, not just in wages, but to unions, to businesses, et cetera. This, um, This will have an impact that's very similar. I've lived through this. I am the only one on this, uh, panel today that has a fiduciary responsibility to our entire state.

So when I say to you policymaker considerations, that's the perspective that I have to take, as well as my colleagues, the other 59 legislators in the state legislature. Next slide. So looking back at history, we've talked about history several times. I go back to Jay Hammond, who talks about the ability to administer the state government prudently. The best inducement, indeed obligation, to do so lies in Article 8, Section 2 of Alaska's Constitution.

This is where we are constitutionally obligated to develop our resources for the maximum benefit. Next slide. The maximum benefit of Alaskans. Congress at that time was debating whether to allow us to become a state. I remember my parents' discussion about this and the controversy with they and their friends, but the emphasis was on the ability of us to perform our basic functions of the state and use our mineral resources to the maximum.

Next slide.

And so that meant that we had to have a sufficient tax base to allow reasonable assurance of future existence. It meant that we had to have wise economic and political leadership in the state so that they in turn will turn it back to the people who will come here from every state in the union. Next slide. So We have a giga project before us. A giga project is a project that is of value more than $10 billion.

We were given the legislation for this project on March 20th. That's 2 and a half months ago. Previous to that, the legislature had been told that we weren't necessary. There was nothing we needed to do to allow this project to go forward. It simply would.

It was a private private project. Well, then we found out that in fact, no, there were some pretty big pieces we had to deal with. The Senate Resources Committee, since March 20th, had 36 hearings in less than 2 months on this. We took a deep dive in. We had to look at this idea of complete property tax relief for— from the state and municipal taxes.

You heard Mayor Machicki speak about that. These property tax— this property tax relief would be in place for 10 years after commercial operations began, or until it got to 1 BCF a day of production for a full month. Then it would go to a very small alternative volumetric tax of 6 cents. Very small. This is a $2 mil tax versus the $20 mil property tax we have in place now.

Revenue would be distributed by Department of Revenue, and this AVT would increase by 1% inflation. I don't know how many of you have ever seen 1% inflation. I certainly haven't in my lifetime. It's much more than that. But the revenue estimates was that the state would take in $74 million.

Million annually. That's a 90% tax cut. So we had to dig into this. We had to scrutinize what was going on and act in the best interest of our state. Next slide.

So some of the things that we— guiding principles that we put in place. Number one, protecting Alaska ratepayers. Now, one of the things that we learned in this process is that there's an iron law of megaprojects. So these— this is an iron law that applies to all megaprojects, and that iron law is that more than 50% of the time they are over budget, over time, under benefits, over and over again. So taking that into account, we realized that the fiscals that we may be considering are in jeopardy.

They absolutely can be violated with overruns, overtime, and under-benefits, over-optimistic assumptions. So we looked at capping the price of gas to consumers. We looked at not allowing any cost overruns to be put on taxpayers, onto consumers, Alaska consumers. And we wrestled with who would regulate those tax— or those, uh, those prices of the gas. Who would regulate the tariff?

That's the cost, the transportation cost through the pipeline. Who would regulate that? Would it be the Regulatory Commission of Alaska? Well, this, this project has been permitted under FERC, the Federal Energy Regulatory Commission. That's a very different agency.

It's a question that we had to deal with. Protection for Alaska communities along the corridor and statewide, so we put in considerations for impact payments. What about increased AGDC oversight and transparency? I have presided over the Senate Resources Committee during the producer-led project in the teens, in the early teens, And prior to that project really amping up, the legislature passed some laws that gave AGDC, the Alaska Gas Line Development Corporation, huge latitude. We had to take a look at that and say, wait a second, what kind of oversight and transparency should we be requiring of this agency that is supposed to be acting in the state's interest?

So that's something we looked at. We looked at what bonding authority we might want to have authority over. What about divestiture of any of these assets? We had invested, we have invested, the State of Alaska has invested about $1 billion in a gas pipeline project so far. That investment, 75% of that investment was transferred to Glenfarm.

What if they decided to divest their 75% to a foreign entity? Well, we felt we should know about that and we should have some approval authority. And then of course there's a statutory, um, option to buy into this. There is a proposal that the state of Alaska, through the legislature, would purchase in 25% equity into this project. We would be given according to Glenn Farnes' guidelines, 6 months to make that investment decision.

It would be millions, possibly billions of dollars depending on how much we chose to buy in. We felt that we needed at least a year. So we did put that in our piece of legislation as well. If you would go to the next slide, please. And then we considered revenue measures to offset construction.

As I said, I worked in a critical care unit in an Anchorage hospital. During the building of TAPS. I saw the demand on our police force. This was only in Anchorage. Think about Fairbanks.

That's my hometown where I was born. The demand on roads, the demand on police force, emergency medical services and hospital services. What about the impacts on that? So we created some impact funds. They would be distributed to impacted communities as needed, and then we created some funds that— some funding that would also be distributed per capita across the state to all communities.

We feel strongly that all the communities, all the Alaskans in our state should benefit from this pipeline, especially if we're giving up some of the property tax that the state would otherwise gain. Remember, those revenues are what fund our schools, what fund our state troopers, what fund our transportation systems. Well, this is an interesting piece that Alaskans should consider. As we talked about this, Glenfarm told us that they were putting in place man camps that would have the housing for all the workforce. By the way, they are— have accelerated from 10,000 people workforce to 12,000.

But the workforce would live in these work camps with restricted access and egress. In other words, what they portrayed to us is that these— this workforce would not be living in the community, would not be going buying t-shirts or going to the local bar or Fred Meyer. So I know a lot of communities have said, well, this is going to bring great economic value to our communities with sales to private companies and so forth. I would challenge that based on what Glen Farn has told us. Um, the contingency provisions we put in— what if this project doesn't move forward?

We've given these tax abatements. We want a 10-year, at least a 10-year, uh, discontinuation if this project does not move forward to Phase 2. What if it stops with only Phase 1? We want a limit on how long the tax abatement the forgiveness, the elimination of those property taxes go. And so we put that into the bill as well.

One of the things you may be thinking about here is, wow, there's a lot to consider here, and I'm not even mentioning some of the details that still have unanswered questions. Would you go to the next slide, please? Kathy, we're actually at time for the entire forum. If you have a final thought, you know, I urge you to share it. You know, there's just more to think about.

The 45Q credits have become an issue the Senate Resources was concerned about. We've learned now that actually that will be a tremendous income to Glen Farn and others working on this, and the state will get very little for it. So thanks very much for having me, Ross. Alright, and thank you all for joining, and I realize we're at 1:31, and I hate asking for people to stick around, but would you— does anyone have to leave of our panelists? Can we stick around for another 10 minutes?

Okay, great. And just point of clarification, Brett, I saw in the chat that someone was— and John, you might be able to answer this as well. The difference between the MCF delivered between partial project versus no project. Are they the same, or is Phase 1— how is Phase 1— if only Phase 1 happens, how does that look for Alaska's energy future? Yeah, I'll take that one, and Brett can opine if he's still on.

But the The biggest difference between no project and Phase 1 is really the volatility that you'll see on the LNG import market. So, you know, you can look at JKM futures and get sort of an indication as to what the market thinks they may be. But the reality is, when you look at those futures versus what they actually were, there's an enormous amount of volatility that happens on the LNG market, and that's kind of what Brett was speaking to. What's nice about the Phase 1 project is it's, it's fixed, uh, and it's also capped. So there was a project overrun cost on there.

We, we know that our price is going to be fixed, uh, and only be subject to an inflation factor on an annual basis, similar to all of our contracts. That, that's a huge benefit from a, from a state's perspective, from a regulator's perspective, from a customer's perspective, they're going to know exactly what their cost is going to be extended all the way out to year 25 of the contract if you wanted to. So you don't have that same luxury with LNG import. So that's, that's one of the benefits there of the Phase 1 project. Don, can I ask, does the contract function as a call option, meaning that are there minimum off-takes that you're obligated to procure, or can you take advantage of low-cost LNG if that materializes, or low-cost cooked gas if it materializes?

Yeah, that's a great question, Brett. So that's one of the things that we're still— there's absolutely going to be a minimum that we have to take, similar to all of our contracts with Hilcorp, right? We— there's, there's some amount of take or pay required. And then what we're trying to do, because there is such volatility, and that was actually one of my slides that I that passed over, we can change between 7 BCF from a warm year to a cold year as far as what we actually need. So we're trying to work out some of those finer points in the contract right now, but there's absolutely a minimum take that we have to have.

And we're trying to get as much flexibility as possible, which is a, it's a commercial negotiation piece for them because they're obviously trying to sell as much in the world market as well. So we're just, yeah, we're trying to work through some of those details and still in discussions. But, but yeah, definitely. And then this is for Cathy and Peter. Lower taxes can mean lower consumer energy bills or higher state revenue, but rarely both at once.

Which should Alaska weigh more heavily and for whom? Well, I'm willing to start because I didn't see Cathy's mute button go off for just a moment. There's no doubt that there's interplay.

You know, I was just texting Mr. Sims because I'd like to spend a little bit more time on the project economics associated with Enstar prices and how that interplay actually occurs. But the bottom line for me is At a certain point, it doesn't matter because struggling seniors in my community must get their costs covered. So there's a bottom line local take that's required. And if you go below it, and we heard the less than zero is, or whatever the governor put out originally on the something percent of nothing is nothing. The only thing worse than that is below zero, right?

If my community's getting below zero, it's an unaffordable project. So that has to be— there has to be a baseline of local communities staying whole. That's more important than anything else in this project because until you can promise my constituents lower-cost gas, I don't have something to exchange, right? And that's how we look at it as a local borough. And I'll just add, I think we can do both.

I think we can get reasonable government revenue, and it's not just state revenue, it's local government revenue, as Senator— as Mayor— I keep calling him Senator Machicki, but Mayor Machicki just articulated. I believe we can do that and support this pipeline project. There's numerous questions. The thing is, we can't do this. We can't thread both needles in 2 and a half months, and that's how long it's been since the legislature was first given this bill to consider.

You know, right now Glenfarn is a limited liability corporation. That means they're a pass-through entity, which means they pay no corporate tax to the state of Alaska on their profits. We have seen modeling from our Department of of revenue that they will be making over $400— excuse me, $40 billion a year when this project comes into full production. I think we can thread both needles here by having the appropriate taxes, whether it's a 6 cents AVT or 12 cent, whether it's a pass-through entity tax, or whether we're addressing the 45Q credits, which haven't even been addressed by either the House or the Senate yet. These are complicated questions and we need more than 2.5 months, but we can do this.

I support this gas pipeline, but we've got to do it wisely. And it sounds like for both you guys, just having the appropriate infrastructure cost covered would, would make you happy, you know, on at least the initial development side of the project? I'll just say that yes, for a basis. What my children and grandchildren will be paying for energy costs is a secondary consideration, but I'm answering as a mayor that's responsible for services being adequately compensated by any user in our community. And so that answers a simple Yes, but there's no— nothing simple about this project.

I'll just leave it at that.

And Matt, is there— I mean, obviously Glenfarn has to come to a decision in the fall, so that's one of the reasons that this legislation is moving forward, in order to make the investment profile more appealing and to help move it forward. I mean, is that correct?

What, I mean, what do you see is needed? Like, what, like, what are we, what is the legislature providing that is helping move this, helping the LNG project move forward? And is it needed in order to take it to the next, to Phase 1 or to Phase 2? Yeah, I mean, this really is the crux of what we're dealing with here. So We've talked about this being a gigaproject.

We've talked about the potential for cost overrun risk. And at the same time, this, this belief that the developer will be extracting these large sums of money— if this project was giving off those sort of numbers, that sort of money, this would have been built long ago. This is a marginal project, and we don't need more studies to tell us that. We know this is a marginal project simply by the fact that Despite our need for it, despite this enormous amount of gas, we so far haven't been able to get it done. And so everything needs to be optimized on this project to move it forward.

But you have to balance that with exactly what Mayor Machicki said. You can't leave the communities holding the bag, and everybody recognizes that. Glenfarm recognizes that, and that's why they're not pursuing something like the tax holidays that you see in Texas where these— these LNG projects for the first 10 years are paying, you know, $0 or $1 million a year and then later revert because there are sunset clauses on those, but later revert to a normal tax system that also is much lower than ours. A project like this cannot put out $800 to $1 billion a year in taxes. It's not— it's not like an oil project.

You don't have those kinds of margins. And so it's all about finding this right balance. And I think, you know, we talk about why was this— why did this bill go to the legislature late? And part of that was having the conversations with the mayors and with the local communities was an important foundation to how it was crafted. And I think that has really helped to inform it.

And, you know, everyone wishes that we had more time to move forward, but As you see, Cook Inlet gas resources are declining. We are getting to a point, as I believe Mr. Sims can agree, to where it's becoming quite critical, and we have to move the project forward. So we just have to find that right balance, and hopefully, as Mayor Machicki has alluded to, hopefully we have found that at this point.

Well, thank you. I very much appreciate all of your time. This has been a phenomenal panel and discussion, and it has really helped me understand the situation a lot better.