SFIN-260527-0900

Call the Senate Finance Committee to order. Today is May 27th. It's 5 minutes after 9:00 a.m. Present today Chairman Steadman, Senator Keehl, Senator Merrick, Senator Kaufman, Senator Cronk, and myself, Senator Hoffman. Senator Olson is weathered out at the present time.

We have one item today for consideration of the committee for the rest of the week or the rest of the month, whichever may happen, which is Senate Bill 2001, the gas line of Volumetric Tax, AGDC, and RCA.

We've invited Mr. Nicholas Fulford of Gaffney Klein. We plan to— plan on starting with some of the basic— basics of megaprojects and this project that's proposed. So I didn't bring forward Nicholas Fulford to the committee to identify himself and give us the presentation.

Before we start, we do have in the audience, we're joined by Senator Bjorgman, and I think Senator Meyer or Myers are in the audience as well.

Okay. Good morning, Chair, and good morning, committee members. For the record, my name is Nicholas Fulford, and I'm Senior Director of Gas and LNG at Gaffney Klein.

So I— just before we start, normally we have a basis of opinion slide, which I seem to have omitted, I wanted to briefly mention that Gaffney Klein is a wholly owned subsidiary, indirectly owned subsidiary of Baker Hughes, who manufacture LNG equipment globally. You'll have noticed that Baker Hughes are one of the supply partners for Glenfarm. So I wanted to make it abundantly clear that Gaffney Klein's consulting activities are completely ring-fenced from the activities of Baker Hughes. And that only certain named individuals work on the project with the legislature, so there's no crossover at all. So I just wanted to make that point both for the committee and for the general public.

So perhaps by way of introduction, obviously now Gaffney Klein has been providing input to the state for probably over 20 years. And my own involvement with the state and the LNG project goes back to the days of Senator Parnell and what was known as Senate Bill 138 at that time. And one of the things I wanted to talk about today is some of the changes that have evolved over the years and some of the differences between the project that we're looking at today And that one.

So I think one of the helpful points to point out is back in 2014-15, one of the major elements that I was working on personally was LNG property tax. At the time, there was an entity called the Municipal Advisory Gas Project Review Board, and I worked alongside many of the various mayors and the borough officials at the time. So as we approach the discussions over the next few days and weeks, it's perhaps worth acknowledging that the question of property tax for LNG has been something that has been high up on the agenda for the LNG project for some time. I think there are 3 elements of property tax which have created that degree of attention. One is the magnitude.

You know, it's a relatively high tax for the project to bear. The second is that it affects the near-term economics of the project, which from a developer point of view is particularly troublesome. And the third element, of course, is that as you look at projecting property tax going forwards, because the taxable value of the assets can change, then that means the tax changes as well. So from a fiscal stability point of view, from being able to look forward and forecast, you know, that's another feature. So really it's those three features which have led to really all the debate and dialogue over the last few years, and ones that we can perhaps talk about a little bit today.

So the next point I wanted to make by way of introduction is that I've probably worked personally on dozens of LNG projects around the world, and some of those in Texas, Louisiana, you know, they're very straightforward. Those states host dozens of LNG projects. They make very little difference to the state economy. But then you get other host nations and states where, you know, the effect of the project on the state economy is transformative, and Alaska is very definitely in that category. And then you layer in the particular, you know, characteristics of the Alaska Constitution, where, you know, one of the duties of this committee is to ensure that the state resources are appropriately developed and revenue is generated in the interests of the citizens.

That adds another degree of due diligence that's required. So in that kind of environment with a transformative project with a very clear constitutional requirement, The debate and the dialogue around taxation, government take, and so forth, it does take a long time. And so insofar as it's taken a lot of dialogue here in Alaska, it's not untypical. You know, it's quite— I could point to many other projects around the world where a similar kind of process has happened. And actually, you know, British Columbia, just south of us, is probably a good example of where it probably took the provincial government maybe 5 years to finally reach an accommodation with the developers of LNG Canada, along with the federal government.

So, you know, you could argue the 5 years has been ticking for a while in Alaska, but nevertheless, I think what you're seeing here and the challenges and the diligence that's gone into property tax is quite anticipated.

The second project which I think helps to put today's remarks in context is that today the Alaska LNG project in its entirety is probably the largest gas infrastructure project in consideration. The amount of capital involved, the investment, the flow of revenues, they're on a kind of a giant scale. And so it puts the project on a similar level to TAPS, for example, you know, where, you know, TAPS became a kind of a landmark project for the state, as this would if it were to go ahead. So it's worth remembering that this is an extremely ambitious project, but nevertheless one with huge benefits if it were to go forward.

Thirdly, I think again from my experience looking at formative LNG projects like this, I can't remember any example where an LNG project has been so profitable from the outset that it's had a kind of a plain sailing through to FID. Typically, getting these projects over the line to start with is, is the most difficult thing. Once you've built them, they tend to perform a little better than, than the specification. They, they can be modified, improved. And, you know, again, you look at LNG Canada, they're just considering a major expansion of the plant.

So once you, once you get them moving, that's when the economics really start to improve. And of course, you know, over the years when the debt gets paid off and so forth, the cash flow from these projects is absolutely immense. And, you know, it can be obviously very transformative for the host nation.

Finally, the feature that I wrote about in the report which was published last December discusses fiscal stability, and in some jurisdictions there is such a thing as a fiscal stability agreement, a contractual agreement between between the LNG developers and the government. Some of them contain a kind of a balancing clause such that if taxes change, there's some other compensation that takes place. Clearly, we're not in that category in Alaska, but nonetheless, you know, with the amount of capital deployed and with the reliance on years of revenues, fiscal stability is a key feature which, which will be important in any outcomes that you consider.

So moving on to today's agenda, I have this divided into a number of areas. We can pause as appropriate and come back to it if necessary. But I wanted to start with a little bit of scene setting just to— for the committee and for the public to understand the scale of the project and and really its context in terms of both the state and globally. The next thing I wanted to do was to discuss the, what is still existing legislation, Senate Bill 138, which put in place really the framework for the original LNG project some 10, 12 years ago, and some of the differences that we're seeing today with the Glenfarm project. I wanted to also touch on what I've called other sources of economic benefit.

These relate mainly to the gas treatment plant and the potential for tax credits on the CO2, and, you know, they also relate to, you know, other features like federal loan guarantees. Then I wanted to move on and talk about the LNG market and the competitiveness of the project. And then think about the Phase 1 gas line considerations, and finally competition from Canada, which I think is probably one of the areas where you're going to see most competition in terms of capital and investment. Mr. Fulford, if you have time after all of that, I wonder if you might comment upon the times that we're living in which is the war, and what, if anything, does that have as an impact on this project? Uh, thank you, Chairman, and, uh, that's a very timely remark.

I think, um, at the end of your—. Okay, agenda, I see. I, I will certainly cover that. Thank you, but it's a very valid comment for sure.

So as we think about the project as a whole, it's, as it's planned, it's 20 million tonnes per annum of LNG. That's out of a global market today of about 400. It's actually a billion MMBTUs. It's my British upbringing is mistyping it as therms, so it's 1 billion MMBTUs per annum, which makes some of the maths a lot easier in terms of the revenues and the money. So if you multiply 1 billion MMBTUs by what was the prevailing price in Asia before the conflict in the Middle East, you get about $11 billion per annum of revenue.

The, the other interesting feature, I, I think, which, you know, perhaps puts into context just how important this is for the state— if, if you look at the, the forecasted LNG revenues in the context of the Alaskan economy, it's, it's about a 20% ratio of revenues to current GDP. If you look at Texas, for example, it's less than half a percent. And, you know, if you look at other jurisdictions, the LNG Canada project boosted the BC economy by 3%, with estimated provincial revenues of $78 billion by the 2060s. And certainly in their case, they— as the assessment is that it created some 71,000 jobs. Moving on to the other end of the scale, the resource, we have 35 trillion cubic feet of proven gas up on the North Slope, much of which has been produced already and reinjected.

And even that multiplied by our $11 price, just as an example, you get to about $400 billion worth of gas once it's delivered. And then if you look at the other gas on the slope, even a connection into Arctic Canada, what you see is that there are, you know, years' worth of relatively low-cost gas which could come through this plant ultimately. So some estimates talk about 200 trillion cubic feet of gas in that region. Which would be the equivalent of $2 trillion when it's delivered. So really the, the volumes, the numbers, they're really quite eye-watering, but to get there obviously requires a huge investment as we've discussed.

The, the other feature which sets the Alaska LNG Project apart is the, is the emphasis on capital investment and 'Cause unlike the Gulf Coast projects, which involve smaller capital investment but higher operating costs, for example, gas purchase and shipping, Alaska's quite the opposite. And although it's a gas project, it's almost easier to look at it as if it were a toll road or an airport or some kind of infrastructure project because most of the value for AKLNG is going to be in that midstream, in the processing plant, the pipeline, and the liquefaction. Once you've put those facilities in, the running costs of the project, if you like, are relatively low. And, you know, you'll often read in the press that, you know, Alaska LNG is too expensive, it's, you know, it's never going to fly because of that. In actual fact, I think, as you'll see later on in the presentation, you know, the economics are perfectly feasible under certain conditions.

It's just that the emphasis is on the upfront capital as opposed to the money required to make the project run.

So just to illustrate the preponderance of capital in the project, I put together this chart. Based on some generic assumptions, but what you see here is that out of the delivered price to Asia, for Alaska, probably about 85, you know, 80 to 90% certainly of that value is in the delivered gas, is completely attributable to the upfront capital investment. For the Gulf Coast, it's about a third. So that, that shows, I think, just how much of an infrastructure project this is, which revolves around, you know, initial very large outlays of capital and steady revenue to pay for it. LNG Canada sits somewhere in the middle, about 75%.

So on this slide, I've started talking about the differences between Senate Bill 138 and the current structure. So there are, there are 3, there are 3 typical forms of, of an LNG project in terms of commercial structure. I've chosen 2 of them to illustrate here. One is what's called a fully integrated LNG project, which typically means that the equity investment in the upstream and in the production of the gas remains constant all the way through the value chain down to the ships. And certainly for an equity marketing type of arrangement, for every, for every therm, every MMBTU that a particular producer puts on the ship, it would turn into a cargo further down the road.

So everything is kind of streamlined and, and aligned. And what this means is that the, the number of commercial interfaces and the number of negotiations that have to take place are considerably reduced. And, and that was the project that was— that existed back in 2014-15. With ConocoPhillips, BP in those days, ExxonMobil, and the state all having a similar equity share in the project right the way through from the wellhead down to the LNG ships.

The project that we have in front of us today with Glenfarm is what's called a merchant structure. In that case, the investors in the LNG project, in the infrastructure, the liquefaction, are different from the investors in the upstream, and what that means is that there's a gas purchase agreement which involves the production of the gas and the sales to the LNG project. So, so that creates a major interface which obviously requires considerable negotiation and discussion to, to make it work appropriately. The, the other feature which is a little different, or can be, is the way in which the LNG is sold. I think under the current project, the, the sales mechanism is simply a sale to third parties, creditworthy third parties, and obviously there are a number of Asian LNG buyers who've already indicated interest in, in the project.

The third mechanism, just briefly discussed, is a tolling mechanism, which hasn't been raised in the current context, but it is quite a common mechanism whereby the infrastructure owner of the liquefaction company charges a toll. It's a fixed toll, usually has inflation involved, but it's enough to cover off the the capital investment. So that's a structure which is used quite frequently on the Gulf Coast for people who simply want to buy gas, liquefy it, and then deal with the LNG on the other end.

Senator Steadman. Are you done with this slide? Yes. Okay. Before we go to that slide, that integrated structure you talked about, I think for the state's 25% share, included our royalties plus a gas tax to create that 25% alignment with the 3 major producers in that project, which seems to be quite dissimilar from the merchant structure or this tolling structure that you just mentioned.

Could you help us with that? Thank you, Senator, through the chair. That's, that's an excellent point in that the The original 25% entitlement to equity, I think it was 25% plus or minus depending on how things turned out, was really a direct approximation of the value of the royalty and taxes gas that would have applied to the upstream. And so that's, that's really the the spark which kind of led to this concept of the integrated structure. So obviously the state continues to have options in terms of royalty in kind and taxes gas, but that automatic sort of flow of the state's entitlement to gas all the way through the chain I think is not present in this current scheme.

Even though as a kind of a continuation from the concept which did exist through AGDC, the state continues to have obviously this 25% equity. But the linkage between the state's 25% equity and the taxes, gas royalty in kind concept I think is not present in this project. So when you're looking at Senate Bill 138. I think Senator Olson, Senator Steadman, and myself were at this table when that whole concept was presented into legislation, and we understood the involvement of the, the producers. So can you comment upon the involvement of the producers in the merchant structure?

Are you going to hit on that later.

Thank you, Chair. And I can comment briefly now. I was going to return to it also. Okay. But—.

Yes. Senator Kaufman. Thank you. I'm wondering the— so the merchant structure, the original proposal was producers on the slope looking at— we've got gas, We want to send it south. You described the— what we're looking at now is more of a highway, is the phrase I think you used.

So are you seeing this as a highway with kind of multiple on-ramps, or is the story still all about production on the slope? I was wondering as you were talking about the potential, if you were taking into account other potential basins that might produce gas along the general route. We picture the pipeline as going from point to point, and we've talked in other committees about takeoff points. I'm just wondering if there's been any look at other input points from other potential areas of production throughout the state. Thank you, Senator Kaufman, and through the chair, again, it's a highly relevant question in the sense that Although the merchant structure arguably has some additional complication, one of the benefits is that it's— once you've formed the project, it is easier to start to include gas input from other sources.

One or two of the Australian projects have done this where they've started the project using, you know, a certain gas field, and they've extended it by adding additional gas production areas. So the merchant structure does have that advantage, that it's easier then to add additional gas. Dennis Kaufman. So I think it was— not sure of the numbering system here— I think it was slide 4 where you were talking about the total potential volume. Was that including— I made a little map just preparing for today.

So like the Denana Basin, of course federal offshore, Yukon Flats over in Canada, the Susitna Basin, West Susitna, Cook Inlet, and potentially who knows even Bristol Bay as part of the gas supply continuum we could create with this system.

Yes, Senator, through the chair.

One of the One of the main considerations in terms of where this gas comes from will be the oil environment.

One of the reasons that, for example, that Qatar are so successful as an LNG producer is that the liquids that come with that gas, the condensate, is so valuable that the gas is almost a waste product, that the value of the gas or the cost of gas is almost zero, which is why essentially Qatar remains even now the sort of base supply for global markets. The— one of the key attributes which makes the Alaska LNG project work is that in spite of this very, very high capital involved in investment, The cost of the gas is potentially very low indeed, in the same way. And the reason it's low is because it's associated gas. It certainly for Prudhoe Bay and Point Thompson, a lot of the infrastructure is already there because of the liquids. So as you think about that build-out, the key feature which will determine which of those areas might get developed and included will be a low cost of gas, which most probably will be linked with some kind of liquids development.

Thank you. Thank you, Senator Kaufman. Senator Keel. Thank you, Mr. Chairman. Mr. Fulford, thinking back to previous attempts, and there have been a lot, in the past the legislature spent a lot of time on the potential for expansion.

Whether that's looping, compression, feeder lines, and the question of who pays. Certainly in the past with producer-owned projects, there's been a concern about access and whether the cost of expansion can be a barrier to access. In the project before us, should we be concerned about that? Should we be insisting on a rolled-in rate structure? Structure, which was I think a part of AGEA before I think you were involved in Alaska's work.

But how ought we be thinking about that with the project proposal before us today? Thank you, Senator, and through the chair. Expansion— some features of expansion are usually dealt with in the formative stages of the project in terms of options to either participate or not in expansion and the capital cost that goes with that. So this might be an important, you know, consideration as you consider this project, partly because expansion and essentially greater capital efficiency by pushing more gas and more LNG through those same facilities that's one of the paths that will lead to a much more profitable project and potentially higher cash flows for the state. So expansion usually does get considered at an early stage so that at least there's an outline framework that is in place as expansion then gets considered.

And it's perhaps something to discuss with AGDC and the project developers. Thank you. Thank you, Senator Keogh. Please proceed.

Okay, thank you, Chair. So again, just remaining with this theme of Senate Bill 138, I think we probably talked about quite a few of the features that relate to this slide, but perhaps the key one, which I'll come back to, is this question of the value transfer from the midstream to the upstream. Depending on how that gas supply agreement is, is structured, there could be quite significant flows of revenue between the gas processing plant, the transmission line, and the liquefaction, and the, the upstream. Now obviously, as I think this committee is very well aware, the taxation mechanisms that Alaska has for the upstream are very different from the ones that would apply to the downstream. So one of the considerations here is that with this ebb and flow of value between the upstream and the midstream, what the tax consequences are and what considerations and what policy might be needed to address that.

So I think that's the main point here, which I go on and discuss in more detail.

So the other feature I wanted to talk about in terms of the differences and where we are today is that of disclosures and confidentiality. Again, if, if you look at the, um, list on the right-hand side for Senate Bill 138, because it was an integrated project, um, there was no need for an explicit gas supply agreement. There, there would have been netback calculations, but they'd have been more of an internal accounting thing. The equity structure of the project was set from day one, and the way the LNG was sold was effectively going to be in equity proportions. So you've got these three major areas of agreement, contractual agreements, which were effectively dealt with at the start.

With the Glenfarm AGDC framework, as we've discussed and as has been reported in the media, I think that there's a dialogue going on between Glenfarm and the major producers on the slope. So that requires considerable negotiation. I think I've heard from their testimony that Glenfarm are looking at additional equity participants, so they'll be discussing equity and the value of it with, with, with those. And then of course we have the LNG sales agreements. So certainly for the first two of those, the, the upstream supply agreement and the equity participation.

The economics of the project in a negotiating environment are very, very tightly held because clearly in that commercial back and forth, whether it's around equity or upstream supply, the understanding of the broad economic basis of the project is a key feature. So unlike the— in SB 138, where there was a considerable degree of transparency between ExxonMobil as the developer then, you know, the state and other entities, with the current arrangement, it's not surprising, frankly, that there is some degree of concern over confidentiality, capital costs, and so forth.

So this is a feature which is often encountered in LNG projects of this sort, and I've put a few examples on this next page in terms of how people have dealt with that. Mr. Secretary Steadman. Back on a previous slide, just to— I think we're kind of glossing over the scale, 'cause as I recall that the previous framework of 138, those companies had significant balance sheets to put on the table. But one in particular, ConocoPhillips, as I recall, was concerned that that could be a company-ending event if it was to go south. The project was so big.

And there was obviously concern from the other BP and Exxon, the magnitude, but they had— all three of them had significant balance sheets. In this case, Clunth Farm doesn't. They couldn't finance this thing if they had to by themselves. So I think we're— the scale difference between the previous three participants under 138, including the state with its financial assets and its taxing authority, far eclipses the structure of Glenfarm.

Thank you, Senator, and through the Chair, yeah, that's an excellent point, and it focuses perhaps on the last one on this slide, which is the equity participation. And as you say, looking at the sort of basic financial framework and the companies involved, it is clear that one or more companies with a very significant balance sheet would have to enter the project with equity in order for it to get across the finish line.

Typically that can include producers, or it could be major buyers. I mean, for example, you know, JIRA in Japan, who've signed up at least in principle for some volumes, POSCO conceivably from Korea, PTT in Thailand. These are all companies who typically will take equity. In projects where they're sourcing gas. So there's an array of companies that are AAA credit entities with very strong balance sheets who could enter, but as yet there's no visibility on who they might be and under what terms they might enter the project.

But it is one of the key differences. Senator Steadman. Yes, thank you, Mr. Chairman, because And we'll get into this later, the scale of what we're dealing with, but we could be looking at in excess of $10 or $15 billion in equity.

So this is not an insignificant dollar amount.

So I think at some point when we get into this over the next several days, we need to look at that. Mr. Chairman, and then get into more discussion on the dilution issue, the equity dilution issue, which the state would be facing as a residual owner right now at 25% with no equity participation coming into the project yet from, from a third party.

Thank you, Senator Steadman. Please proceed. Thank you, Chair.

I won't hesitate long on this page. There's a lot of detail on it, but really this is a summary of other LNG projects that have found themselves in a similar situation to yourselves, that you're being asked to determine fiscal policy and potentially change tax rates without, at this point, full visibility into the project economics and so forth. So there are different approaches that have been used, but many of them use a— some kind of common economic tool to evaluate the project. And in fact, I know you've had a lot of analysis done by Department of Revenue that Mr. Stickel has presented. And I believe that model that is currently hosted by Department of Revenue is a derivation of the open book economic model that was in fact used in the days of Senate Bill 138.

So in that sense, you already have a tool readily available which has been well scrubbed, well audited. And so really focusing on that with an appropriate number of counterparties might be the way to find your way through some of these economics. But clearly confidentiality is often raised and indeed is an issue. And that was one of the things that was dealt with under SB 138 with a list of individuals who were authorized to look at the economics. Again, maybe some lessons to be learned for the current situation.

Thank you, Senator Steadman. Please proceed.

So I want to return briefly then to this question of the upstream gas contract, because the way in which it's framed as I say, will have a significant impact on the way the tax flows occur. And certainly in, in the testimony and in the media and so forth, what you typically see is a reference to a, a base price. So is it going to be $1? Is it going to be $1.50? That's, that's typically the sort of rhetoric that goes with it.

The reality is, of course, that it, it won't be a fixed price. There'll be some kind of indexation applied to the, to the price. One common way of indexing gas is, is to use oil, so that's, you know, potentially one of the mechanisms that could be used to determine the price of the gas.

It could be simply some kind of inflationary mechanism but given the nature of the producers who are frankly accustomed to taking commodity risk, I think they would want to see some kind of commodity risk exposure in that gas price. So as I say, one approach would be to use an oil index of some sort, which would be, you know, very conventional. The, the other approach which could be used in this event would be to apply what's called a netback price, such that whatever price is realized for the LNG through a sale in Asia somewhere, some percentage of that would be netted back to the upstream. So, you know, for example, it— you know, the gas price could be structured at, say, 15% of the the sales price or some other number, just an example. But again, that would create, um, much more variability in the earnings and profit pattern in the upstream and the midstream part of the company.

So understanding how that gas contract might work and the terms of the indexation hasn't really surfaced in the discussion and the dialogue, but it's probably something that the legislature will want to focus in on at some point. Could it be that the purchase price in these contracts that are confidential could have different points of sale on the netback?

Uh, thank you, Chair. Certainly, um, I, I would expect naturally that the negotiations between the producers and the LNG company would be carried out independently. That there are some complications around the way in which the joint ventures work on the North Slope, such that I think my understanding certainly is that each of the producers has some flexibility around producing their own gas, which we're seeing to some extent in the supply arrangements planned for the Phase 1 pipeline. But when it comes to, you know, a major sale of multiple BCF a day, there would have to be some coordination between them. But the price that they're paid for that gas could be different, and they could each select a different kind of indexation, conceivably.

Senator Steadman. On the chairman's question, let me try to put a finer point on it, and we'll get into this when we get the Department of Revenue here, but my understanding is there's a prevailing price of gas on the North Slope way in excess of a dollar. Maybe 2.5 times that or some number. And that there's a blended sale price of gas, which then would be like similar to, in concept, to like when we look at TAPS and our oil value, we just look up the price of NS West Coast and we got the price of oil. It's not different for each company, it's a blended price we're dealing with.

And I think that the gas has also a blended price, which may not, you know, some— one firm may be high or lower in their negotiated sale than that tax we would use for, or the price that we would use being blended for our tax calculation.

Solution? Thank you, Senator, through the Chair. I think that's— some sort of mechanism like that could well emerge. And again, it emphasises the importance of the detailed terms of the gas supply agreement. The other brief comment I might offer is that I believe the prevailing price of gas on the North Slope is to do with local industrial demand for power generation and so forth.

And obviously the economies of scale in terms of the compression and the infrastructure which has to be installed to provide that gas are very different for local industrial demand of that sort compared to more meaningful flow of gas either for the Phase 1 pipeline. So I think it's not surprising that that prevailing cost of gas is a little higher than what's being discussed. But no doubt the details will come out in due course. Senator Steadman. And the concern, I guess I should have worded the question a little, little different.

I recognize that the prevailing price of gas is basically for internal use of the North— on the North Slope, power generation and so on and so forth. But then there's the blended price of the value of gas That's already— my understanding is in our statutes already. And that might be something that— or it is something we need to ask Revenue if that is an impairment that we need to deal with. Because what we're talking about here today is a full-blown project with export. But later on, when we get into the tax discussion and some of the finer points, we could possibly end up with just an in-state gas line with no export facilities.

So there's— we need to have, I guess, some clarity on how we position the state, Mr. Chairman, under both alternatives so we don't end up making a tactical error here, end up with a different project than we actually assumed we were going to have when we went through this legislative work this summer.

Do you have a response, Mr.—. Thank you, Chairman. And yeah, I think— I think Senator Steadman's question there really speaks to the level of detail and full understanding that needs to be addressed prior to FID, basically. The other point which was raised is this question of, you know, the Phase 1 gas line being the only project that happens. And later on in the presentation, I have some illustrative numbers around that, because certainly without increased flow rate, the Phase 1 gas line represents quite a challenging economic prospect, or a very high gas price for Southcentral and Fairbanks customers.

So I think this whole question of whether, you know, whether the Phase 1 gas line is an end result or whether it's part of a transition is another key one. Thank you. Thank you, Senator Stidman. Senator Kaufman. Thank you.

I have heard folks consider the possibility that we only get phase 1, but it seems to me like phase 1 is the hurdle. And so if you just consider phase 1 creating the reality of gas essentially at tidewater in these volumes that the economic incentive to grab that gas, liquefy it, and transport it becomes a pretty compelling economic case. So, I guess, have you seen anything that would suggest that there could be a situation where we would get the Stage 1 pipeline that far basically solve the 800-mile problem and get the gas to a point where it could be picked up and used, you know, and transported. Does that seem like a likely possibility considering the economics that would be involved once we got the gas to that point? Thank you, Senator Kaufman.

Through the chair, I think it's helpful to kind of step back and consider what that Phase 1 gas line represents.

And in effect it's a very large option. The—. For South Central customers it represents an option or a line of sight to considerably lower gas prices to those that exist today, with all the economic benefit that would result from that.

For the producers, it's an option to sell, you know, a billion, billion and a half dollars worth of gas every year. So again, for them, that option is very, very valuable. And for Glenfarm, it's an option on essentially launching the rest of the project, as you were indicating. So I think if that Phase 1 gas line project were built, there would be a very, very compelling economic case to complete the project and build the liquefaction. But obviously there's no guarantee.

But certainly, you know, for— you've got 3 sets of stakeholders, if you like. You've got the gas customers, you've got Glenfarm, you've got the producers, all of whom would be very highly incentivized to ensure that that full project were built subsequently. Thank you, Senator Kaufman. Senator Keel. Thank you, Mr. Chairman.

I guess I will ask questions about cost overruns and fiscal structures and who pays maybe later when you look at some of your Phase 1 slides. On the slides in front of us now, the 11 and 12, you have a last bullet about the tax consequence of fixed price as compared to netback price.

And you didn't spend much time on those. Could you talk us through a little bit what the implications would be for the taxing authority there?

Thank you, Senator, and through the Chair.

The— as I say, one of the considerations is that the North Slope producers, they are in the business of producing oil and gas, and their shareholders and their investors are accustomed and attracted by the idea of commodity price risk. So I think it would be— it would be unusual for those companies to enter into a major sales contract which didn't include some kind of commodity price exposure. Further than that, ExxonMobil and ConocoPhillips are one of a small— two members of a very small group of sort of preeminent global LNG companies. They, they both have multi-million ton LNG portfolios, and they've both stated LNG growth as being a major part of their strategies. So, so further than that, you know, I think their interest in the gas as it moves downstream into the LNG market, you know, will be significant, and they will be looking at ways in which they can leverage that with their broader LNG.

So from a from a tax point of view, depending on how far down that road you go, you could go down the road such that the Glenfarm project receives a relatively stable fixed income for the infrastructure, and all the price risk moves to the upstream, in which case you could get, you know, supernormal profits in, for example, at the moment, you know, with LNG prices being extremely high, you would see under that scenario, you would see all that profit moving to the upstream and being taxed, you know, as production tax and royalty for the gas. Equally, you know, in sort of 2020, '21, when we saw a big dip in LNG prices, you would see quite considerable losses in that area.

So this question of how the profits flow and how they get taxed is, you know, is a material one and one which could, you know, significantly change the tax outcome for the state. Follow-up. Senator Kehoe. So I notice in the slide you talk about whether or not— whether a portion of the benefits from the project and thus the profits are pushed to that midstream owner, that pipeline and LNG facility owner, and you talk about corporate income tax. When it comes to royalty and production tax, all of our North Slope operators pay that.

But when it comes to corporate income tax, a company almost gets to choose.

How ought we think about the project in front of us and the legislature's duty in that environment?

Thank you, Senator Keelan. And through the chair, the— Most jurisdictions will apply a corporate income tax to operations, you know, in their jurisdiction. Obviously, there are some historical anomalies which apply here in Alaska, and how they get dealt with is probably outside the scope of today's discussion. But from an LNG perspective, clearly appropriate capturing of corporate income tax going forwards might be something that you would want to consider, given that I think the DOR projections suggest it will be $60, $70 million per annum, depending on where the taxes are set, by the sort of 2040 timeframe. So these are fairly significant revenues for from corporate income tax, which may or may not be captured, as you mentioned.

Thank you. Thank you, Senator Keehl. Senator Steadman. Just to the earlier question about the risk of this project, when we look at the potential of the in-state gas line and then the majors coming in to finish it off, possibly, or somebody else with the liquefaction conditioning plants or what have you.

One of the things that I find curious is that when we look back several years, we had testimony here at the table of why Conoco's in the state. Why is BP here? Why is Exxon? Conoco is here for our oil. BP was here for just harvesting.

They were in harvest mode and that really jacked them up when that hit the table. And Exxon was here for our gas. And if under that scenario, I just find it curious that Exxon's not at the table when it's part of their objective is to get Alaska's gas to market. So there's got to be a reason they're standing on the sideline selling it at the wellhead. Or at the edge of the Point Thompson unit.

And that's just a data point that might want to help us keep our feet on the ground and not get enamored with these huge dollar amounts 30 years from now.

That may or may not ever materialize. Yeah, thank you. Senator Steadman, through the chair, This partly goes back to the request the chair made a few minutes ago to sort of talk about the current environment, because Exxon, one of their global partnerships is with Qatar Energy, and Qatar has been a major platform for them. They're also investing in a liquefaction plant in the Gulf Coast with Qatar Energy. But of course, things have changed considerably in terms of how Qatar is now perceived because of the clear risk to security of supply and indeed the damage that's been done to some of the trains there.

So, you know, one could ask the question of whether Exxon are currently reviewing their gas strategy, and a project of the size of Alaska could perhaps be more attractive than it was a few months ago. But time will tell.

Thank you, Senator Steadman. Please proceed. Thank you.

Yeah, so thank you. Just, um, I wanted to spend just a couple of slides on other sources of economic benefit because we've heard a lot in the different hearings in the legislature over the last few weeks now about property tax and the ABT. But a similar, similar order of magnitude in terms of value to the project is whether or not federal loan guarantees materialize. As I think many of you will know, the legislation, the federal legislation to enable these federal loan guarantees was put in place some decades ago. The precise regulatory framework under which that would happen, I think, needs some work, as I understand it.

And of course, now you have the Energy Dominance Fund and various other federal initiatives which ultimately could help to lower the cost of financing the project. But quick back of the envelope, if you, if you assume a cost of debt of 6.5%, which is not untypical in the LNG area without the federal loan guarantees, if you say it's maybe 5% with them, the, the flow-through is hundreds of millions of dollars in savings, and from a delivered cost of gas in Asia, it represents quite a material saving which could help to push the project into economic territory. So it remains to be seen what will happen on this, but it is a material factor which ultimately will hinge on federal government policy.

So on this topic, since it has been decades since this loan guarantee was brought forward and the President of the United States has said that the development of this project is important to the nation, Why haven't we heard anything from the federal government saying certain things that they could— actions that they could take to push this along? It just seems to be just a general resolution.

Thank you, Chair, and certainly, as you'll recall, Glenfarm entered into the transaction with AGDC just before the election last year, or is it two years ago now? And subsequently we saw a number of executive orders and so forth which came out very positively in support of developing Alaska's resources.

Clearly there are many features of federal policy under, you know, constantly being developed and evolved. But I think all one can say is that as yet none of the moves from the federal side appear to have resulted in a kind of a material agreement relating to the AKLNG project. There's been a lot of support for trade missions to Asia and so forth, and certainly I think Asian countries are being encouraged to enter into agreements for American LNG, and including Alaska, but currently there doesn't appear to be a tangible federal step to help the project. So you It would seem as though this loan guarantee could potentially be critical and with the inflationary numbers that we have, the purchasing power of $20 billion has substantially been reduced. Please proceed.

Thank you, Mr. Chair.

So the, the other interesting element of additional value for the project is the gas treatment plant, which is there to treat the gas to LNG quality. As I think many people will be aware, carbon dioxide in, in the gas to be liquefied can't be tolerated. Even down to a few parts per million. So one of the key prerequisites for the LNG is to remove the CO2. Because of the changes in federal policy around tax credits and so forth since the original project, one of the additional benefits which didn't apply to the, the original project is the ability to collect these tax credits.

So they currently stand at $85 a ton of CO2. I think from AGDC testimony, I think the target CO2 removal from the North Slope would be around 7 million tons. So, you know, clearly we're looking at, you know, a fairly significant saving as well, similar order of magnitude, so 60 cents per MMBtu of delivered gas, so around about $600 million per year of tax credit. One of the interesting features around these tax credits is that you often, you have to sell them to people who can use them, so there's an element of commercial structuring around that gas treatment plant and who might own it, which are relevant here. And of course the other feature of the CO2 is that it can be used for enhanced oil recovery.

Now exactly which oil fields on the slope could be candidates for EOR using CO2 remains to be determined, I think. But nonetheless, I think for every for every ton of CO2 injected, there's the potential for 3 to 5 barrels of oil additional production. So I think it's quite conceivable that that CO2 will have a value to some of the North Slope producers, and that too could generate some revenue for the project. But that's, that's a topic which remains to be seen. But the one thing we do know is that under current federal law, there would be a 12-year period over which this $85 a ton inflated would be available to the project.

Senator Keogh. Thank you, Mr. Chairman. Mr. Fulford, I'm interested in the notion that I hadn't thought through these credits affecting the ownership structure of a gas treatment plant. Can you just build out a little more the notion that— I can't quote what you said, but it's going to affect who can own this thing. What are we talking about?

Thank you, Senator, and through the Chair. Looking at the Lower 48 where these carbon capture projects are quite significantly under development, Because the tax credits are quite material in the context of the investment, using them, monetizing them is the key. So the favored ownership structure for these plants is using a tax partnership, and all I know is that Tax attorneys look very carefully at these structures to ensure that the way the credits flow results in $85 of value. Another way of doing it is to facilitate a mechanism whereby the credits can be sold to somebody else and then used, in which case you'd probably get maybe 80, 90 cents on the dollar for the credits, But the way in which the ownership structure around the CCUS plant is established is kind of pivotal to the whole project and making sure that those credits are monetized. So I would imagine quite a bit of, you know, tax attorney work involved in setting up exactly how the ownership of the project might need to function.

So it may have implications for equity in terms of who can take equity in it, but I think with appropriate structuring, some kind of arrangement could be made. Senator Kiel? Just to follow up, thank you. In the proposal that is under development now, do you have a sense of how, were the state to elect maximum equity that were— is available to us, Would there be offsets if we ought not be an equity owner in a gas treatment plant? Would we have a greater equity stake in some other piece of the project?

How would that be structured then?

Thank you, through the Chair. The fact that each sub-project has been set up with a separate ownership structure around the kind of 8-star holding company does mean exactly that, you know, the state can elect to take equity or not. I think the— of the 3 units, the equity around the treatment plant is probably the most complex because of the reasons I've mentioned, but I wouldn't be in a position to comment really on what the broader implications might be, but it's something that will need to be looked at. Thank you, Senator Kehoe. Senator Steadman.

Don't we already own 25% of that?

75-25 Is the split between us and Glenfarm, is my understanding. So my understanding is that the 75-25 split relates to the holding company. And that as and when FID is taken on the sub-companies, capital will be, you know, put into those companies who will then potentially pay a dividend up to the holding.

So my understanding is that the state has 25% in the holding company, but as and when FID is taken on these other 3 units, that there will be a further election that will have to be made. Senator Steadman. Who owns the 3 subcompanies then? Currently they are owned by 8Star, the holding company, but then they have no assets. I think at the point they have assets assigned to them, then equity in those subcontracts, subprojects will be set.

And we talked earlier about the likelihood that potentially other equity investors will participate in the project.

They would probably be present in those sub-project companies as well.

It gets into the dilution question. So in essence, we own through 8STAR 25% of the sub-companies because we own 25% of 8STAR, is my understanding. And then when they go out to bring in other investors, we'll suffer a dilution issue. Issue. And the question is, how big is the dilution issue?

We have no idea. We could be diluted down without taking an equity position as a new investor in one of those 3 subcompanies. And we're— 8 Star will be diluted and will own 25% of whatever the dilution value of 8Star is. Is that not correct? Thank you, Senator.

Through the Chair, I think I followed your logic, and certainly once FID has taken on those 3 subunits, the state's 25% of the holding company may or may not have significant value.

Senator Stewart. Senator Steadman? My concern, it'll have no value, or virtually no value.

8-Star in the end. Thank you, Senator. I think that's a valid question, maybe one to address to Glen Farn and AGDC. Thank you, Senator Steadman. Please proceed.

Thank you. Well, at this juncture, and I know we're getting fairly short of time, So I can probably go through these slides fairly quickly, but for illustrative purposes—. Take as much time as you need. Okay, thank you, Mr. Chairman. So what I've set out on this slide is the gas supply cost that would have to apply for the pipeline element of the project to reach a 10% rate of return under different scenarios.

So I've taken 3 levels of capital involved in investment— $10, $12, and $14 billion— and I've looked at it using 2 flow rates. And what you can derive from that slide, I think, is that without a significant increase in the forecasted flow rate through the pipeline, the ultimate cost to really the gas utility buying the gas would be relatively high. So I, I know, you know, a $12 price has been put out there as being the the sort of notional price of gas through the pipeline. And you'll see from that that with a relatively conservative $10 billion capital cost and with a 500 million standard cubic feet per day flow rate, you can just about get down to the $12 per million BTU. But in all the other scenarios, you're looking at something, something more.

So on the next slide, I've reversed the question and said, well, if, if the price paid by the gas utility is $12, what does that mean in terms of the rate of return on the pipeline? So what you note here is, as before, with the 500 million standard cubic feet per day and the, the lower capital, then you can just about get to a 10% rate of return. But if it's a lower rate, 300 million standard cubic feet, for example, and a higher capital cost, then the return on the pipeline is very low. So, so that sets out the challenges of the Phase 1 pipeline if, if there aren't any mechanisms to bring up the flow rate. Conversely, if you look at it from the other side of the equation—.

Senator Steadman. Yeah, we're moving a little too fast for my small mind coming from an island that we buy oil and we buy electricity.

So when we look at these prices, $12, that's roughly a $1.50 oil, if I'm not mistaken, in equivalency at 80% efficiency of oil. Around $4 or 4 cents per kilowatt. I think it would be very informative, Mr. Chairman, as we go through this to help people understand what we're talking about in dollars, equivalency of kilowatts and price per oil. And you could use 80% or 90% efficiency conversion on oil, whatever you want to do, if you got a monitor stove or an old boiler. So we can get a benchmark of what we're talking about here.

Because $17 per MMBTU— well, $20 doesn't even get to $3 oil.

So it would be nice to take a look at these conversions because I think the spin rate on a hydro is 4 cents, somewhere in that range. And that would be fairly close to that $12 MMBTU. And one of the concerns that we all have sitting at the table here is, I think in this building, is that we don't make a mistake and we end up putting a rail belt in a position where they have excessively high energy costs and really hurt our economy. But it's hard to do the conversion unless we see a scale of equivalency. So that would be helpful as we go forward.

I don't know what Fairbanks' cost of oil, at $4 oil, that's $30 natural gas per BTU. Just to give a scale on what we're dealing with here. That's important. And for the committee's information, first delivery of fuel barges in Dillingham, Alaska this last weekend. The prices of gas were posted at $9.09 a gallon, and heating oil is probably going to be around that, if not slightly higher than that.

So just for everybody to digest that number. Senator Steadman. That's $65 per MMBTU.

I'll take 12. But I think it would be helpful, and then I think too, as we get on in this subject later on, it'd be nice to get a cash flow breakdown of the project in more detail through the construction when they're asking for concessions from the state. And I recognize that, you know, we have a very high millage rate. But it would be nice to look at the cash flow through the construction to First Gas so we can actually see when the cash calls come into play for property tax. And while we're talking about this topic, I understand that the rail belt uses natural gas, but while we were discussing Senate Bill 138, as a member of this Committee, I said that I thought it was a mistake that Alaska did not look at use of that gas, that oil, in-state.

It was just monetizing it, and the citizens of Alaska did not get any lower energy costs when we were providing the nation at that point between 25 25 to 28% of the oil supply for all of the United States. And I believe that we also should be looking at fixing that when we're talking about developing gas and selling gas for in-state use. Just my viewpoint. Do you have a comment, Mr. Senator Steadman's statement.

Thank you, Chair. And certainly in relation to the comment from Senator Steadman, you know, Alaska has its unique energy challenges, and certainly one of the main benefits of the project, if it goes through in its full form, is that it would transform the cost of energy for the Rail Belt, for Fairbanks, etc. Um, all I would say is that in the context of big LNG projects like this, um, the, the terms of supply for the domestic market are often fully integrated in, into the sort of legislative framework for the, for the project. Even down to legislating a price for the gas. And, you know, what the other thing you often see is a domestic market reservation such that a certain proportion of the gas that's produced for LNG has to go first to the domestic market.

It's interesting what they've just done in Australia. Where obviously they had a huge push to build LNG export facilities, so much so that it's now put pressure on gas prices for eastern Australia. So a new piece of legislation came in the other day enabling, or really forcing, some percentage of that LNG volume to be offered up to the domestic market before export. So this question of, you know, LNG pricing and framework versus energy supply for the host government, it's one that very, very often comes up, and there are often special terms that apply to what in this case would be in-state gas supply. In relation to the LNG project structure.

Senator Steadman. Thank you, Mr. Chairman. You know, it's— the project is being focused on in-state gas.

My district is pretty far away from in-state gas. I mean, I could move out to Adak Island probably and be about as close. But the value that I think my district sees is the enhanced expansion of the oil basin itself, allowing more players into the Prudhoe Bay arena and the longevity of our basin itself and longevity of TAPS, which has enormous financial benefit to the state and all its citizens. And as the chairman referenced, there might be some residual direct benefit from, from the gas line itself into a holding account and then distributed to the rural areas or our non-railbelt communities to help them with their energy costs. So I think it goes— this project goes much further than just in-state gas because we are going to use just a fraction of the capacity.

And we'll get into that here at some point. But we're basically a non-consequential user of this project.

Thank you, Senator Steadman. And that brings up— and not to be discussed at this point, but at a later point— takeoff points that particularly on the Yukon that affects Senator Cronk's district and his communities which is not part of the discussion that Glenfarn has brought forward. Please continue.

Thank you, Chair. And perhaps coming back for a moment to Senator Steadman's comment there about the broader benefits to Alaska, it is true that, you know, when people talk about stranded gas, generally, you know, one of the first examples that they point to is the North Slope, where, you know, you have this huge gas resource but currently no way to monetize it in the market. And so I, I would say that one of the broader benefits of the LNG project would be to provide that kind of outlet for gas, which could then enable additional oil production and would enhance the economics of oil production, which today doesn't exist. So certainly, as a mechanism for continuing investment and even broadening investment into other basins, the LNG project does have a value in that context. People should be keeping in mind, in the listening audience, that we're talking about 35 1 trillion cubic feet of proven reserves.

That number is probably going to go up substantially as new fields are discovered. Please proceed. Thank you. Good morning, Mr. Chairman. Senator Steadman.

Another quick point here, real quick. We brought that up several years ago in the other project under 138, and that's when the industry will be able to book the reserves on their balance sheet. So it would be nice for us to touch on that sometime as we go through this process, because it's a significant asset booking when they could book that gas. That's a very valid comment, Senator. Thank you.

Thank you, Senator Steadman. Please proceed. Thank you. The last, the last point I wanted to make around the Phase 1 gas supply is as and when the LNG project does come to fruition, then of course the effect you were seeing with the lack of economies of scale in the last two slides is reversed, and the potential for gas delivery to Nstar or Chugach or one of the utilities for less than $5 becomes a reality. So with the additional 3 BCF of gas coming down the line for the LNG, the, the economics of energy supply to Fairbanks and Southcentral is transformed.

So really that's what this slide says.

So I wanted to finish off for the most part talking about the LNG market.

The one, one of the illustrative pieces of material that's been used in the various hearings today has been this so-called break-even matrix from Department of Revenue, which I personally find exceptionally helpful in communicating, you know, where this project sits in in terms of global market. Um, Mr. Stickel has explained this matrix, I think, to you, and, um, what it ultimately means is that if you can push the breakeven price of delivery to Asia to the top left-hand corner of this matrix, then you have an exceptionally competitive project. The, the more you move away from that top left corner whether it's because the capex invested in the project is higher, or whether it's the gas supply price that's higher, you then start eroding the, the competitiveness of the project, and ultimately, of course, you get to the point where you simply cannot deliver gas at a competitive price. So the first thing I did with this chart is to look at the last 10 years and of LNG deliveries into Asia. So I used the Japanese customs data for imported LNG, and from 2016 to 2026, the average was $10.41.

So what I, what I did with this chart was I drew a box around the entries in the box that would result in a delivered price to Asia of less than $10.41. So effectively, this is a kind of a— what I've called a zone of profitability. And you can see the difference between the original— or the existing property tax mechanism and the Governor's Bill proposed a couple of months back with the 6 cents per MMBTU— sorry, per MCF AVT. So what you can see there is that, that zone of profitability is expanded somewhat. So what that means is that the project could sustain a higher increase in capital cost, or it could sustain a higher gas price and still remain competitive against that 10-year price.

So, so that was my kind of starting point. Again, I think it's worth highlighting, you know, the cost of the LNG project in Alaska is indeed very, very high indeed, but the cost of the delivered gas to Asia is not necessarily high, and it's because of the short shipping distance and the relatively low cost of gas that enables you to do that. When we talk about the cost of the project, I think it's useful to make sure that we're comparing apples to apples. Yes, it's— from a capital point of view, it's costly, but from a delivered gas point of view, it need not be. Mr.

Senator Steadman, then Senator Keel.

On this chart here on page— previous page, whatever it is. 2019. What's the capital cost used? Because that's one of the, I guess, indigestion points that we have is the lack of, uh, are using dated, dated capital costs. Could you help us with that?

Then I got a comment. Uh, yes, thank you, Senator, through the chair. This uses the DOR base CAPEX assumption, which is I believe $46 billion, which is inflated from one of the previous capital cost estimates that was put out there, I think in a Wood Mackenzie report a couple of years ago. $35 Billion?

Well, I think $35 billion was certainly around at one time, but I think that's probably wishful thinking these days. So yes, base CAPEX is $46 billion in this example. Senator Steadman. Just for clarity, is that today's value or is that $46 billion as the base 10 years ago extrapolated out with inflation? $46 Billion is today's value.

Yeah, well, okay. So I hope when Glenfarm comes in here and has a discussion, they use a little more accurate numbers because this committee has spent year after year after year dealing with construction projects all across the state and we have massive inflation and cost escalations over the last decade to the point where we've had to put in tens of millions of dollars backfill for OMB— excuse me, not OMB, but our contractors to facilitate the completion of their contracts, even several years ago dealing with asphalt.

So that number is complete garbage. And it makes it very misleading. So we're going to have to deal with that somehow at this table to get a rough idea of what actual costs we're looking at, especially when somebody is going to sit at the end of the table and ask for a concession.

Because if they need a concession, on a $45 billion project, what are they going to ask for when it's $70 billion?

Thank you, Senator Steadman. Through the Chair, I think you've hit there on, you know, perhaps one of the major features that needs to be addressed and developed with the developer. And if I could, I think what we're referring— what I'm referring to here is the base cost. Not inadvertent cost overruns. And we'll— I think at some point we're going to have a discussion over LNG Canada sitting right south of Ketchikan and their significant financial impacts they had on cost overruns to the point where Ottawa had to come in and bail them out.

So, you know, we need to have, you know, as accurate in numbers as absolutely possible. And I think, I don't think we have the numbers here at the table, and I don't think anyone remembers, but the, we need to get the projected cost of the Trans-Alaska Pipeline and the actual cost, which has been, was substantially higher than doubled. From my recollection. But for the committee's reference, that information would be very interesting to have, and we will get that— those numbers for the committee to review. Senator Keele.

Well, thank you, Mr. Chairman. Mr. Fulford, I actually have wanted to ask the ignorant question about when a project goes to FID. You've got the best cost estimates and engineering you can get. Everybody signs.

And unexpected costs do pop up.

As the co-chair Steadman said, with public transportation infrastructure projects, we know where those get covered. Within the LNG industry, pipeline and LNG industry, Where do those get covered? Is it a mixture of going back to gas suppliers and lowering their cost? Is it lowering the pipeline builder's profit over time? Is it raising cost to the customer?

Is it the public fisc? How does that work in the industry?

Thank you, Senator Kyl. It's probably worth through the Chair, it's probably worth dividing projects up into those which are pure LNG export projects and then those which involve some degree of in-state supply or gasification of the host government. But for LNG projects that are kind of intended just for gas export, the cost inflation after FID, which certainly for some of the Australian projects has been a huge issue, it typically gets dealt with in two ways. You know, one is that some of it has to be absorbed by the equity investors, but particularly after some of the, you know, very, very significant cost escalation which we've seen in some LNG projects, These days, some degree of cost guarantee is pushed onto the EPC contractor.

And then of course you're into the question of change orders and changes to the design and so forth. But with a project of this scale, there will be very significant and well-capitalized EPC contractors. Companies building it, but even they wouldn't have the balance sheet to support more than, I would say, a modest cost difference. And indeed, EPC contractors, not surprisingly, do charge for taking price risk. You know, if you let a contract that doesn't have a price cap, the price will be less than one that does, because it's a question of risk and reward.

So on a project of this scale, certainly you'd want to ensure that the equity stakeholders involved have sufficient scope and capacity to absorb some degree of cost escalation.

The key question, of course, which applies in this case is what effect might that have on in-state gas supply? And I think I've heard reference to testimony which suggests that following FID on the gas pipeline element of the project, that the gas tariffs negotiated as part of that package would be unaffected by cost escalation, but I'm not sure that I've seen that set out in writing. Thank you, and I warned you it was an ignorant question. When you say equity investors will absorb, Does that mean write another check, or does that mean we're going to go borrow the difference and you'll get a lower return on the check you already wrote us, or something else? Thank you, Senator Kyl.

That's a good question. It's a combination, and it depends on the sort of financial management decisions of the equity participants, but yes, often additional borrowing would be required.

And, you know, there are— you know, there are some projects that have put considerable strain on the balance sheets of the companies involved because of these cost overruns. If I may, Senator Kyl. Thank you. That's helpful, and it's putting my head in a decent spot. I think you said that was That answer was specific to pure LNG export projects.

What is the historical trend? What tends to happen in projects where there is a local gas supply component as well? Is that— how does that differ? That's another excellent question through the chair.

I mentioned earlier in the in today's meeting that domestic supply is often woven into the very core of the LNG legislation in the host nation. And when that happens, as I say, sometimes the price of domestic gas is fixed, that there's a determination that, let's say, $5 an MMBtu is the price which will enable the domestic market to function and to use gas. And in that case, regardless of where the costs of the project end up, because that number is sort of burnt into, into contract, it stays where it is. I think somebody made the comment earlier that once the LNG project here is, is kind of fully functioning, that the the economic significance of in-state supply is relatively low. And so it's conceivable that, um, I think in the bigger picture, some kind of protection for in-state supply could be worked into the broader framework for the project because there are probably bigger elements that the project developer needs to concern themselves with.

Well, thank you, Mr. Chairman. That would be something you could write in at the beginning. My worry is about cost overruns once FID has happened and where that cash comes from to take care of the in-state supply.

I share Senator Steadman's belief that if we have a gas line, there will be additional oil down taps. I also share an element in my district that there won't be any gas coming here from that. If my district were to get gas, it would come from Canada. It's just geography, right? So I very much want affordable gas into Senator Kaufman's district.

I have several family members who live in his district. That's important to me, but I also have to protect my constituents to whom I'm accountable from calls on the Treasury for gas they won't get. So I'm trying to figure out where the risk points are. I appreciate—. Trust me, we'll take care of it.

Thank you, Mr. Chairman. Senator Kiel, Senator Kaufman, and then Senator Stidman. Thank you, Mr. Fulford. There's— these hearings are often, you know, a cloud of considerations of concerns, all the many things that people think of to wonder and worry about. I'm just curious, given your expertise and the capabilities of Gavney Klein, have you produced or been asked to produce a tabulation that could be what's essentially a decision support package?

So we have to decide what to do. We have to consider as many aspects as possible. And there's cases where we have all the information that we need. There's cases where we may not. There's cases where we might not be able to access that because of some interpretation of confidentiality.

There may need to be some workaround, you know, essentially a SCIF for that or something where we could go in and look at certain things under some sort of agreement. One of the problems I think that the committees that have been chewing on this get into is the cloud of information and not getting it racked into a tabulation that we can move through it, not necessarily linearly, but in parallel, because we're going to get this done. We've got a lot of stuff that we've got to work on. And so we need to know what those are and task that out to the different entities, the stakeholders, or participants in this process that can answer those questions and get things nailed down so that we have a clean agenda of what we need to do legislatively to consider either in this piece of legislation or in subsequent legislation, give it a criticality on a sequence of events to create some forward momentum in this if it's going to have forward momentum. Has such a product ever been asked for or created?

Thank you, Senator Kaufman, and through the chair, as it happens, some of my colleagues are working on a decision support package on another project thousands of miles away.

Our role in that is diligence on behalf of one of the investors leading up to FID. So I think that's exactly the kind of type of package that you're referring to, which is a kind of a soup-to-nuts evaluation of the project from beginning to end.

Our role typically has been to provide the diligence to look at that DSP, decision support package. In this case, it's been prepared by one of the major project developers. And certainly a huge amount of work, you know, has gone into preparing that. So I think maybe at a subsequent meeting, very happy to sort of talk about what typically goes into that, but I think preparing a full decision support package would probably rest with one of the developers. Senator Kaufman?

And I agree. I'm talking about in concept, Now, our task is not to do the project, so we don't have to do all of those things that— or assure all of those things. But there's the piece of that type of process that could be tailored to knock out a, you know, the legislative task that we need to do, the legislative considerations, and could just help us surface some of these things that come up in conversations. You're talking about one thing. The person next to you thinks of another thing.

And it— I think we have to fight back against the information cloud a little bit and get things, again, racked into some sort of tabulation where we can say, okay, we've got this, we've got that figured out, we've got this, we've got this, we need to know this, and how are we going to find out about that? And then we can work on those things. And it doesn't have to be anywhere near as comprehensive as what a major capital project, document might be for that, because our goal is just to come up with the legislative pieces that we really need to do on the timeline that we're in right now. And so I think some simplified version of that would be very helpful.

Thank you, Senator. Perhaps we can develop some ideas and bring them back to committee. Thank you, Senator Kaufman. Senator Steadman? I got a point to make, but just on this last question, I think we've asked well over a year ago if we needed to do anything from the state's perspective, and the answer was no, we don't need to do anything, just stay out of the way and they're going to go build it.

So I think they missed that mark by a mile, and we knew it, a lot of us that have been around, that that's not at all the case, but that's the line of razzle-dazzle they gave us. But to the utility question and the concern dealing with the rail built cost overruns. I think back on another project when we were looking at the construction of the Continental Line heading down towards Chicago area. There was a lot of discussion on how to finance it, and one of the proposals that was brought up and talked about was the utilities are going to back it. And that's what we were told by the administration.

Well, the utilities can't back it. They can't afford to take the cost overrun positions, and they're barred by the regulators to do that. And I think that's one of the questions we need to find out from our regulatory environment. But my expectation is the utilities in rail belt will not be allowed to do that. It would wipe them out, the scale.

And same with the old Continental Line.

They would be barred. But we sat in the governor's conference room and were told point blank that that's how it was gonna be financed. And that was just complete BS. So we need to clarify the state's position on that, Mr. Chairman, but I don't, I'll be shocked if they could back this and expose themselves to cost overruns.

Thank you. Do you have comment, Mr. Folkford, on Senator Steadman's statement?

Thank you, Chair. The— I would say in response to Senator Steadman's remarks that one consideration certainly is that the RCA and the existing regulatory framework that they operate under is probably worth looking at in some detail, in, in the sense that it was probably never really designed for a project at this scale with such wide-ranging economic consequences for the, the South Central area and indeed Fairbanks. So examining the current regulatory framework and considering what it might have to look like to guard against scenarios such as Senator Steadman described is certainly something I think which probably warrants examination.

Thank you, Senator Steadman. Please proceed.

Thank you. So, um, the next 3 slides involve, you know, more pricing data really. So this, this is a graphical representation of what I use to come up with the 10-year average price that I used for the zone of profitability. And you can see that the price of LNG into Japan has been relatively volatile over the last 10 years. There was a relative softening of price, um, really in the lead-up to kind of 2018 when a lot of US LNG was coming onto the market.

Then we saw this big dip around 2020 caused by the industrial demand collapse from COVID and then of course we had the Ukraine crisis, which created a very tight LNG supply environment, mainly because Europe was using up so much LNG, much of which came from the US. Um, I also put the current forward curve on there, which gives you some sense of how much prices have jumped since the, um, uh, military action in the Middle East. But of course, you know, in terms of that forward price, it does stabilize again over the next couple of years.

So that blue or turquoise rectangle represents the zone where, based on the previous slide, the Alaska Profit would have been profitable. In other words, they could have been— they could have delivered gas to Asia, to Japan, and secured a reasonable return on the project. Where the orange line diverges from the blue rectangle, those are areas where the project would be put under some pressure, bearing in mind, of course, that LNG is a long-term business. So in investing in the LNG, you would expect expect to see these periods of firmer or softer pricing. But anyway, graphically speaking, that gives you a sense of where the project is.

The dotted line on there represents the incremental zone of profitable gas deliveries which would arise from the 6-cent per MCF AVT. So you can see that there's a, uh, a movement downwards enabling the project to be more profitable over time. So if we take that still further— oh, well, that's actually—. Do you have a question on that slide, Senator Steadman? Yes, when he's done with this slide, I have a question.

And when you're looking at this slide and the drastic drop from Iran, down.

What estimation are you giving that drop to ending the war, if any? Thank you, Chair. And that's, again, it's a very timely and opportune question because clearly over the last few weeks some information has come out in terms of the extent of the damage that's occurred to the Qatari LNG trains. As you may be aware, Qatar had relatively recently embarked on a very substantial growth program involving quite a number of new LNG trains. I think an additional— I think is at least another 30 million tons of LNG.

Possibly more than that. So, so that whole kind of growth plan has been pushed back a number of years, is my understanding. But I think the, the more fundamental point, and probably the one which is most relevant to Alaska, is not necessarily those sort of short or medium-term disruptions to supply, but the fact that LNG coming through the Gulf is now perceived as being somewhat unreliable, and certainly for an Asian economy that relies very heavily on LNG, and you look at Pakistan and India, for example, Pakistan in particular had a particularly strong reliance on Qatari LNG, so within days of the conflict they were having to shut off industry. They were having to put in place, you know, 3-day-a-week programs and so forth for their power. So right there, there's a real example of the implications of being too reliant on a particular supplier.

So of course, you know, you can compare and contrast that with Alaska— relatively short shipping distance to Asia across the Pacific. No, no real navigational hazards in between. So the events will definitely place more interest and, and activity in Pacific LNG purchases compared to, you know, prior to the conflict. So these are factors which should provide what I'd call fundamental drivers for an Alaska project and people interested in buying gas. Please proceed, Mr. Wolford.

Senator Steadman. Yes, I have a question on this chart. Just for background, there's a decade and a half or maybe back two decades ago, there's the oil cocktail that created the LNG price in Japan. And, and as time moved on, I think the the countries tried to get away from the oil cocktail pricing LNG against the relative price of oil. Can you give us kind of a brief update on where that is?

Have they broken the oil cocktail or is it still the majority of the price indexing used in Asia? Thank you, Senator, through the chair.

The— I talked previously about indexation for the gas supply into the project, and the same, the same factors really apply to indexation for, for LNG buyers.

I think many, many commentators would, would suggest that in due course there'll be some kind of global clearing price for natural gas in the same way that you have, you know, Brent and other oil indexes which occur today. But we're not there yet. So you have this array of different prices which do affect one another.

One of the emerging gas indices in, in, in the Asian theater is JKM, which is— it's called, you know, Japan Korea Marker is, is the full name. It's run by Platts.

But I think, you know, some buyers had begun to move a lot of their LNG purchases towards that kind of index. But the problem with the index is that the trading is still relatively shallow. So every time there's a supply disruption, JKM can go, go up. I think certainly during Ukraine, it was up to $100 a barrel— sorry, $100 an MMBTU, which is equivalent to like, you know, $600 or $700 a barrel of oil. So, so there has been some caution moving away from oil.

What has become quite common, and, and it's, it's going to be an interesting question for the Alaska LNG sales, is moving towards so-called hybrid pricing. So the, the indexation could comprise some oil, it could comprise some Henry Hub, for example, you know, now that U.S. exports have such a fundamental effect on the, on the market. So Henry Hub indexation is, is becoming more common, certainly in Europe. TTF, which is the, it's the Netherlands index, that's become common in LNG. So, so yeah, there is this trend away from just oil, but certainly for Asian LNG buyers, oil still tends to be quite a popular way to To index.

Senator Steadman. No, that's fine. Thank you, Senator Steadman. Please proceed. Okay, you have a brief addies.

Addies.

Call the meeting back to order. We do have prior commitments, so what we're going to do is take a recess until 1:30. If members of the Finance Committee want some time to schedule with Mr. Fulford, I think you could check with Senator Ray Jackson, her staffer is going to be able to schedule time. But we'll recess until 1:30. Do you have any closing comments, Mr. Fulford, before we adjourn until 1:30?

Thank you, Chair. No, I think I'll defer my comments to the recommencement of the meeting. Thank you. This afternoon's 1:30 meeting will probably be less than an hour, but with that, we will recess until 1:30.