Legislature(2025 - 2026)BUTROVICH 205
04/14/2026 09:00 AM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| SB280 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 280 | TELECONFERENCED | |
| += | SB 275 | TELECONFERENCED | |
SENATE RESOURCES
APRIL 14, 2026
9:01 A.M.
INITIAL VERSION DRAFT
FOR
BILLS AND PRESENTATIONS GERMANE TO 2ND SPECIAL
SESSION
MEMBERS PRESENT
Senator Cathy Giessel, Chair
Senator Bill Wielechowski, Vice Chair
Senator Matt Claman
Senator Forrest Dunbar
Senator Scott Kawasaki
Senator Robert Myers
Senator George Rauscher
MEMBERS ABSENT
All members present
COMMITTEE CALENDAR
SENATE BILL NO. 280
"An Act relating to the taxation of certain natural gas pipeline
property; relating to municipal taxation limitations;
establishing an alternative volumetric tax on natural gas
throughput; relating to the allocation of revenue from the
alternative volumetric tax; and providing for an effective
date."
- HEARD & HELD
SENATE BILL NO. 275 "An Act relating to natural gas and natural
gas projects; relating to the Alaska Gasline Development
Corporation; relating to the powers and duties of the
Legislative Budget and Audit Committee; relating to the value of
certain oil and gas; relating to an income tax on certain
natural gas-related entities; relating to the oil and gas
production tax; establishing a surcharge on gas processed in the
state; and providing for an effective date."
- SCHEDULED BUT NOT HEARD
PREVIOUS COMMITTEE ACTION
BILL: SB 280 SHORT TITLE: OIL & GAS PROPERTY TAX; MUNI TAX
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
03/20/26 (S) READ THE FIRST TIME - REFERRALS
03/20/26 (S) RES, FIN
03/23/26 (S) RES WAIVED PUBLIC HEARING NOTICE,RULE
23
03/27/26 (S) RES AT 3:30 PM BUTROVICH 205
03/27/26 (S) Heard & Held
03/27/26 (S) MINUTE(RES)
03/30/26 (S) RES AT 3:30 PM BUTROVICH 205
03/30/26 (S) Heard & Held
03/30/26 (S) MINUTE(RES)
04/13/26 (S) RES AT 3:30 PM BUTROVICH 205
04/13/26 (S) Heard & Held
04/13/26 (S) MINUTE(RES)
04/14/26 (S) RES AT 9:00 AM BUTROVICH 205
WITNESS REGISTER
DAN STICKEL, Chief Economist
Department of Revenue (DOR)
Juneau, Alaska
POSITION STATEMENT: Delivered a presentation on SB 280.
DAVID HERBERT, Commercial Analyst
Tax Division
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Answered questions on SB 280.
MATT KISSINGER, Commercial Director
Alaska Gasline Development Corporation (AGDC)
Anchorage, Alaska
POSITION STATEMENT: Answered questions on SB 280.
RYAN FARNSWORTH, Assistant Attorney General
Department of Law
Anchorage, Alaska
POSITION STATEMENT: Answered questions on SB 280.
ACTION NARRATIVE
9:01:00 AM
CHAIR GIESSEL called the Senate Resources Standing Committee
meeting to order at 9:01 a.m. Present at the call to order were
Senators Myers, Dunbar, Wielechowski, Kawasaki, Claman and Chair
Giessel. Senator Rauscher arrived thereafter.
SB 280-OIL & GAS PROPERTY TAX; MUNI TAX
9:01:46 AM
CHAIR GIESSEL announced the consideration of SENATE BILL NO. 280
"An Act relating to the taxation of certain natural gas pipeline
property; relating to municipal taxation limitations;
establishing an alternative volumetric tax on natural gas
throughput; relating to the allocation of revenue from the
alternative volumetric tax; and providing for an effective
date."
9:02:31 AM
DAN STICKEL, Chief Economist, Department of Revenue (DOR),
Juneau, Alaska, delivered a presentation on SB 280.
Before I jump back into the presentation, I wanted to correct on
the record two things that I did misspeak on yesterday. In
relation to the municipalities that TAPS flows through, the
Trans-Alaska Oil Pipeline, the three primary municipalities
receiving revenue from that are the North Slope Borough, the
Fairbanks North Slope Borough, and then Valdez. There are
smaller TAPS-related impacts to Anchorage, Mat-Su Borough,
Whittier, and Cordova. And then there was a slide where we had
talked about what the state property tax would be for the gas
pipeline under current law versus the proposal in the bill. I
misspoke on that yesterday because I was forgot to reference a
provision of the bill where under the alternative volumetric tax
for a portion of the line located in a municipality, the
municipality receives all of the revenue, whereas under the
current property tax, there's a split between the state and
municipalities. In any case, for 2035 under current law and our
baseline modeling assumptions, the state would receive $239
million of property tax, and under the alternative volumetric
tax, that would be $9 million for a $230 million difference. For
the municipalities, it would be $497 million of current property
tax, and then under the bill, it would be $63.6 million of
alternative volumetric tax.
9:04:22 AM
SENATOR GIESSEL
I also wanted to mention something that was shared yesterday. I
will add that Matt Kessinger has joined online. Yesterday it was
mentioned that the initial gas supply for the pipeline in phase
1 would come from Pantheon Great Bear. I touched base with the
Alaska Oil Gas Conservation Commission, they would have to
approve the off-take of the gas. At this point Great Bear has
not applied for any off-take authorizations. I wanted to put
that out for information.
9:05:11 AM
SENATOR CLAMAN
For some clarity, Mr. Stickel, you just ran out a number of
figures, and when I'm looking at the slides, if you could
actually tell us where the figures you just read off go on the
slides that we have.
9:05:27 AM
MR. STICKEL
The metric tax numbers to the state would be from the insurance.
The current law and proposed law property tax and alternative
volumetric tax numbers to the state would be from slide 30 and
32. Also relating to an earlier slide, which would be slide 18
where we lay out the alternative volumetric tax by municipality
and for the state.
9:06:07 AM
SENATOR CLAMAN
Could you tell us which spaces to put the numbers you gave us. I
don't really necessarily know immediately the figures you read
off where they fit on these pieces that we're looking at.
9:06:25 AM
MR. STICKEL
I would be looking at slide 18, and then this shows the revenues
that the state would receive from the alternative volumetric
tax. Some of the questions from the committee were, if the
project were to go forward under current law, what would the
expected property tax value be. Looking at 2035, for North Slope
Borough, the expected property tax would be $288 million. For
Fairbanks North Star Borough, it would be $0.4 million. For
Denali Borough, it would be $0. For Mat-Su Borough, it would be
$30.5 million. For Kenai, it would be $178 million. For a total
to the municipalities of $497 million, and then for the state,
it would be $239 million, for a total property tax of $736
million under current law.
9:07:29 AM
SENATOR CLAMAN
This is all in the FY35 column.
MR. STICKEL
These would be annual revenue. That is correct. Under the
current law with our base line capital assumptions there will be
about a $736 million dollars per year property tax burden from
the project and that would be reduced to about $74 million
dollars under this bill.
9:08:03 AM
SENATOR KAWASAKI
This may be a request to help so that it would be easier to
clarify if we could get something of an estimated impact graph
that would state what it would be had it not changed. So, you
know, just all those numbers that you read off in 2035 would be
put into a graph and then, I mean, I don't know how you would
estimate, but, you know, make some sort of a judgment call on
how to estimate what that approximate would be so that we kind
of figure out like lost revenue to municipalities.
9:08:38 AM
MR. STICKEL
I'm seeing that it maybe helpful to provide something similar to
slide 18 under current law. We will provide that.
9:08:53 AM
SENATOR CLAMAN
I take it you'll be doing that not just for FY 2035 under
current law, but the whole range of columns.
MR. STICKEL
What we'll do is provide this slide under what it looks like
under current law. That would answer a lot of these questions.
9:09:27 AM
MR. STICKEL moved to slide 29, Analysis Summary; Current Tax Law
This slide summarized the key outputs of our modeling under
current law and our baseline assumptions. This would be if the
project went forward under current law. We saw what the revenues
were to the various stakeholders. As a reminder, the top set of
numbers here are cash flows. For the upstream and midstream,
these represent gross revenues before any costs. Highlighting
the break-even costs of supply numbers here, which is $4.86 in
2033 for in-state and then $9.07 for LNG exported. Those become
important numbers as we compare to different scenarios and
different market conditions.
9:10:38 AM
CHAIR GIESSEL
For clarification, gas commodity charge, is that the price at
the wellhead.
MR. STICKEL
Yes.
9:10:53 AM
MR. STICKEL moved to slide 30, State Revenues by Year; Current
Law.
Slide 30 shows a chart of annual state revenues under the
current law analysis. This would be if the project went forward
under current law without property tax relief. We're looking at
a little over $200 million per year of property tax, around $600
million per year if you include royalties and corporate tax, and
then about a billion dollars per year total. These are revenues
just to the state once we add in the production tax impacts.
9:11:30 AM
CHAIR GIESSEL
At year 2033, that peak, and then it plateaus, this must be
after the export facility is fully functional.
MR. STICKEL
That is correct.
9:11:51 AM
SENATOR DUNBAR
Could you explain the TBTU per year 1150. How does that compare
to the 3.5 billion is usually the number we see for when the LNG
is fully being exported. This is a different measurement. How is
that, are you assuming that same amount being exported.
9:12:19 AM
MR. STICKEL
The left axis is the revenues, and then the right axis is the
volumes. This one's been labeled in trillions of BTUs per year,
which a BTU and a thousand cubic feet have a rough equivalency,
but that top threshold is equivalent to the 3.5 billion cubic
feet per day of full capacity of the project.
9:13:00 AM
MR. STICKEL moved to slide 31, Analysis Summary; Proposed
Legislation.
Slide 31 summarizes some of the key outputs of the modeling
under the proposed legislation and with the baseline
assumptions. Everything the same as slide 29, except we
implement SB 280 and the alternative volumetric tax. Under this
analysis through 2062, there's $22.5 billion of state revenues,
which is $7.2 billion less than current law. There's $4 billion
of municipal revenues, which is $13.3 billion less. There's $60
billion to the upstream producers, that is the same as the prior
analysis. And then there's $68.5 billion to the midstream in
revenue, which is $1.5 billion less than under current law. Why
is that less is because the project, the cost to operate the
project is less with the lower property tax burden, and we are
assuming a 10 percent return to the midstream owner. They're
making a 10 percent return on a lower base when we provide the
property tax relief. In terms of cost of supply, under our
baseline, we get a $4.43 break-even price for the in-state cost
of supply, which is 43 cents per thousand cubic feet reduction
to in-state, and then $8.48 per thousand cubic feet, which is a
59-cent per thousand cubic feet reduction to the price that
would allow the project to break even in the market for
delivered LNG.
9:14:52 AM
SENATOR MYERS
I'm looking at your cost of supply summaries. The in-state
versus the LNG, the gas commodity charge, gas treatment plant
toll, and pipeline toll are slightly higher on the LNG portion.
Why is that.
9:15:12 AM
MR. STICKEL
The gas commodity charge for LNG includes some additional
treatment costs.
9:15:28 AM
SENATOR MYERS
We just clarified that's at the wellhead and so treatment would
come later, but then you've got your gas treatment plant toll,
and that's, if all the gas is run through the same treatment
plant, it should be the same. The producers don't care if it's
getting sold in Anchorage or if it's getting sold in Japan.
They're going to charge the same price. The gas treatment plant,
it's the same plant. It's all going to get charged the same.
It's the same pipeline. That's all going to get charged the
same. The LNG plant and the ship and the overseas shipping, of
course, that's different, but we're talking about the same gas
running through the same infrastructure, so why is it different.
9:16:06 AM
MR. STICKEL
I was hoping I had Mr. Herbert, my commercial analyst on the
line. I'll follow up with that. I know we have an answer and he
could answer it off the top of his head, but I'll get that for
you guys.
9:16:31 AM
CHAIR GIESSEL
You've pointed out the change in revenue for each of these. How
much will this save the consumer and have you calculated down to
that level.
9:16:46 AM
MR. STICKEL
We've done some initial analysis looking at after contracts
expire for ENSTAR in particular in 2033, what are the options
that exist there and how does the AKLG project compare to
imported gas being the primary concerns there. We looked at a
2023 study by BRG that was done for ENSTAR, and that had a cost
of imported gas. We inflated that price up to 2033 dollars and
it came out to about $17 per thousand cubic feet for imported
gas into the market. Our baseline here for in-state gas would be
$4.43 per thousand cubic feet. That would be a savings of about
$12.50 per thousand cubic feet. Looking at ENSTAR customers as a
total, which consume about 34 billion cubic feet per year, that
would be about a $358 million annual savings or about $10.7
billion over a 30-year time horizon. We looked at ENSTAR in
particular because they have some readily available information
around number of customers and exactly what their prices are. If
we extrapolated that from the 34 billion cubic feet that ENSTAR
is using to a larger number, such as the 65 to 70 billion cubic
feet that are consumed in the inlet or potentially a larger
number if there's, you know, incentive, if new demand is
incentivized, things like if there is a Fairbanks spur line,
some sort of an industrial base load consumer could be data
center, agrium, sales to mines, then the savings could be
significantly higher than those ENSTAR-only numbers.
9:19:09 AM
SENATOR WIELECHOWSKI
On that question of the savings to consumers, it's 43 cents per
MCF is what the savings is for the property tax cuts, correct.
9:19:28 AM
MR. STICKEL
43 cents per thousand cubic feet is the comparison of the
delivered price to utilities under, if you assume the project
goes forward under current law versus under this bill.
9:19:50 AM
SENATOR WIELECHOWSKI
To do a comparison on how much the people of Alaska would be
giving up, the state property taxes are reduced by $230 million,
which divide that by 600,000 Alaskans comes out to $383 per
person. The muni cut is $434 million, which is probably $700,
$800 per person, but the munis are separate. I guess the point
that is curious to me is that the amount of, I checked with
ENSTAR, the amount of natural gas that the average Anchorage
residential customer uses is 139 MCF per year. When you multiply
that by 43 cents, you get $58.38, which means that the average
household in Anchorage with that 43-cent savings is saving
$58.38, but they're giving up $239 million in state property
taxes, which is the equivalent of $383 per person. A household
of four is giving up almost $1,500 to get its potential PFDs or
potential state services in exchange for $58.38 of savings. Does
that sound about right.
9:21:26 AM
MR. STICKEL
9:21:56 AM
SENATOR WIELECHOWSKI
9:22:28 AM
SENATOR MYERS
The question is what is the alternative. If your view is that
this project will not go forward under current law, then the
comparison would be, what is the alternative source of gas, you
know, by imports, which is what I quoted. If your view is that
this project will go forward under current law, then the numbers
you cited would be more accurate.
9:23:00 AM
SENATOR MYERS
I was looking at the cost of supply charts that Mr. Stickle had
on both slides 29 and 31. I believe they're the same on these
three pieces. The LNG break-even price versus the in-state
break-even price, the gas commodity charge, the gas treatment
plant toll, and the pipeline toll are all slightly higher for
the LNG price. And I'm just curious as to why, since it's the
same gas and the same infrastructure.
9:23:42 AM
DAVID HERBERT, Commercial Analyst, Tax Division, Department of
Revenue (DOR), Anchorage, Alaska, answered questions on SB 280.
Something we try and highlight in these is that these cost of
supply are based off of the price to the end consumer, be it the
utilities or LNG customers. And as a result, the total cents
here are based off of the output volumes. For the LNG, there's
additional fuel that needs to be transported down the gas line
process in order to run the liquefaction plant, and that adds
the cost there across the board.
9:24:33 AM
SENATOR MYERS
To clarify, so effectively what I'm hearing is because of the
extra volume needed, I'm assuming that means we're going to need
to run pipelines out to Point Thomson or a couple of the other
North Star Endicott to get the gas. You're factoring that, the
cost of that extra infrastructure being built into those extra
costs going up a little bit.
9:25:02 AM
MR. HERBERT
In this case, those costs are already baked into both of these
things, but in order to run the liquefaction plant itself, a
certain amount of additional gas needs to be transported just
for that. Instead of letting the cost associated with that gas
get incorporated into both sides of it, they're only shown on
the LNG, so the in-state customers aren't subsidizing that.
9:25:37 AM
SENATOR MYERS
It's the cost of the LNG. It's the extra gas that is necessary
in order to run the LNG plant and that's just back added into
the other pieces.
9:26:00 AM
MR. STICKEL moved to slide 32, State Revenues by Year; Proposed
Legislation.
Slide 32 is our same annual revenue chart under the proposed
analysis. Looks very similar to the current law slide, except
it's about $230 million per year lower across the board due to
removing that property tax and replacing it with the alternative
volumetric tax. State revenue from the AKLNG project with this
bill passed is looking at about $800 million per year total.
9:26:37 AM
SENATOR DUNBAR
Two things. First, just to reiterate what I said yesterday, one
of my primary goals in this bill, if I'm going to support it, is
to prevent that happening in 2028 through 2032 where our
revenues go negative. If we're going to produce that much
revenue in the future, there's no reason to have any period
where we can't put those costs out into the future. So that's
one. The second is, I think if you were a layperson looking at
this graph, it looks like the total government revenue here,
approaches is quite close to the line in the previous graph on
30. It's actually over the line at the time. You might interpret
that as saying the government is taking the vast majority of the
revenues, if that is indeed the revenues. If you look at the
prior slide and you've got the upstream owners and the midstream
owners and all of them together, that adds up to 177.5 billion
approximately. About 72.5 percent of it is taken by the owners
and 28.5 percent is taken by the government. The government,
less than 30 percent of the total revenue is captured by the
government, which is probably fair. The vast majority of the
revenue goes to the producers and the midstream owners. I guess
one of my questions is, why doesn't this graph reflect that. Why
isn't the gap between the lines and the revenue equal to 70
percent of the revenues produced. Does that make sense. If you
look at the prior slide, 72.5 percent of all revenue related to
this project is captured by the upstream owners and the
midstream owners. Good. But this graph makes it look like it's a
much tighter gap between the revenues produced and the state and
all government revenue. What am I missing there.
9:28:53 AM
MR. STICKEL
This chart shows two things. This shows total gas sales on the
right axis and the dotted line, and then total state revenues
only in the stacked bar charts. This chart is only looking at
that state revenue number and how that breaks out into the
different components. We could certainly prepare a chart that
shows all the revenues to the different entities, and that would
demonstrate that the revenue to the state is a fraction of the
total revenue generated by the project.
9:29:33 AM
SENATOR DUNBAR
I don't understand what the dotted line was. I thought the
dotted line was trying to illustrate the total revenue generated
by the project. Why does the dotted line exist if that's not
what it's showing.
9:29:46 AM
MR. STICKEL
What the dotted line represents is gas sales from the project.
The reason we included that is we wanted to show the start of
the project where there are no gas sales. We wanted to show what
the impact on state revenue is for the first couple of years
when there's only in-state gas sales. Then we wanted to show the
ramp up period where the full export project is coming online.
Then to show that the significant state revenues really do start
in 2033 when the project is fully operational.
9:30:23 AM
SENATOR DUNBAR
I don't think this is intentional by the Department of Revenue,
but that is a wildly misleading graph because people look at it
and they associate the dotted line with the revenue on the y-
axis on the left. What you're saying is, no, the dotted line
only applies to on the right. You see what I mean. Why not just
make a dotted line that tracks with the revenues, which would
also track with the gas sales, but they'd show a vastly
different. They would show this line would go way three times
off the graph to show all the profits being made, or all the
revenue being generated, perhaps not profits. Does that make
sense.
9:31:10 AM
MR. STICKEL
I understand the alternative slide that you're discussing. We'd
be happy to provide a version of that.
SENATOR DUNBAR
Please don't put this slide into the public like this, because
again, I think unless there's some way to be very clear, because
it even says LNG and gas sales, which implies that there's some
dollar figure on the bottom there with the dotted line. A
person's going to look at this and say, man, the government is
taking the vast majority of the revenue being generated here. If
they look at the thing on slide 30, they'll come to the
conclusion that the government revenue exceeds the total revenue
for a portion. No wonder they need this giant tax break. That's
not at all what this is showing. I don't think it was
intentional. I hope we can change this before it goes out for
broader public consumption, Madam Chair.
9:32:05 AM
MR. STICKEL
Absolutely not intentional. I see that we can improve our
labeling on this slide if we're going to include that dotted
line, and we'll take a look at that.
9:32:18 AM
SENATOR MYERS
On 29 and 31, when we had the dollar figures for the upstream
motors and the midstream motors, I believe you said that that
was not profit, that was strictly cash flow. If we, once we
subtract it out the upstream and midstream costs, then those,
the actual profit would be significantly smaller than that. Is
that accurate.
9:32:44 AM
MR. STICKEL
That's accurate.
9:32:54 AM
SENATOR CLAMAN
Let's start at slide 32. Under this proposal, we often talk
about how the gas line is going to bring enormous revenue to the
state, and particularly at least when we sit in the legislature,
we think, is this going to be a big increase in revenue to state
government. I'm looking at slide 32. Never in a single year do
the revenues to the state exceed a billion dollars. I'm not
minimizing that a billion dollars is no small amount of money to
the state, but I think about how much we're drawing annually on
the POMV draw from the earnings reserve to fund state
government, which is over $3 billion and has been for the last
few years. I look at this, which shows less than a billion
dollars coming to the state in the best years. If this project
has potential revenue to the state, is there some other means
the state can achieve great revenue from this particular project
because it doesn't look like it's coming from royalties and
production taxes. Not to understate that we don't need the
revenue, but this doesn't look like a game changer. Where is the
big revenue to the state in the project.
9:34:23 AM
MR. STICKEL
I would suggest that $800 million dollars a year is a
significant increase to state revenue.
SENATOR CLAMAN
I agree it's a significant increase but it doesn't really change
the picture dramatically because $800 million is about 25
percent of the POMV draw from the earnings reserve.
9:34:47 AM
MR. STICKEL
I was going to add, gas is a lower value commodity than oil.
That is a truth. And so when you're looking at a gas, there is a
lesser amount of profit overall with gas than oil, and that's
something to keep in mind.
9:34:54 AM
SENATOR RAUSCHER joined the meeting.
9:35:08 AM
CHAIR GIESSEL
That's a really important point that we often forget, because we
are used to dealing with oil. I'll just interject that. But the
other point you make, Senator Claman, because you're referring
to the percent of market value that is available for general
fund use, and we are proposing actually reducing the percent of
market value percent from 5 percent down to 4.5 percent
progressively over a five-year period, which if you apply that
to this graph, it will hit at about 2032, 2033. I don't have the
bill in front of me that's being considered, but we need to take
that into consideration also, though this is not our only source
of revenue.
9:35:55 AM
SENATOR CLAMAN
The question I'm raising is, if there is this potentially more
significant win for the state than just what's on these graphs,
where is that. Is that somehow that we have ownership interest
or greater ownership interest in pieces of the pipeline that
will bring us revenue separate from royalties and production
taxes.
9:36:23 AM
MR. STICKEL
That's certainly an option that the legislature could consider
to have an ownership interest, you know, broader economic
impacts, economic development in the state. And then what we
haven't really looked at is the impact on exploration and
development above and beyond what's in the revenue forecast. I
spoke to that a little bit yesterday in some of the slides, but
this idea that when you have a sales mechanism for gas, that it
makes exploration and development more attractive generally on
the slope.
9:37:11 AM
SENATOR WIELECHOWSKI
Do you have any idea what the costs are to the upstream owners
to produce $1.50 worth of gas are. Right now, my understanding
is they're injecting like 8 billion cubic feet a day, they're
just reinjecting it. I would imagine the costs to the producers
are pennies, extremely low. Does that sound, is that probably
about right.
9:37:38 AM
MR. STICKEL
We do have assumptions around what the incremental cost of the
gas and associated new oil will be. Those are baked into the
model. I don't have those at my fingertips, but we do have
assumptions that we've developed with AGDC.
9:37:55 AM
SENATOR WIELECHOWSKI
Profits for industry, I guess. If you have a $1.50 gas, which is
what you're estimating, the state's share is $1.50 times, we get
a 12.5 percent royalty, we get a 13 percent gross tax, that's
25.5 percent. That comes out to $38.25. Corporate income tax is
a little bit, not as much as it could be, but the property taxes
are very little. It's maybe $0.40, I'm guessing. The producers,
on the other hand, are getting it costs virtually nothing for
them. They're just producing it and reinjecting it right now.
They're probably making a dollar in MCF. Does that sound about
right.
9:38:56 AM
MR. STICKEL
I would have to look at our assumptions to validate that exact
number.
9:39:04 AM
SENATOR WIELECHOWSKI
Can you provide us with that data.
MR. STICKEL
Yes. We'd be happy to do that. As I mentioned we do have
assumptions baked into the modeling for incremental cost at
Prudhoe Bay and Point Thomson.
9:39:22 AM
CHAIR GIESSEL
The other thing to consider here is what I shared at the outset.
The idea that Pantheon is going to be the initial source of gas
is a questionable assumption, since they haven't applied for gas
off-take yet. Not thinking that there doesn't have to be gas
treatment costs at the very beginning is a flawed assumption, in
my opinion.
9:39:57 AM
SENATOR RAUSCHER
This regards to the question by Senator Wielechowski. When they
reinject air, they have different reasons for it to bring up
more oil.
In regards to the question by Senator Wielekowski. When they re-
inject and inject, they have different reasons for it, to bring
up more oil. Sometimes they have too much gas that comes up
because of the oil that they're taking out of the ground. This
is not a complete search for gas. This is something that
happened along the way, which may be too much for them to re-
inject just to bring up new oil or whatever, but when you're
looking at actually providing the gas that we're providing here
and liquefying and getting it in the pipeline, I think that the
costs go up considerably other than why they're re-injecting
what you're talking about there and the cost that it seems like
would be almost nil. These are two different types of gas
supplies that we're trying to come up with and volume that we're
needing. That's just my opinion from working up there.
9:40:59 AM
SENATOR MYERS
To go back to Senator Claman's question about the benefit to the
state. We're talking about dollar benefit in terms of direct
royalties and taxes, but I mean, the other benefit to the state
would be lower energy costs for residents, hopefully fewer
people leave the state because it gets more affordable to live
here. Maybe some businesses become more profitable. We start
some businesses. You mentioned Agrium potentially restarting up
if they've got a decent, a reliable supply again. Something gets
thrown on the property tax rolls with Kenai. If other businesses
can get started, those increase the property tax rolls locally
for a lot of places. At Department of Revenue, do you have any
modeling that can estimate those types of benefits, even though
they aren't necessarily direct benefits to the state treasury
because, we don't have a broad-based tax. Can you model some of
those other benefits to municipalities or to the population in
general.
9:42:00 AM
MR. STICKEL
That's something we've been looking at, how we can model those
broader economic benefits. I'm not sure that's quite ready for
prime time, but qualitatively, we can certainly speak to some of
what we're looking at. It's things like light data centers, like
a restart of an Agrium plant, like a line out to support mining
operations like the Donlin mine, like the Fairbanks spur line.
And certainly those have economic impacts that go beyond just
the direct revenues.
9:42:40 AM
CHAIR GIESSEL
I appreciate what you spoke about in terms of opening and
restarting businesses and that resulting, of course, in property
tax and so forth. Remember under 4356-022, all municipal
property taxes, ad valorem sales tax, municipal gross and net
income, license fees, excise, municipal charges, et cetera,
related to consumption, whatever, are all prohibited during
construction, which is the most impactful time. You see the line
there, it actually, the line starts way over in 2022. We're
actually in 2026 already. But those, that prohibition on any
municipal taxes of any kind continues until they reach a billion
cubic feet, which this optimistically is projecting in 2033.
That's a pretty optimistic projection. It could be a while
before that idea of additional municipal income would come to
fruition. Just some practical considerations.
9:43:54 AM
SENATOR MYERS
I understand that we may need to clarify that because I think
that the point of the bill here is to say we don't want to tax
them while they're in the middle of construction, but again,
there will be some spillover effects, and we do want the
municipalities and the like to be able to capture those. I'm all
in favor of clarifying that. To say, I don't think it's quite
accurate to say, because that's what the language is in the bill
right now, that for example, the Kenai, I wouldn't be able to
tax the Agrium plant just because they're using the gas because
that doesn't have anything to do with the construction. I
understand we may need to clarify that, but just thinking about
where the benefits go.
9:44:39 AM
SENATOR WIELECHOWSKI
On the pipeline, can you go back a slide to 31. OK, so I'm
struck by the number, the disparity in cumulative to 2062. You
got $22 billion to the state, $22 billion to the feds, $3
billion to the uni, $60 billion to upstream, $68 billion to
midstream. And I'm trying to figure out what's the share is. We
talk about a third, a third for the state, feds, upstream. In
this case, we got midstream. What profit do you estimate the
midstream owners are getting from that $68 billion.
9:45:24 AM
MR. STICKEL
Our model assumes a 10 percent rate of return for midstream.
9:45:34 AM
SENATOR WIELECHOWSKI
That would be $6.8 billion dollars.
9:45:40 AM
MR. STICKEL
Roughly.
9:45:46 AM
SENATOR WIELECHOWSKI
On the upstream do you have any sense on what kind of profit
they are looking at.
MR. STICKEL
I don't have that number at the top of my head.
9:46:02 AM
SENATOR WIELECHOWSKI
I'm curious about those federal numbers. Why is there a negative
federal number from [2042].
MR. STICKEL
The federal revenues represent two things, one is a federal
corporate income tax which would be we would assume a slight
offset to federal corporate income taxes during the build out
phase, when there is money being laid out. Also, we're assuming
enefits from the 45 Q credits, which are credits for carbon
capture which apply to the gas treatment plant. Those are the
The federal revenues represent two things. One is a federal
corporate income tax, which would be, we would assume, a slight
offset to federal corporate income taxes during the build-out
phase when there's money being laid out. Also, we're assuming
benefits from the 45Q credits, which are credits for carbon
capture which would apply to the gas treatment plant. Those are
a positive benefit to the project, but an outlay from the
federal government during the initial years of the project.
9:46:54 AM
SENATOR WIELECHOWSKI
So those 45Q credits, I assume, those go to the upstream owners
or the midstream owners. What's your expectation on that and are
you reflecting the shift to those owners in this slide.
MR. STICKEL
We assume that those 45Q credits are realized by the midstream
owner at the gas treatment plant, and that is baked into our
modeling, yes.
9:47:25 AM
SENATOR WIELECHOWSKI
Explain how you're valuing that. That's, so you've got a ton of
carbon, maybe explain more, and explain how that's reflected in
here, and how many tons you're estimating.
9:47:47 AM
MR. STICKEL
I'll see what I have at my fingertips. I may have to defer this
one to my lifeline.
9:48:09 AM
MR. HERBERT
We right now are estimating 7.5 million tons of CO2 removed at
the GTP plant per year once everything is at full operations and
that is sequestered earning a credit per ton of, according to
the current 45Q law, which is $85 per ton today, but increases
with inflation over time. So by the time the project is running
at full capacity, we're talking about $100 per ton of CO2
sequestered, which combining those two numbers together for the
first 12 years of the project, which is the length of those 45Q
credits we're talking about, approximately $750 to $900 million
over that time frame as credits that are either cashable or
immediately transferable from the federal government to the
project.
9:50:03 AM
SENATOR WIELECHOWSKI
where are you anticipating that the carbon will be stored. Is
there a well that's been approved. I know we had approved giving
the department that authority to go forward on getting EPA
authority to start this process. Have you done that and where
are we at in that process.
9:50:28 AM
MR. STICKEL
That would be a good question for Matt Kissinger with the AGDC.
9:50:43 AM
MATT KISSINGER, Commercial Director, Alaska Gasline Development
Corporation (AGDC), Anchorage, Alaska, answered questions on SB
280.
There are two ways to sequester your CO2 under the 45Q credits.
There is the permanent geological sequestration, and then
there's use for EOR. As this project has developed, the base
case assumption has always been that the CO2 would be returned
to Prudhoe Bay. In fact, it's a distal part of the reservoir,
which is the target area for it to go into. By putting it into
Prudhoe Bay, you're just by default taking the EOR credits
rather than the permanent geological storage credits. The
enhanced oil recovery mechanism is the pressure itself from
putting those molecules back into the reservoir, and then, you
know, there's also the potential that the CO2 would be so
miscible and be able to withdraw more oil just to do it even in
the reservoir.
9:51:48 AM
SENATOR DUNBAR
If we go forward one slide, and you must have mentioned this,
but I must have missed it. What's going on in 2038 here again.
There are two different shades of blue here, I think that's the
property tax and ABT, but it might be the production tax. It
just disappears for a year and then it comes back. Could you
explain that again.
9:52:10 AM
MR. STICKEL
We are assuming that for Point Thomson in particular, that
there's two major capital outlays associated with expanding that
field, one that occurs prior to full exports and another in
2038. That represents an expected reduction to production tax in
that one year when we're expecting a major outlay of funds at
Point Thomson.
9:52:39 AM
SENATOR DUNBAR
Just remind me, that production tax is for both oil and gas, or
just production taxes on the gas.
9:52:47 AM
MR. STICKEL
This is total production tax. The production tax due to the
state is paid on a statewide basis, so we combine the oil and
the gas from the producers.
9:53:04 AM
SENATOR DUNBAR
If this all goes forward, I think the legislature in 2036 is
going to have a pretty detailed discussion about that.
9:53:15 AM
MR. STICKEL
These are incremental production tax revenues above and beyond
our spring revenue forecast. And so in 2038, we would still be
expecting additional revenue above and beyond the existing
forecast, just not hundreds of millions of dollars like we are
in other years.
9:53:36 AM
SENATOR CLAMAN
Senator Wielechowski was asking some questions about, actually
took a question from Mr. Kissinger asking about the CO2 stuff,
but I think he also asked the status of an EPA application to
get permitted, and I'd never heard an answer to that.
9:54:03 AM
MR. KISSINGER
The Class 6 wells, as I mentioned, there are two ways you can
earn the credit through the permanent geological storage or
through the VLR. If the Class 6 wells are needed for the
permanent geological storage. These were, this gas is used as
ULR and the reservoir would just be sent through the approved
system into either existing injector wells or new injector
wells. Those wells would not need to be Class 6 wells as far as
I understand. It would be more than a year.
9:54:43 AM
CHAIR GIESSEL
My understanding is AOCC has achieved authorization for Class 6
well, but let me confirm that. It's been a couple of months
since I last spoke to them, and I do have another inquiry out to
them related to Great Bear. So I'll ask that question in the
next day or so.
9:55:03 AM
SENATOR WIELECHOWSKI
Going back to Senator Dunbar's question on lease expenditures.
Can you get us a chart that had the lease expenditures, could
you get us a chart that had the amount of lease expenditure, the
cost of lease expenditure deductions to the state per year from
this project.
9:55:18 AM
MR. STICKEL
I will provide our assumptions around incremental lease
expenditures associated with the project.
9:55:30 AM
SENATOR WIELECHOWSKI
Yes, the lease expenditures, but also the loss in revenue to the
state from those lease expenditures.
MR. STICKEL
We will include the increase or decrease in revenue associated
with these expenditures.
9:55:57 AM
MR. STICKEL moved to slide 33, Sensitivity Matrix; In-State Gas
Break-Even Price, Nominal $/Mcf in 2033
This gets at some of the questions around uncertainties of
assumptions around the AK LNG project. Two of the biggest
assumptions that we've identified have uncertainty around them
are what the gas price will be that the producers receive and
how much the project will actually cost. There was some
discussion yesterday of potentially some different numbers
running around. Within Department of Revenue, we don't have
final or confidential numbers on those two items, we prepare
some extensive sensitivity analysis. We show on the top, what
we're showing here is the break-even price for the cost of
supply that we've shown on previous slides. On this chart, we're
showing that in-state cost of supply, and we are varying the gas
purchase price on the x-axis, which is how much do the producers
receive for selling the gas into the project. Then we are
varying the capital cost for the project. We start with our $46
billion capital cost assumption as our base capex, and we run
increments of that up to a 100 percent cost overrun. You can
look at what is the impact if there is a capital expenditure
that's 20 or 40 percent higher than the baseline costs. Our
baseline assumptions are the $1.50 per thousand cubic feet for
the purchase price, and then the $46 billion project cost. In
the baseline, this bill would reduce that in-state break-even
price from $4.86 per thousand cubic feet down to $4.43 per
thousand cubic feet. But then you can see the significant range
of outcomes that are potential there and the risk to the
developer for the higher capital cost in particular.
9:58:12 AM
SENATOR DUNBAR
Just so we can put this in context, this break-even price, what
is the sort of, what is the international price that they'd be
competing with right now.
9:58:27 AM
MR. STICKEL
This looks at the in-state price. This would be the price to in-
state utilities. I do have another, the next chart actually
looks at the international LNG prices.
SENATOR DUNBAR
The second one says Alaska LNG, but its still in-state even
though the in-state users are not using the LNG.
MR. STICKEL
Right, we are showing the capital cost for the entire project
and then what is the delivered gas to in-state utilities.
SENATOR DUNBAR
Right, because it's all one project.
MR. STICKEL
The next slide will show a similar chart looking at LNG sales
into global market.
9:59:18 AM
CHAIR GIESSEL
One of the concerns that we have is the phase one and it
existing as an isolated occurrence. For the first few years, I
think on your previous slide, 32 and 30, the first few years
when it's in-state only, there's quite a loss. What is the price
of, what is the break-even price there. What are Alaskans going
to look at paying.
9:59:50 AM
MR. STICKEL
I have some numbers based on a fall 2025 version of the
analysis. We haven't fully completed the most updated spring
version of the analysis, but the numbers should be fairly
comparable. If the project were to build the pipeline phase one
only and not proceed to the full project, we estimated a break-
even gas delivered to utilities price of about $12.52 per
thousand cubic feet.
10:00:26 AM
SENATOR WIELECHOWSKI
Just so I understand this, so the base, looking at the top one
here, the base CapEx at $1.5446, that, is that the delivered
price to the consumer in South Central, or are you assuming
other charges on top of that.
MR. STICKEL
The prices here represent the delivered price to utilities. This
would be the cost that a utility such as NSTAR would be
purchasing the gas for, and then the consumers would be paying a
higher price that would represent the transportation cost that
NSTAR has.
10:01:14 AM
SENATOR WIELECHOWSKI
Do you have a rough estimate of what that number would reflect
from 486 to 586, 686.
MR. STICKEL
Not off the top of my head.
10:01:33 AM
SENATOR WIELECHOWSKI
If you could get that. I'm just curious, are you assuming that
cost overruns are going to be passed on to the consumers. Is
that what this assumption is making.
MR. STICKEL
Yes. The way this looks is we assume that the midstream operator
will earn a 10 percent rate of return, and then we look at what
is the price that would be required to allow them that 10
percent rate of return on different levels of capital costs.
That's how we've done the modeling approach. What would happen
in reality is the midstream operator would have a price that
they would pay to the upstream, they would have a price that
they would sell the gas for, they would have a cost of the
project, and they would bear a lot of that risk at the
midstream.
10:02:42 AM
SENATOR WIELECHOWSKI
That was my understanding of the testimony, was that the cost
overruns would not be passed to the consumers. I'm not sure what
to make with this chart. Are you saying that if there's a 20
percent cost overrun, it won't be 543 if it's $1.50 gas. It'll
be something different.
MR. STICKEL
What we're showing here is, given if you assume a 20 percent
cost overrun, for instance, and if you assume the $1.50 purchase
price, for instance, then a $5.43 per thousand cubic feet would
be required. That would be the price that the midstream operator
would have to sell the gas for to get that 10 percent return.
Now, they could sell it for a lower price and get less than a 10
percent return. Then under the bill before you, that break-even
in that scenario would go from $5.43 down to $4.92. It would
make a lower required price for them to earn that rate of
return.
10:03:52 AM
SENATOR WIELECHOWSKI
To be clear, you heard the same testimony I did, that cost
overruns will not be passed onto consumers, correct.
MR. STICKEL
Correct.
10:04:05 AM
SENATOR DUNBAR
What volume of consumption are you assuming here from in-state.
MR. STICKEL
I need to defer the question. Mr. Herbert has the answer at his
fingertips.
10:04:33 AM
MR. HERBERT
I have a revenue in the version of the model you have that's
being presented in front of you, we have an in-state sales
demand of approximately 67 BCF per year, but growing over time.
10:05:12 AM
SENATOR DUNBAR
67 BCF per year, you're not saying the whole project could
survive selling 67 BCF per year at this price, right. This chart
cannot exist without the chart on the following slide where they
are selling the full 3.5 BCF per day. Is that correct.
10:05:37 AM
MR. STICKEL
Yes, that's correct. So these represent the in-state delivered
sales assuming the full project goes forward. Then again, if we
assume, if the full project didn't go forward and it was just
the phase one, yes, the in-state prices would be significantly
higher.
10:05:59 AM
SENATOR DUNBAR
My follow-up question will be on the next slide. The point is
sort of, this is an interesting slide because this slide cannot
exist, and none of this will happen unless what happens on the
next slide goes forward, which is they are competitively selling
a much, much larger volume of gas into the international market.
That's my question about what price are they competing with goes
to the next slide, but it's tied to this slide in the sense that
if they can't compete on the next slide, this slide doesn't
exist. This doesn't happen.
10:06:39 AM
SENATOR RAUSCHER
Assuming these sellers wanted to maintain their projected 10
percent profit, the consumers will bear the cost of cost
overruns, is what I just heard, right. What I'm trying to get
through before I get the answer is, who is the consumer. The
consumer could be whoever's purchasing overseas, as opposed to a
different price which we could get in-state. Is that a
possibility. I'm trying to understand the actual definition of
the consumer and who's actually going to absorb the cost.
10:07:31 AM
MR. STICKEL
No, we are not assuming that cost overruns would be borne by the
consumer. We've developed the model, it's based on a, the
initial model was based on a tolling model for a regulated
pipeline where there is a regulated return. We've basically
modified this approach to modeling to the current project. What
we're presenting here is, if you assume a given sales price and
a given construction cost, and if you assume a 10 percent rate
of return, then what is the sales price to utilities that would
be required for the project to earn that 10 percent rate of
return. This would be, these in effect would be break-even
prices for Glenfarne. What would they need to sell the gas for
to achieve their 10 percent rate of return. As far as who is the
consumer, when we do the modeling, we're looking at sales to
utilities. So for in-state sales, it would be sales to, it would
be sales to Instar, to Golden Valley, other utilities like that.
For LNG, it would be sales to the utilities, you know,
potentially overseas.
10:09:01 AM
SENATOR RAUSCHER
The bulk of the gas is going overseas.
MR. STICKEL
That is correct.
SENATOR RAUSCHER
They are basically going to accept the bulk of the extra cost.
MR. STICKEL
The LNG market is a global market, and so the prices for the
delivered LNG will be based on market prices. Glynnfarne would
go out and negotiate those contracts based on what the market
will bear for delivered costs. They will negotiate the upstream
prices with the producers, and they will outlay the funds to
build the project. They will ultimately bear the risk of a cost
override unless they have a very unique contract arrangement
where they could do some sort of cost sharing.
10:10:03 AM
CHAIR GIESSEL
I just wanted to clarify. I had asked you the question, what if
just the pipe were built, only the pipeline, and you said the
break-even for that would be $12.52. I wanted to clarify, is
that the price that ENSTAR would pay if only the pipe were in
the ground.
MR. STICKEL
To put a finer point on that, and these were based on the fall
version of the model, so they're not exactly directly comparable
to what you're seeing here, but the break-even price for in-
state with phase one only would be $12.52 per thousand cubic
feet under current law if the project went forward, and it would
be $10.72 per thousand cubic feet under the proposed law.
10:10:58 AM
CHAIR GIESSEL
To clarify that's the price to ENSTAR not the price to the
consumer.
MR. STICKEL
That is correct.
10:11:08 AM
SENATOR CLAMAN
So there's several questions about that the consumer, meaning
the gas user in ENSTAR, the homeowner in NSAR's example, isn't
going to pay the cost overruns. Who is going to pay the cost
overruns. Does that just mean in the 10 percent rate of return
that you've calculated that they have to absorb those cost
overruns in the 10 percent and reduce their margin, or does it
get paid somewhere else.
MR. STICKEL
yes, the assumption is the midstream operator would have to
absorb cost over runs.
10:11:53 AM
SENATOR WIELECHOWSKI
Has Glenfarne agreed to not seek a higher than 10 percent rate
of return.
MR. STICKEL
The 10 percent rate of return, this would not be a regulated
pipeline. The 10 percent rate of return is a modeling assumption
that we've developed. They could certainly get a higher than 10
percent rate of return. They could very well get a lower than 10
percent rate of return.
10:12:18 AM
SENATOR WIELECHOWSKI
Who would decide what their rate of return is.
MR. STICKEL
Given that its not a regulated pipeline, the rate of return
would be a function of the purchase price for the gas, the
expenses to build and operate the pipeline, and then the selling
price for the gas.
10:12:39 AM
SENATOR WIELECHOWSKI
Is it the department's position that the RCA or FERC doesn't
regulate this pipeline.
MR. STICKEL
My understanding is that this would not be a regulated pipeline.
I'm happy to call on a lifeline for more details on that.
10:13:11 AM
MR. KISSINGER
This project is a FERC regulated project. It's regulated under
Section 3 of the Natural Gas Act, and it is not subject to RCA
regulation. It is under the exclusive jurisdiction of the
federal government.
10:13:36 AM
SENATOR WIELECHOWSKI
My understanding is FERC doesn't regulate returns, so it would
be up to the, the pipeline producer or the pipeline builder to
decide what their rate of return is.
10:13:51 AM
MR. KISSINGER
As you know, the market will determine what returns are required
to attract the investors. What we've done in coordination with
the Department of Revenue is take a stab at an assumption on
what would be attractive to the market. The market is also going
to factor in their cost overrun risk exposure. So, yes, the
midstream will take on the cost overrun risk, but when the
project is fully contracted, meaning all the upstream contracts,
as Mr. Stickle mentioned, all the downstream contracts, L place,
and EPC contracts constructed, there needs to be sufficient room
to bear what is the perceived cost overrun risk by the
investors. We're trying to see if there's sufficient room for
that.
10:14:52 AM
SENATOR WIELECHOWSKI
We've heard throughout the presentation that the expected rate
of return will be 10 percent, is that what you expect it to be.
MR. KISSINGER
We've always assumed here at AGDC a 12 percent pre-tax rate of
return and a 10 percent after-tax rate of return. But again, as
we seek the investors at FID, that's when the market will make
itself known. Those are somewhat standard infrastructure level
rates of return for projects that are project-financed with
highly creditworthy counterparties.
10:15:41 AM
SENATOR CLAMAN
Let's go back to the consumer and the cost overruns wouldn't be
borne by the consumer in an unregulated pipeline. Where does the
consumer go to get assurance that, in fact, those costs have not
been put onto their utility bill.
10:16:34 AM
CHAIR GIESSEL
The Regulatory Commission of Alaska (RCA) regulates ENSTAR and
the price it charges consumers.
10:16:45 AM
MR. KISSINGER
It is our understanding that the RCA regulates the gas sales
agreements to these utilities, so the utility would take the
application to the RCA in much the same way they do now. They
pick the application for North or Cook Inlet gas sales to the
RCA. The RCA doesn't go and examine all the costs involved and
then make a determination on whether the gas sale itself is fair
and reasonable, is my understanding.
10:17:19 AM
SENATOR CLAMAN
If you've got an unregulated pipeline that's coming in, the RCA
really isn't in a position to say, well, they're charging too
much for the gas that's coming in the pipeline and potentially
putting in the costs that are very much showing up now in the
consumer's bill. RCA would say, well, where's the point at which
we can say, no, this is not OK, because they actually don't
regulate the pipeline that's getting it there. I have questions
about the certainty, the proposal that we wouldn't charge it to
the consumer is just another day when somebody said, well, these
were cost overruns, it's built into the pipeline gas price
that's coming to ENSTAR. ENSTAR says this is the best price we
could get and it's got those very prices getting shared to the
consumer.
10:18:08 AM
CHAIR GIESSEL
It is my understanding, and I will confirm that, that if this
were an in-state pipeline only, that the Regulatory Commission
of Alaska would regulate it. However, the Glenfarne entity has
gone to FERC and permitted this as a single project, which
includes an export facility, which FERC does have jurisdiction
over. My understanding is that the Regulatory Commission of
Alaska will regulate what the rate of return to ENSTAR is. They
will tell them what the cost of the gas is that Glenfarne is
selling it to them for, and then determine how much ENSTAR can
add to that to cover ENSTAR's cost. That's where the RCA would
come in. I can confirm that, and we can certainly invite an RCA
commissioner to join us at the table, but that's my
understanding.
10:19:12 AM
SENATOR KAWASAKI
Just because we're talking about RCA and then who would figure
this out, and I don't know who can answer this, but is the spur
line from wherever to Fairbanks going to be rate regulated
through RCA, or is it just a FERC project. If it's not with this
AKLG, but it's a spur, who regulates that.
10:19:48 AM
MR. KISSINGER
It is my understanding that would be, that you mentioned, an in-
state gas pipeline, and so therefore would fall under the Alaska
state statutes.
SENATOR KAWASAKI
Maybe we will clarify with RCA at some point.
CHAIR GIESSEL
We absolutely will and I have that understanding also, that the
RCA will regulate that gas pipeline.
10:20:16 AM
SENATOR WIELECHOWSKI
Just a hypothetical, and correct me if I'm wrong, but could we
pass this bill with the assumptions that were given, and then it
turns out, well, gas isn't really $1.50, it's $3, and the CapEx,
the cost isn't really $46 billion, it's really $90 billion, and
the rate of return isn't really 10 percent, it's 13 or 14
percent. Is that theoretically possible that could happen. The
way the bill's currently written.
10:20:58 AM
MR. KISSINGER
This is difficult for me to apply in so many hypotheticals, so I
apologize.
SENATOR WIELECHOWSKI
I'll break it down for you, Mr. Kissinger, if that's okay. Is it
possible that the gas instead of being $1.50 could be $3. Is
that possible. Yes or no.
MR. KISSINGER
It's theoretically possible, but I'm finding it difficult that
we would be able to clear the market on the LNG side. So,
hypothetically, yes, reasonably, no.
10:21:34 AM
SENATOR WIELECHOWSKI
Is it possible that the capex could be instead of $46 billion,
$80 or $90 billion, yes or no.
MR. KISSINGER
If we're dealing in pure hypotheticals, any number, it could
result in almost any number. I think it would be very difficult
to clear the LNG market if capex estimated $90 billion and you
also have cost overrun. We are now sitting on a class 2 cost
estimate, which has a 15 percent accuracy rate band on it on the
mainline pipeline, and we're moving into feed on the gas
treatment plant and the LNG facility. Once feeders complete on
those, we'll be able to apply with more confidence on the
narrower band of what the capex should result in. I wouldn't
expect that to be $90 billion.
10:22:30 AM
SENATOR WIELECHOWSKI
When can we expect that.
MR. KISSINGER
The developer is attempting to enter into feed the middle part
of this year on both the gas treatment plant and the LNG
facility, and that feed could take as long as one year to
complete.
10:22:54 AM
SENATOR WIELECHOWSKI
When we heard earlier this year that pipe would start to be laid
in December, is that being pushed back now.
MR. KISSINGER
It's important to differentiate between the pipeline and the GTP
and LNG subprojects. The pipeline subproject, as I said, has a
Class 2 cost estimate already on the mainline, and so, no, we're
willing to move forward on phase one with that Class 2 cost
estimate on the mainline pipeline.
10:23:28 AM
SENATOR WIELECHOWSKI
The pipe will still start to be laid in December of this year.
MR. KISSINGER
As I've mentioned before, I don't like to deal in setting hard
timelines for achieving an FID. I'd rather talk about the
ingredients going into the FID and how those ingredients are
progressing over time. We've seen the gas sales, precedent
agreements with the upstream, those need to be converted into
definitive gas sales agreements. That's happening right now. We
have the downstream gas sales agreement to ENSTAR and industrial
customers. Those negotiations are ongoing. And ultimately, that
will go into an RCA process. The RCA process will take a certain
amount of time. That is less managed both on our side, and that
all has to be factored in. Ideally, yes, by the end of the year,
we would be laying pipe.
10:24:29 AM
SENATOR MYERS
You answered about half my questions already. Appreciate that.
To clarify, going back to kind of consumer protection, my
understanding of the process and of what you just said was that
before FID, you guys and Glenfarne, are going to have to sign
firm or binding contracts with Chugach and E and maybe a couple
other customers in the south central that I'm forgetting in
order to go to FID on phase one. But then before those contracts
can get signed, ENSTAR has to have them approved by the RCA,
meaning that it would be extremely difficult for ENSTAR, for
Glenfarne to pass the cost on to the consumer if there's any
significant cost overruns, because that would require ENSTAR or
Chugach or somebody to turn around and go back to the RCA and
get those contracts re-approved and renegotiated. Is that
correct.
10:25:46 AM
MR. KISSINGER
I think that you've captured it exactly how I understand it. If
I just can sort of repeat what you said for clarity, we would
first enter into the gas purchase agreement and the gas sales
agreement that underpin the financing on this project. We would
then get the RCA approvals, we would get the financing, and if
the project did have extreme cost overruns, it would not be a
simple matter of turning around and just passing that cost on to
the consumer, because the consumer, A, has a long-term contract
in place, and B, that long-term contract requires the approval
of the RCA.
10:26:35 AM
SENATOR RAUSCHER
I think the options are still out there. The whole idea behind
this pipeline is to beat the cost of overseas, which I think is
still an option if the price gets too high. I don't know if
that's fact, but I think that that's also an option. And then
there's always whatever we have in the inlet, whatever's left of
whatever we have in the inlet. I think those, they compete
against each other, so I assume that they have to take those
into consideration too. That's just my opinion.
10:27:21 AM
CHAIR GIESSEL
I do want to interject here that Nick Fulford with Gaffney,
Cline is online, and he sends a comment that he has slides on
many of these questions and would be happy to jump in. I'm
hesitant to do that because we do have Mr. Stickel at the table,
and we still have more slides, so we will look forward to
hearing from Mr. Fulford at our next hearing.
10:28:15 AM
MR. STICKEL moved to slide 34, Sensitivity Matrix; LNG Break-
Even Price, Nominal $/Mcf in 2033.
Slide 34 is similar to what we had on slide 33, but looking at
those LNG breakeven prices. What would the price have to be into
the market under different gas purchase prices and capital
costs. This bill would reduce the breakeven gas price for the
developer from $9.07 down to $8.48 per thousand cubic feet under
our baseline assumptions. My understanding is Gaffney, Cline has
some excellent charts that kind of put those values into context
in terms of current and historical market prices globally.
10:29:12 AM
SENATOR DUNBAR
This is going to Gaffney, Cline, but what is the current, price
maybe is a little bit not the best use because of what's going
on in Qatar and elsewhere, but what is the current price that we
would be competing with, and what's the projected price in 2033
we would be competing with.
MR. STICKEL
I would defer some of those questions around exactly what we're
competing against. I looked at futures market prices yesterday
for delivered LNG into Asia. Currently, the prices are well over
$10 per thousand cubic feet, especially over the very near term.
There's a bit of a supply crunch. Once you go out into that
early 2030s timeframe, the prices are lower. They're in the
around $8 to $9 per thousand cubic feet range and really
highlights that these delivered prices are right on the margin
of being competitive.
10:30:22 AM
SENATOR DUNBAR
This is more to Mr. Kissinger. I'd like you to provide a little
more detail about that. Let's say it's $10, we said, and it goes
down because there are a bunch of other LNG projects that are
coming online all over the world, including two potentially from
Glenfarne. My two questions are, what are you assuming to be the
price you're going to be competing with. Then second, I'm still
struggling with this idea that the previous slide, that Alaskans
will really get that price when we're only 5 percent of the
volume that's coming down the pipe. Is there a world in which,
let's say the South Central consumer in Alaska is getting gas
out of this pipe that is more expensive than what we potentially
could be importing from the LNG market.
10:31:42 AM
MR. KISSINGER
On a full build-out of the three train exports, I'd say no,
that's not possible. We did have, in the Alaska Advantage
principles, we have this concept of differential rates. So
differential rates are where you can sell at a lower cost into
one customer than another. For example, to bring on, we've
talked about the Agrium plant. I think everyone would love to
see the Agrium nitrogen plant back online. To do that, under
phase one, if in-state customers are paying in the $13 range,
you would not be able to bring that plant on. You use a tool
called differential rates, and you go, what rate can you pay
there. For hypothetical purposes, let's say that's $6. If
they're paying $6, that would bring your in-state costs down
from the $12, $13 range to the $10 range. In that instance, and
apologies, but the same could be done with a single train of
LNG. If you build with just the first train of LNG, you could
take it off that way. Hypothetically, in that situation, you
could have overseas customers paying less for the gas than the
in-state customers. The way those differential rates are allowed
under this Alaska Advantage principles is only where they
achieve the one resting possible rate for in-state utility
customers. It has to be demonstrated that we're benefiting from
those differential rates. Even though it's a very hard pill to
swallow, we still need to be demonstrating that we're at least
benefiting from those differential rates and bringing down the
cost to in-state customers from where they would otherwise be.
10:33:47 AM
SENATOR DUNBAR
I assume that exists in law, that principle, and you as a state
agency, I assume, would be answering to the rest of state
government on that. If that's not correct, let me know. Second,
you know, our Department of Revenue has made some, different
break-even prices. Where is ENSTAR assuming that the price will
be in 2033.
10:34:24 AM
MR. KISSINGER
The way you look at the market is on the basis of a marginal
supplier. You don't look at who can supply for the cheapest
price into the market, which in a lot of different ways before
the war was caught up. They don't sell at that low price if they
produce that. Of course they sell at the market rate. The market
rate gets set by whoever is producing into the market at the
highest cost. That happens to be the U.S. Gulf Coast, generally.
If you break down just the structure to go from Henry Hub
pricing to delivered LNG into Asia, it goes something like this.
You buy your gas at Henry Hub prices plus 15 percent. That 15
percent covers the fuel, the same way we had these questions
earlier around why the costs are different. You still have to
pay for your fuel in that low 48 model. If you're thinking of
around a $4, maybe $4 plus, just to make the math easier, Henry
Hub price, which is a decent forecast for long-term Henry Hub,
you'd be around $5 by the time it's going into the LNG plant,
because you're including that fuel. Liquefaction across the U.S.
Gulf Coast is pretty standard. It's about $2.50 per MMBtu. So
that puts you at $7.50 over there in the U.S. Gulf Coast, still
needing to be delivered to Asia. It's about $2.50 to deliver
from the U.S. Gulf Coast to Asia, a lot of that driven by the
impacts of the Panama Canal or having to go the long way to get
there because you avoid the Panama Canal. That achieves a
delivered price into Asia of $10. Then you have to stress that.
You have to be able to withstand periods of time when Henry Hub
goes down to $2.50 like it does now. You also have to take into
account that a lot of LNG is also priced on Brent. That's the
math on U.S. Gulf Coast, moving to the math on Brent and it's
usually sold as a percent of Brent. Through casual reading, I
think you'd be able to discover that the price band is fairly
narrow. It's somewhere around 12 percent, 13 percent, sometimes
14 percent, sometimes less, sometimes 11 percent Brent. Let's
use 12 percent Brent as our assumption now. Where you're at $100
oil, you're paying $12 for the LNG. That's how that works. If
you think of $75 oil, which is, a long-term stable view of oil,
that would be $9 for an MMBtu. What we're trying to beat is
somewhere in that $9 to $10 range.
10:37:13 AM
SENATOR DUNBAR
I think that's a good summary. It does illustrate perhaps the
necessity of this legislation, but it also sort of illustrates
that, as Mr. Stickel just said, this is in some ways a marginal
project, and if you go over 20 percent cost overrun, you're not
really competitive, even at $1.50, and certainly not at $2 or
$2.50. It's good testimony for this bill. It sort of reiterates
what I think a lot of us have been feeling, which is we are
still skeptical that the private market will step in and invest
in this project.
10:38:08 AM
MR. STICKEL moved to slide 35, Sensitivity Matrix; Cumulative
State Revenues through 2062, Nominal $ millions.
This shows total cumulative state revenue over the life of the
project. Under current law, state and municipal revenues would
increase substantially with higher project costs. We assumed
that those higher project costs would feed through to higher
property tax valuations. You see some upside to state revenues
under current law. Then the flip side of that is risk to higher
state taxes for the developer. Under this proposal, state and
municipal revenues would be lower across the board, but then
they would not increase if there were higher project costs. When
folks are saying that the bill de-risks the project, that's what
they're talking about, both the lower tax burden overall and
then lower risk of facing higher taxes if the project value
comes in higher than expected. You see a similar sort of chart
if we did this for municipal revenues, but even bigger numbers,
since the majority of the property tax is to the municipal
owners.
10:39:38 AM
MR. STICKEL moved to slide 36, Sensitivity Scenarios; In-State
Gas Cost, 2033 Nominal $/Mcf in 2033.
Slide 36 is a tornado chart, another form of sensitivity
analysis. What we did here is we looked at how certain key
assumptions could impact that break-even in-state gas price.
Under current law, starting with the $4.86 as our baseline price
for delivered in-state gas, and we looked at property taxes,
capital expenditures, that rate of return to the midstream, the
purchase price of gas, and the interest rate paid on debt, and
what higher or lower values for each of those would do to that
break-even cost of supply. The biggest ways to reduce that
required price for in-state gas would be through property tax
relief and paying lower prices to the producers for the gas. The
biggest risks to the upside would be higher than expected
project costs and paying a higher value for the gas to the
producers. You see this bill would de-risk that capital
expenditures risk quite a bit in addition to reducing the
property tax burden.
10:41:13 AM
MR. STICKEL moved to slide 37, Sensitivity Scenarios; LNG export
price, Nominal $/Mcf in 2033.
by looking at the breakeven LNG export price, $9.07 per thousand
cubic feet being the current law baseline, and we see the impact
of those key assumptions on that required cost of supply. Lots
of risk to the upside in this project, and you can see from
looking at the capex number in particular, why it's important to
the developer to de-risk that capex, especially if they think
there's a chance that project costs could come in higher than
the $46 billion that we've assumed.
10:41:59 AM
CHAIR GIESSEL
I'm looking at the cost of debt. I understand that there is some
hope that the federal government will have some loan
opportunities, and would that be at the lower interest rate.
Where would that fall.
10:42:19 AM
MR. STICKEL
We assume a 5 percent interest rate for that cost of debt. If
there was some sort of reduction to that, we show the impact if
those rates were brought down to 3.5 percent, that would
materially impact the breakeven prices, and then we show the
impact of a higher cost of debt as well. The 5 percent is a
baseline assumption. It incorporates the known information
around the federal loan guarantees that do exist. Obviously, if
there was additional support that would be enacted, that would
be a positive to the project.
10:43:00 AM
SENATOR CLAMAN
Could you repeat the baseline price for the LNG export chart,
this one.
10:43:06 AM
MR. STICKEL
$9.07 per thousand cubic feet in 2033 is our current law
baseline. That's where we start this tornado chart.
10:43:26 AM
MR. STICKEL moved to slide 38, Summary: Total Government
Revenue, Part 1 of 2.
Slide 38 shows a summary of total government revenues under this
bill, and we show this over 10, 20, and 30 years of full
production from the project. This is a snapshot of a detailed
summary document that we've provided as a committee document,
and we've split that into two slides here to make it reasonable.
10:43:59 AM
SENATOR WIELECHOWSKI
Looking at the upstream corporate income tax, what would that
number be if all the producers on the North slope were paying a
corporate income tax.
10:44:09 AM
MR. STICKEL
It would be about 50 percent higher, roughly speaking, about
two-thirds of the producers are paying corporate income tax.
10:44:22 AM
SENATOR WIELECHOWSKI
What would that number for project corporate income tax look
like if the pipeline developer or all the others involved in
this project were paying a corporate income tax.
10:44:38 AM
MR. STICKEL
We can provide that. We haven't calculated that out here. We are
assuming, conservatively, that the midstream would pay zero
corporate income tax.
10:45:07 AM
MR. STICKEL moved to slide 39, Summary: Total Government
Revenue, Part 2 of 2.
Slide 39 is the second half of this chart. This entire analysis
has been provided as a committee document, but through the 30-
year modeling period, looking at a total of $22.5 billion of
state benefits over the life of project, and then nearly $4
billion to the municipalities over the life of project, and
federal government income tax benefits netting about $22 billion
over life of project, so a total of $48 billion to the various
governments through 2062.
10:45:47 AM
SENATOR MYERS
If you're going to provide us numbers about if the midstream was
paying the corporate income tax, could you also provide an
estimate of what that would do to the gas cost, both for in-
state and for LNG sales.
10:46:05 AM
MR. STICKEL
Yes.
10:46:10 AM
SENATOR WIELECHOWSKI
Looking at the oil production tax, why is that a decrease of a
couple hundred million dollars from 2052 to 2062.
10:46:21 AM
MR. STICKEL
These are positive impacts above and beyond the revenue
forecast, and what our modeling does is it accounts for all of
the impacts of the ability of companies to deduct lease
expenditures against the oil tax. It accounts for all of the
impacts of per-taxable barrel credits, and going from the 2052
to the 2062 timeframe, we see a net increase in the production
tax paid to the state overall when you combine the oil and the
gas pieces, but some of the lease expenditure deductions and
per-taxable barrel credits do reduce the oil side of things. In
our modeling, we calculate out the gas production tax, the 13
percent gross tax, we calculate out the oil tax net of
everything, and then we add them together to get the total
production tax impact.
10:47:33 AM
SENATOR WIELECHOWSKI
Am I reading that correctly, that the oil production tax is $1.6
billion positive through 2052, but then it declines by $275
million through the next 10 years.
10:47:50 AM
MR. STICKEL
Yeah, from the 2053 to 2062 timeframe, we do expect a reduction
in oil production tax relative to the forecast, but that will be
more than offset by increase to gas production tax.
10:48:18 AM
CHAIR GIESSEL
Is this reflecting the deductions they can take against their
oil taxes as they produce more gas.
10:48:29 AM
MR. STICKEL
All our modeling accounts for the fact that under our current
production tax law, any incremental lease expenditures
associated with gas development can be deducted against the oil
tax calculation. We also account for the nuances of the per-
taxable barrel credits, which those are generated based on oil
production and applied based on the statewide tax calculation.
Both of those factors are built into our modeling.
10:49:07 AM
MR. STICKEL moved to slide 40, Conclusions.
The AK LNG project, if it was constructed, it would provide
billions of dollars to the state and the federal government and
local governments. It would provide a new revenue stream to the
upstream producers and a new revenue stream for a midstream
developer. It would provide jobs and support energy security in
the state and nationally. This bill would reduce the tax burden
on the developer, making the project relatively more economic
and would help de-risk the project in terms of reducing the
potential impacts of higher project costs or higher tax
assessments.
10:50:02 AM
CHAIR GIESSEL
The next few slides are sectionals, which we don't have to go
through. I do want to ask you a question, however, on slide 46,
and this relates to Alaska statute 4356-022. This is where it
imposes a replacement of all state and municipal property ad
valorem, et cetera, taxes. It's all written there. Looking at
this, it's unclear to me whether this is confined to certain oil
and gas properties or if this applies across the state. Would it
be applying then to qualified property under that definition
that is in Cook Inlet, for example, or in Middle Earth.
10:50:55 AM
MR. STICKEL
I can speak to what my understanding of the intent is. The
intent is, if you look at current property tax law, there's
language in the statutes that property tax is in lieu of other
similar taxes. That's kind of the intent is a fairly narrow
exclusion. Municipalities, the volumetric tax would be in lieu
of the property tax or similar taxes. And so the intent of that
is not to provide an extremely broad exclusion, but a narrow
exclusion. We've got Department of Law on who can opine on in
further detail if that's helpful.
10:51:40 AM
CHAIR GIESSEL
It would be. Let's see. Ryan Farnsworth is online with the
Department of Law. Mr. Farnsworth, how broadly can this
exclusion be applied.
10:51:56 AM
RYAN FARNSWORTH, Assistant Attorney General, Department of Law,
Anchorage, Alaska, answered questions on SB 280.
Is the question about the abatement of property tax.
CHAIR GIESSEL
Yes, its on slide 46, but its section 4356-022. It seems very
broad. It pertains to purchase, use, consumption, or ownership
of property or services in that municipality or jurisdiction.
10:52:33 AM
MR. FARNSWORTH
It is a broad exemption.
CHAIR GIESSEL
Could it be applied to, let's say, the Glenfarne, or AGDC has an
employee that lives in Bethel, and they come to work for two
weeks in Kenai. They're building the export facility. They are
going to go to buy some groceries. We're talking now about
consumption, right. Purchase, use, consumption. Can they be
waived. Can they receive a waiver on the property or the
municipal sales tax when they go back to Bethel as well, or only
in the Kenai Borough, or how will that apply to the employee.
10:53:33 AM
MR. FARNSWORTH
I don't think the employee would be exempted from sales tax for
lunch purchased while working. It would have to be property
that's definitely something contributed to the project by
contract, so perhaps catering for a large event, something like
that for the project, but I don't think individual lunches would
be exempt.
10:53:56 AM
CHAIR GIESSEL
That is not defined here. You're making an assumption because,
of course, regulations haven't been written to apply this. Is
that true.
10:54:09 AM
MR. FARNSWORTH
No, because the alternative, the exemption from the tax is
related to the qualified property, so it has to be related to
the property, the project, or something associated.
10:54:26 AM
SENATOR DUNBAR
I just want to ask another hypothetical, just a little bit more
direct. If Glenfarne brought in a bunch of contractors that,
again, were working directly on the project, and they stayed in
Anchorage for a week in hotels, would they be exempt from our
bed tax.
10:54:46 AM
MR. FARNSWORTH
I would say no to that.
10:54:50 AM
SENATOR DUNBAR
Why. The way it's written here. I don't understand why having
construction or contract employees that are directly working on
the project wouldn't be associated with the project. Are you
saying it has to be something physical, physically attached to
the project.
MR. FARNSWORTH
Not necessarily. It depends who's paying that bill, if the
project's being billed or the individual.
10:55:36 AM
SENATOR DUNBAR
What about Anchorage gas tax if you're filling up a bunch of
trucks headed to the project carrying things for the project.
Are they exempt from Anchorage gas tax.
MR. FARNSWORTH
That's probably a little detail that isn't in this statute, this
draft.
10:56:09 AM
SENATOR WIELECHOWSKI
I'm curious if the Department of Revenue included in their
modeling how much this section would cost the municipalities or
the state.
10:56:22 AM
MR. STICKEL
We modeled to what I understand is the intent of the section. I
understand that there may be an amendment to tighten up the
language here that would be helpful. I did have discussions with
the Governor's office to understand what was intended here. The
intent is a narrow exemption, basically to disallow a property
tax by another name. That's what the ABT would be a replacement
for the property tax and the type of property that would be
taxable under a property tax. The intent is not to include bed
taxes and sales taxes and things like that. When we did our
modeling, we modeled to that intent. We looked at the reduction
to the property tax and then the imposition of the alternative
volumetric tax.
10:57:21 AM
SENATOR WIELECHOWSKI
Different topic, but just a request.
10:57:26 AM
CHAIR GIESSEL
Could I follow up then just briefly on that. You're saying
that's the intent, but would you agree that that intent is not
actually fleshed out in this statement of a statute.
10:57:37 AM
MR. STICKEL
We would need to put regulations into place. I would suggest
that we would look at that intent when crafting those
regulations. If we wanted to put the additional clarity into
statute, that could be certainly helpful.
10:57:54 AM
SENATOR WIELECHOWSKI
A request for the department if they could get us. Slide 33 was
the sensitivity matrix for in-state gas as of 2033. That's phase
two. I'd like to see that chart for phase one. I think that'd be
beneficial to the to the committee. Do you understand that.
10:58:17 AM
MR. STICKEL
This would be a phase one only if the full project did not
proceed. We are in the process of preparing that modeling. When
it's ready, we will re-present that.
10:58:29 AM
SENATOR WIELECHOWSKI
Then I had a question for Mr. Kissinger. I've heard from
constituents and other legislators that there are ads running
just on the radio and on political blogs urging support for the
LNG projects. I'm just curious who's paying for those.
10:58:52 AM
MR. KISSINGER
It's my understanding that Glenfarne is paying for those.
10:59:03 AM
SENATOR WIELECHOWSKI
Is AEDC paying for those in any way, or have you approved of
those.
10:59:13 AM
MR. KISSINGER
We have neither approved them nor paid for them.
10:59:23 AM
SENATOR CLAMAN
I want to go back to the discussion about regulations, Mr.
Stickel. There's this theme that we often hear, the regulations
have to comply with the law and the regulations can't do more
than the law, and if we have regulations that do one thing and
the law doesn't go that far, then there's a lawsuit and says,
well, those regulations are improper. If we're concerned that
this, as drafted, is too broad, why would we rely on regulations
to straighten it out.
10:59:58 AM
MR. STICKEL
I'm an economist, not a lawyer. If I were involved in the
regulation process, I shared what my view would be and what the
intent and direction from the administration was in this.
Certainly, we'd be happy to look at potential amendments to
strengthen up that language to make sure that it does indeed
match what the intent is.
11:01:01 AM
[CHAIR GIESSEL held SB 280 in committee.]
11:01:12 AM
There being no further business to come before the committee,
Chair Giessel adjourned the Senate Resources Standing Committee
meeting at 11:01 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 280- AGOCC Conservation Order 341F.pdf |
SRES 4/14/2026 9:00:00 AM |
SB 280 |
| SB280 GaffneyCline Presentation to SRES 4.14.26.pdf |
SRES 4/14/2026 9:00:00 AM SRES 4/15/2026 3:30:00 PM SRES 4/16/2026 9:00:00 AM |
SB 280 |
| SB280 Presentation to S.RES 03.30.26.pdf |
SAAF 3/30/2026 3:30:00 PM SRES 3/30/2026 3:30:00 PM SRES 4/13/2026 3:30:00 PM SRES 4/14/2026 9:00:00 AM |
SB 280 |