I call Senate resources committee to order today as Friday, January 30th, 2026, and the
time is 3.30 p.m.
Please turn off your cell phones.
Oh, check mine.
Yes.
All right.
Members present today, Senator Kawasaki, senator Myers,
Senator Rauscher,
Senator Dunbar,
Vice Chair,
Senator
Willakowski and I am Chair Geesele. I do expect Senator Clayman along shortly,
but we have a quorum to conduct business. Thank you to Heather and Chloe for helping us out
with the minutes and the audio.
Today we're hearing a presentation continuing in the discussion of a potential gas pipeline.
And today we will hear from the Department of Natural Resources and on the phone will
be the Alaska Oil and Gas Conservation Commission.
So I will invite the department of resources forward first and, excuse me, Deputy Commissioner
John Crow there is here and director of Division of Oil
and Gas, Derek Nottingham.
So welcome.
And then online for questions.
Let me make sure they're actually here.
Jessie Chimalowski, she's a commissioner at AOGCC,
along with Greg Wilson and Tom McKay, also commissioners.
Tom Kays is an appointee at this time.
And Rudeve Robie, senior reservoir engineer.
at AOGCC. Welcome, Senator Clayman.
So we will go ahead and proceed with DNR's presentation.
Welcome.
Thank you, Chair Giesel and members of the committee.
For the record, John Crother, Commissioner Designee.
I also have at times been referring to myself as Deputy
Commissioner on the records, so I apologize for if I do it as well.
But it's great to be here before you and important topic today.
Further ado, I'll turn it over to my colleague, Director Noddingham, and he'll start our presentation unless you have any framing remarks the committee would like to make.
No, please proceed. That's great.
Thank you, Chair Geesele. For the record,
I'm Derek Nodingham, director of the Division of Oil and Gas.
And I will just go ahead and move on to the first slide here and just kind of...
give you a brief overview of what we're going to talk about today's scope and the objectives.
What we are going do is just kind of talk through some of the natural gas availability from the
the fields that we commonly hear referenced in regards to North Slope gas, that would be
Prudhoe Bay, Point Thompson, the North Star unit, Indicot, or otherwise known as the Duck Island
unit. And more recently the Alcade, Talitha, and Tulek River units, kind of to the south of the
the resources that we're talking about in terms of gas and these fields represent
about 30 TCF of Gas. So in context...
If you were to put it in, you know, kind of context of the cook inlet, that's over 400 years
of gas supply that could be supplied to us. An area like the size of South Central, obviously,
the intent is to export that, the majority of that at some point in the future, but just that gives
you an idea of this size and volume of gases that we're talking about here. There are other
that the gas resources do exist, but we're not going to discuss those today.
They're really not the ones that we typically refer to as being the primary contributors to the AKLNG project.
And if you just kind of consider all of the unexplored gas on the north slope.
estimates are that that's well over 200 TCF of gas that still yet to be explored
on the North Slope, Beaufort Sea, Chukchi Sea those regions. So lots of
gas on The North slope. What we're going to talk through today are DNR's
characterizations of what the gas resources are, the analysis that we've
primarily or all of it's actually from public data unless it is explicitly referenced as
not.
So these are in general a lot of our calculations or they're referenced in the public.
The pie chart that you see on the left there, that represents the kind of distribution of
Prudhoe Bay, North Star, Point Thompson and Duck Island are in the cut.
That gas cumulatively adds up to almost 30 BCF or 30 TCF of gas.
I apologize.
You'll see these, the nomenclature in here, TC F, trillions of cubic feet, BC F billions
slip back and forth in between that a little bit, so apologies if it gets a
little confusing. So that that is what we would call known gas because it comes
from fields that have either utilized that gas in the past as part of their
enhanced oil recovery and they're continuing ongoing oil operations in
quantifiable amount of gas, we know that they produce significant rates and those kind of things.
Now, in the Alcade to lead the Tulek River area, the resource volumes that of
gas that could be there are somewhere up to possibly 7 TCF or 7,000 BCF as you see there.
But there are still ongoing exploration activities, appraisal activities to understand that resource
and prove its commerciality to date that there's been quite a bit of exploration wells that have
to date really haven't seen a commercially
developable project there yet.
But that work, that exploration work continues to move forward.
So a question, Director Nonningham.
Where are those three fields?
Are they the hashed yellow ones on the pipeline route there?
Chair Geesele, yes that's correct.
They're the units that you see on
the pipelines to the south of Prudhoe Bay.
So are those the units that Pantheon is working?
Yeah, Chair Geesell, yes, that's correct.
It's a great bare pantheon and also 88 energy
is another operator in the Toula-Griever unit.
OK, very good.
Any other questions from members?
All right, seeing none, go ahead.
The next slide is just stepping through each one of these fields.
We'll kind of go through a bit of the resource and kind
of some characterization around that.
The first one is Prudhoe Bay.
I think everybody knows Prudehoe is a really big oil field.
It's one the largest in the world.
It is the large in North America.
Original oil in place was about 25 billion barrels.
They're getting close to somewhere around 13 or 14 billion barrels
of produced out of Prudhoe Bay to date, and the original gas,
or gas cap in place was 46 TCF.
The resources available from Prudo are estimated at 22,000 BCF
or 22 TCFs at a maximum off take rate of 3.6 BCFs per day.
per the AOGCC 2015 off-take order.
Some of the challenges that, you know,
probably through the CCUS bill and just through
the context of that I think it's right widely recognized.
There's a fairly high CO2 content in Prudhoe Bay,
somewhere in the 10 to 15% range.
CO2 content presents a unique challenge that would require a major facility to remove CO
2 from the gas before it could be produced down the pipeline quality kind of specs.
about 250,000 barrels of oil a day.
So roughly a little bit more than half
of the North Slope oil.
Great, thank you.
Senator Kawasaki has any question.
Thank you, Madam Chair.
Thank You, Mr. Nottingham for being here.
Question about the off take rates
and maybe just
to explain how the pressurization of the field has worked so far so that you've used gas to
basically produce more oil and if you start to take gas pressure out you'll produce less.
Can you kind of explain the dynamics and the mechanics of that or maybe there might be somebody
else online who can do that too? Through the chair, Senator Kawasaki, I could probably go through a very
Basic explanation for you. However, the AOGCC is on the line, and I believe David Robies on
the lines, so they may want him to kind of speak to that. Sure. So, commissioners at AOGCC,
I'll let you choose who you'd like to have answered that question.
You got anyone to go ahead? Yeah. Okay. This is David Rowley. I'm the
When Prudhoe originally came online, they anticipated beginning gas sales, five years after oil sales.
And at that time they expected the ultimate oil recovery to be about 9 billion barrels.
So pretty much everything about that, the 14-inch billion that's been produced so far,
the extra 5 billion is due to the gas not leaving Pruthoe Bay,
Follow-ups under Kawasaki. Thank you. Thanks for that explanation. So as a
As there's off take of gas at this
3.6
Or 0.36 TCF per day amount
How does the pressurization of the field?
How did it maintain itself or is there a point in which the Field?
Switches over to more of a gas field than an oil field
During the Kawasaki Food Chair, this is Dave Rovigin.
When they begin major gas sales, the pressure of Prudhoe Bay will start dropping, and there's
really nothing that can be done about it.
They'll reduce the amount of remaining oil that's recoverable.
But that said, there is currently four times as much BOE that there was oil equivalent
in the gas than there are remaining liquids in this field.
So I guess the the question then on the amount of off-take or the off take rate is kind of important in the discussion and
How much gas is going to be available for an LNG export facility and
So have you have been involved with the discussions surrounding the
a calendar process and what they're expecting to be taking off at what times.
Senator Kawasaki to the chair. I haven't been involved too much with the current
a-k-l-n-g with Len Farm, sorry, in charge. But back in 2015, when BP was the operator and came
to us with an application, myself and others here were closely involved with them going through the
reservoir information, economic information and stuff like that.
I'm sure things are different now since it's been 10 plus years.
But have good background understanding of how things
are working.
Thank you.
Thank You.
Senator Wilkowski.
I am interested in hearing the interplay between DNR and AOGCC on.
Somebody will get to have to make a decision about where
Where's the value? I I know a GCC has
The obligation to and make sure there's no waste your obligation is to manage the resource for the maximum benefit of the people
So I'm trying to understand your role in this and if
It's probably important to know what the price of the gas sale is and what
the revenue to the state would be, I would assume.
And if I'm hearing gas is going to sell on the North Slope for
a dollar to dot me a $1.25 per MCF, if it's different, let us know.
State gets that current taxes, $0.13 per MCF versus
both get royalties in both, but probably a much higher production tax, so the value to the state would be much
higher. So I'm just curious how you're approaching this and determining what's in the best interests of the
state. Senator Willakowski through the chair, John Crowder here, for the record.
The, I think the, and I don't want to speak for my ARGCC colleagues,
that that off take order, you know, what is the maximum allowable rate for production
that conserves the energy and ultimate recovery of the reservoir across barrels of oil and
barrel of olive oil equivalent and gas.
So I think that direct regulatory authority is there as you alluded to, the department
how that affects royalty value and it as you reference the price of both commodities one to
another affects that and the performance of the reservoir I am not a reservoir engineer so it
eludes me to say the least but the you know it's not pure trade-off of we start producing gas we
stop producing oil it is a very complex interplay between less pressure from gas re-injection
you know water maintenance and flooding the reservoir and such so it's a complex
equation for how gas off take wood influence recovery but I believe the
technical specs are gone through closely with AOGCC the department will be
working to model that as it affects kind of value and for making royalty
disposition decisions. Follow-up Senator Wilkowski. Do taxes factor into that
We've heard testimony that we capture the value of our resource, which we're required to constitutionally maximize the
a series of
property taxes and production taxes, and royalties and corporate income taxes. And so
Do you factor in the volume of those other things when you're determining?
Whether or not we should be
Making that trade off and allowing more gas at the expense of some oil
Senator Willakowski through the chair, the department works to model and
understand those values as it relates to our royalty value.
And we work with the Department of Revenue on the tax related things, which are not directly in our jurisdiction.
I think our input would be informational to AOGCC, but
I'm not sure the scope of what they're required and what their discretion able to consider in the course of their review.
But they might be able answer that.
Would you like to ask AGCC?
I'm curious, if I could, my chair.
Yes, Senator Kosaki.
Excuse me, pardon me.
Not the first time we've been confused.
Who has the ultimate authority?
If DNR in your analysis says, you know what?
It'd be better off if we delayed gas sales
for a couple of years because we can make a cup of billion
dollars more in revenue for the state via oil sales
and you'll have declining oil
sales with declining pressurization.
who wins that battle, who, I mean, how is that decision made?
Senator Willakowski through the chair,
I believe on a technical what the off-take order
can be approved at as an AOGCC determination,
and I'd let them speak to their exact criteria,
where the department to be aware of a material difference in outcomes,
we may very well assess and share that information.
But depending on the specifics, but I have to let AOGCC speak to where their line is
of what they're required to consider and what their discretionarily able to
consider.
Just to clarify, who's responsible for making sure we get the maximum value for our resource?
Is it DNR?
And AogCC is responsible to make sure that we don't have waste, right?
to the chair, I believe the department is responsible for maximizing the value to
the greatest degree within our authorities in control, and that would involve as much
understanding about the ultimate recovery of royalty and its impacts to its value of gas
But the decision about what best leads to recovery of energy equivalent out of the reservoir as a question of pure authority, I believe, is with AOGCC as the final decision.
Senator, would you like to ask AOCCC?
You're looking at me.
Well, get to AogCC when they come up and testify, but I think this is an important answer for us to get because I actually think the legislature is responsible for ensuring the maximum benefit of that resource.
Shouldn't we know the price that the gas is being sold for and how much revenue we're getting?
Before we embark on a project that could significantly diminish the value of the resource.
Senator Willacowski through the chair, I think is it in a philosophical sense, absolutely yes.
And I I the department, any determinations we made about selecting royalty and
value versus royalty in time would be based on information about price.
proposed sales. I'd have to let AOGCC speak to how they evaluate, you know, price going
into their authorities.
I will note for clarification, I do believe they assess, again, the technical specifics
elude me personally. The energy equivalent, obviously oil and gas are on a spectrum, but
on an energy equivalent basis, and that often plays
into relative price premiums one to another.
I should clarify for the committee.
This is sort of a combined presentation.
AOGCC is online, but they're going to tag team on this.
So I'm going call on AOGCC to answer
Senator Wilakowski's question in terms of how they made
they think the off-take should be. So commissioners, who would like to speak to that?
This is Jesse Chablowski, Senator Wilakowski through the chair. I'm going to just reference
Conservation Order 341F as in Frank, which we can provide for you, but it's on our website,
reviewing reservoir simulation results and concluded that the ultimate recovery from
the prutobite oil pool could only be maximized with major gas sales as there are significantly
more barrels of oil equivalent of reserves in the form of gas within the pool than there
are in liquids that remain within pool.
taxes or the price of the gas. We're certainly looking at greatest ultimate recovery in the resource.
Follow up. Question, Senator Wilakowski. Yeah, and it's article eight section two says the
legislature shall provide for the utilization development and conservation of all natural
resources belonging to the state including land and waters for maximum benefit of people.
So it seems to me
that one of the things that we look at for maximum benefit
is how much revenue we get to the state.
And it seems to me like it would be important for us
to know how many revenue
we're gonna get from the,
if we start taking gas off of Prudhoe Bay
and we are getting it at a tax rate and a revenue
at royalty rate, quite frankly,
that's much lower than we'd probably get for our oil.
That's all I'm saying.
And I'm not sure that's what AOGC is saying, they're looking at a barrel of oil equivalent,
they are not looking out the revenue aspect of this.
We have a $2 billion deficit that we have to solve.
So for us, the Revenue aspect is very important.
So I am curious, who is looking for the Reveno aspect to this, especially considering the
fact that, we had no idea what this gas is even being sold, I mean, general things that
out there in hearsay, but shouldn't we have some sort
of modeling, shouldn we, have
some public information that is available to us
about the value of what we're getting?
Mr.?
Senator Willakowski, through the chair,
I believe that in coordination with the Department
of Revenue, we potentially would be able to present
information based on assumptions of gas production volume
oil in production impacts over time and price based on a variety of assumptions
Information about kind of net revenue balance and and such
It's a complex suite of information formulas, but I believe there's work at done at that the executive level on those questions
Senator Dunbar did I see your hand up?
Yes, madam chair, it's all right. Thank you. All right, so under claimant
follow-up for Commissioner Crowder.
I appreciate the notion of saying this is kind of a philosophical question,
but I guess as I listen to it,
I think it's more of
a math question and that doesn't mean it is a simple math questions.
I agree with you because part of what you're trying to figure out is if you
are injecting a certain amount of gas,
what does that do to your oil pressures and oil coming up?
At some level that would be in the engineers world. I think in theory fairly
straightforward, but actually I'm sure it can't because these are incredibly complex oil fields
that have been developed and lots of engineers involved and that's work. But it seems to me that
really having a better understanding to show to us.
If you're reducing the gas that's going down, that is going to reduce the oil that
is coming up and I think it's been a given for decades that we make more money on oil
than we do on gas.
But as the field characteristics change, there may be a point at which that changes,
but it seems to me that math problem is something that should have a lot more information about
There certainly should be a price at the value of the gas.
It's more effective to continue to pump all of it down into the wells to get more oil out.
And there's also a priced at oil that gets so low that it becomes more worth it to
get the guess out, because the gass starts becoming more valuable in ways than the oil.
But I see it more than philosophical.
Senator Clement, through the chair, your point's well taken.
mathematical quantitative question and an important one I think today we're
you know prepared to present about you gas volume on a general scale but of
course as the committee wants more information about these questions we can
work with the Department of Revenue and other entities is appropriate to
present what we were able to and we request that going forward before we leave
the slide though I would like to ask Commissioner Tumalowski taking the gas
How does that ripple out to the pressure in the in
the fields at Millie Point and Caparic River?
Is there, I don't know what the connectivity is underground?
Chair Kecil, this is Jesse Chimalowski.
The fields are really not connected in that way,
so selling with the gas from Prudevay
should not affect the reservoir maintenance
or pressure maintenance of those other fields you referenced.
Thank you
Any other questions on this slide all right seeing none, I'll let you proceed
I think we're on slide 5 now point top are we on point Thompson? Yeah, good to the chair
For the record, that's the one I'm looking for Derek Nottingham again
Yeah so it just for clarity sake
Prudhoe Bay is not
One of the primary targets is my understanding of a klng phase one
It's probably in you know later phase phase two
When you you get a kind of full-scale exports of gas out of out, of Alaska so and
So that's just another consideration when we're
kind of walking through these, we're walking
through this more in terms of the resource size
and not where they stand in relation to the phasing
of project as we know it.
So Point Thompson, I think most people are pretty familiar
with the name, 60 miles or so east of Prudhoe Bay.
I thing is actually 44 miles east
of Dead Horse, so a little bit of a discrepancy
in the mileage there.
Eight BCF, or I'm sorry, I know these numbers
like the back of my hand and I get them confused.
It's eight TCF of gas originally in place.
Estimated six TCFs or 6,000 BCFs of gases of resource
and what's a retrograde condensate reservoir.
per AOGCC in 2015. Also, the maximum off take rate from the Point Thompson reservoir
was anticipated to be 1.1 BCF per day. There is currently no gas pipeline that traverses that
40 to 60 miles from Point Tomsen back into the main infrastructure there at Prudhoe Bay.
retrograde condensate reservoir.
So without getting into too much technical detail,
we need to deplete the pressure in and around the wells
or in the reservoir, the liquids that we actually
produce now, they start to fall out in
the Reservoir and they kind of block flow.
So it creates sort of these challenges around
The flow capability of the reservoir the wells and those kind of things
So that's why it's really important to kind
Of continually to get to maximize oil recovery out of reservoir
inject the gas maintain the pressure and then and you can recover those liquids without as much impediment
We understand the CO2 content to be lower than Prudhoe Bay. It's not zero
but it's not nearly the kind of the 10 to 15%
that you see in Prudhoe Bay.
So I guess I would characterize it as marginal.
how much treatment will be required to remove that CO2, if at all, to kind of
send it down the pipeline as a sales gas. Currently, the field's producing a
little over 4,000 barrels a day. The Point Thompson 17 well has basically had
some of those impacts possibly from the retrograde con and say possibly
quite certain what that is, but the operator is actually drilling another
well to up the off-take rate out there to get it closer or above the 10,000
barrels a day that it historically is targeted. So there's plans to put in a pipeline.
Through the chair Gissel that there would have to be a pipeline a gas pipeline from point Thompson
back into the into
The main pipeline for imprudible. Yes
Has that been permitted?
pipe ordered
You know what phase that's in?
Yeah
chair Geesele I
It has not been
permitted
as a kind of a .38 .35 from our division.
What has been permitted is the line,
as I understand it, the main right away,
the AKLNG right way from Prudoh.
However, it's fairly typical process for us to permit
is part of our normal process at DNR.
Gotcha.
Yes, Senator Wilakowski, question.
Yeah, thank you.
There have been several settlement agreements
entered into an extension, September 10, 2018,
regarding the Point Thompson unit.
And the extension period was to continue until D&R
that either there's a financial and final investment decision on the Alaskal and G project or
I work on, the Alaska on G is no longer progressing.
I'm curious, what is the status of that agreement and extension?
Senator Willakowski through the chair, John Crowler for the record.
So that letter agreement dating to 2018, as you referenced, it provides a bit of a binary
path between a statement of abandonment of the project, which is obviously not the scenario
we're in, and a final investment decision on the
project which triggers some of that development benchmarks.
I don't want to speak definitively to what positions the Department of Law may take.
Because we do want to ensure that maximum developments occurring at the unit consistent on a timeline
That enables either phase one or phase two gas sales as necessary
So we have not triggered that FID action at this time
but we are
Working with the operator through the the process of reviewing their plans of development
for activity in the unit as Director Noddingham referenced,
I'm sorry for a little discursion here,
as director N
there is a well being drilled right now
with an intent of increasing
potential throughput out of that facility in that unit,
which we view as kind of consistent
with either phase one or phase two progress.
And we're going to keep looking both of
that letter agreement and the underlying settlement agreement
for how to make sure that continued activity
Is a focus
Follow-up senator Wilkowski could you just refresh us on the obligations that?
the operator had under the terms of that agreement and
What specifically they are doing and have done in the last six years eight years to to meet the Terms of That settlement?
Yes, Senator Wilakowski through the chair at a high level
the settlement agreement, and I don't have it in front of me, I would misstate the dates
to kind of describe it exactly, but it called for a series of investments in the startup
of the unit around the 2011-2012 timeframe to start permitting the development, constructed
and then put it into operation at the IPS, the initial production system.
Again, I missed the exact year, but shortly thereafter and a few years after that period,
due to the fact that it was fed by one well, there were some challenges hitting that volumetric
requirement.
The department worked throughout that time to encourage and promote continued investment
was focused on continuing to see that development.
And that prior negotiations and prior structure of the project
is what led to that 2018 letter agreement,
that in a sense, pause some of those requirements pending
that binary path of FID on the Project
or Banditment of The Project.
I think I skipped over the original settlement agreement
development in essentially kind of concentric rings of the unit, but also in scale for providing
gas by certain timelines. Because of that 2018 letter agreement, those timelines have
been paused. Were those original timelines to come back into place with a FID under the
terms of 18 agreement? We would see that activity hopefully proceed on that schedule.
You know, it is a product of negotiation and it's a very important thing for the state to see that development
And I think if the State is interested in
Negotiating with that that operator and owner group to to be as much activity there as we can and
The the indications of having a well-drilled this winter is encouraging to us that they're they are taking that commitment seriously
Follow-up cinder will casket so just so we're clear so it it says in the agreement
shall provide notice to all parties to the settlement agreement.
It shall continue until there is a final investment decision of Anne and
it's in capitals, Alaska LNG project.
Is it the department's interpretation that that was under a different project,
but that the current project is still under the terms,
still obligates the operator under terms of the settle agreement?
Senator Willakowski through the chair.
I don't want to compromise the states negotiating or interpret a position on this agreement at all.
I think we want
to preserve our ability to assert that the development obligations
consistent with the underlying leases, the original settlement agreement,
and the letter agreement can be as enforceable and appropriate for the situation as possible.
And particularly the situations we find ourselves in is the potential gas sales
And so, we would hope and potentially want to take negotiation or enforcement action under those agreements to make sure that development was occurring on track to meet action for either phase one or phase two.
Senator Myers.
Thank you, Madam Chair.
put out the maximum off-take at 3.6 BSCF a day if I'm
Doing if you remember right
Glen forn had said that their plan is to have the
export
facility set up to do 20 million tons a year of LNG and
I am asking if he please correct me if my math is wrong here, but I if i'm understanding it correctly
20 million tons a year translates to approximately 2.6 BSCF a day.
So what I'm seeing here is that at least right away Prudhoe Bay by itself would, unless
something has drastically changed in the last decade, Prudehoe by it self can supply the
gas line, atleast for the first few years, and so obviously we want to get point Thompson
We do have a little bit of time there.
Is that accurate?
Senator Myers, through the chair,
I'll speak to that, John Crow, for the record.
I will speak briefly to my colleague, Derek Noddingham.
I want to speak a bit more technically.
I think it's true that potential volumes of sales,
even at the phase two level,
may not hit the full off-take order approved by OGC.
And there might be commercial reasons or operational reasons
demanded at a different time. Obviously the AOGCC order would cap that so you couldn't go over it.
There may be strategic commercial royalty other decisions about sequencing of gas and so
it's not necessarily that we would want to excuse the lay term, you know, tap into Prito Bay,
exhaust it and then move on. We might want Point Thompson first, we might wanna blend first.
there might be divergent views about that.
And so I do think for phase two that the discussion is ongoing
and I think it's not necessarily that we have time so to speak.
But that's again why we're encouraged to see activity this winter
in a sense starting to potentially have more well-stocked
and be prepared for development at some additional scale.
follow-ups and reminders. Yeah, just a quick question for the AOGCC. I believe they said that
they that this off-take order for The Gas at at least at Prudo.
I was a sheriff point tops. It was included in that came out in 2015.
I always curious how often they update those off take orders or if they think that's going
to be updated at some point soon. If the gas line does start construction.
So commissioner Chimalowski, are you the one to answer that question?
Yes, this is Jesse Shamalaski through the chair. Thank you for the question on both orders were issued in
Conservation order 719 is the one that addresses point on some specifically
So the process for updating it is it has not been updated, but it still currently valid
So to the extent that it meets the needs of Glenfarn
It could stay as is
The process to renew would typically come from the operator of the field who wish to
renew it. So it could be Hillport for Prudoh, Hillcourt for Point Thompson.
So they would submit an application to update or revise the gas off-take order.
And then we would consider the information that provided
most likely hold a hearing and then issue a follow-up order, thank you.
Okay, Thank you, Senator Dunbar.
So Commissioner we had a presentation I believe it was last meeting
I've been too many weeks ago from Gaffney Klein that had very
Interesting very detailed discussion
About everything but in particular about what FID actually means and he described it at the consultant described is both sort of a moment
But also a process that could take potentially years
And so my question gets back to senator Wilkowski's question about the settlement
agreement at Point Thompson. Is it immediate sort of the first announcement of FID? Is that what
triggers it? Or is there some other technical or legal point along in that process that triggers
the settlement agreement? And do you anticipate it might be something that is either negotiated
or even litigated with the operator? Senator Dunbar, through the chair,
I appreciate the question.
I think as you alluded to in the final part of it,
it's certainly something that may be the subject
of negotiation or litigation as it is in legal agreement
and its interpretation application is material.
So I don't want to say anything that could at all constrain
the state's position.
I will say a little tongue in cheek, but also seriously,
if there's a interpretive space for the DNR commissioner's obligated to interpret it
as favorably to the state as possible.
And so I think that's the approach we would take on any interpretative question about
that agreement in light of the full balance of state interests.
So I know that may seem like a general response, but I
Effects development in the field is a very important operational and interpretive question
Okay, a brief follow-up again this this question is also a little bit tongue-in-cheek, but what does FID mean to you?
in this context
Thank you
Senator Dunbar through the chair
Not at all speaking as an interpretative question of the particular 2018 legal agreement or a
or meant to reference that in any way.
I think it is, you know, the department,
we deal with the question of FIDs
in a lot of different contexts.
And we obviously deal
with them in only the gas projects,
midstream infrastructure projects
as director, nodding him alluded to.
We, we see an interfield pipelines.
We also see mining.
We see other large industrial activities.
Very often it's focusing on securing financing, securing customers,
securing a development plan, a feasibility, and so all of those things I think are
relevant, but I suspect having not reviewed that presentation from Gaffney
Klein closely, you know, their discussion about it can be a moment in time or a
period. I believe that generally matches with, we see a variety across different
Thank you. Thank You Madam Chair
Right, I'll let you proceed. I don't see any other questions. Oh, Senator Wilkowski
What would what does the current plan of development at Prudhoe Bay require the operator to do?
I'm sorry point Thompson
through the chair senator Wilakowski in general it requires them to
ensure that
the production operations are ongoing and maximized or optimized to perform
any well work or necessary operations to keep their well flowing and
to drill this year in particular to
Gas off take rate from where it is, which is a suppressed level compared to historical backup
to the facility maximum of, I think it's around 200 million cubic feet per day.
There may be some other requirements in there that I'm not remembering.
I do have a lot of those plans of development in my head, but I
think those are the general requirements and the point Thompson POD.
Follow-up senator Wilkowski, and is it the department's position that?
Exxon for the last eight years or I guess so corp now is
Complying with all the terms of the plan of development and has complied with All the Terms of The Plan of Development and the settlement agreement
Senator Wilakowski through the chair John Crowler for The Record
Again, not not wanting to say anything that would
would compromise the state's ability to assert or litigate
any interpretive question.
We understand they have been actively developing the field,
producing from the one well to fill the IPS
to the extent of operational capacity.
And there were operational challenges,
both with the pipeline had had some issues.
And then there was also some some
issues around the reservoir and the well performance
over the last several years.
The operator has worked to respond to those and restore that and as director Noddingham
just eluded in our in their current POD program they're obligated to work on drilling this
well to try and restore the IPS to full capacity increase the gas handling.
We understand they are doing that, and pursuing that well and that's on track.
Follow-up.
Senator Wilkesky.
This is one of the largest gas reserves I believe in North America and it's.
extremely valuable condensate there. How many wells have they actually developed or explored
in the last eight years? And how much oil and gas have actually produced in last 8 years.
Senator Willakowski, through the chair, my colleague Derek Noddenham is wisely steering
me to our own chart, which shows those information, so I won't blend her through it. I'll stop
of our chart here in the lower left of that bar of four items.
The total barrels of oil and gas, natural gas liquids produced 19 million approximately.
As alluded to previously in this discussion, that has been for periods below that 10,000 barrels per day IPS target.
We've understood the operator to be working to hit that target, but it's only been hit for limited periods in that eight year period.
That's been produced primarily, I believe, from one production well and two injection
wells, and as discussed previously, having an additional production
well, which hopefully will come online this year, will be a very positive thing for meeting
that obligation and an addition production.
Very good.
You know, the questions on Point Thompson are important because it's
alluded to that the first gas for the pipeline, for
the AKL and G pipeline would come from Point Thompson because
of its low CO2 content.
But now we're aware that there's no gas pipeline there yet.
So that's very interesting.
Thank you.
I don't see any other questions.
I'll let you go on to slide number six.
Thank You, Cherokee.
So for record, Derek nodding him again.
talk about is one of the satellite fields of Prudhoe Bay North Star, the North
Star Unit. It's a joint state federal unit, 12 miles north of
Prude Bay. The resources that we estimate there are around a little less than a
TCF, so significantly smaller than Pruder Bay or Point Thompson. Nevertheless,
I can't do the math quick enough in my head
to understand how many years of cooking
that I guess that would be 11 or 12 years
of cookin' like gas, so to put it in context.
There is a gas line that runs from Prudhoe Bay
to North Star as we understand that was used
to actually export gas out of the Prude Bay field
into NorthStar for some...
gas for enhanced oil operations, actually more for fuel gas and those kind of things.
So, there has been imported gas into North Star from Prudhoe Bay in the past.
Could that 10-inch line, the line that exists be turned around and used for production out of?
I think that's a very good possibility.
I don't know that it's been used in quite a number of years though.
In the gas production rate, when you think about Point Thompson or Prudoh, Point
Thompson's injecting at 200 million cubic feet a day or so when they're up one step, Prudos
It's uncertain how much
Rate will come back from north star mainly because there could be some facility limitations or pipeline
Limitations that but this is one that
also does have what we understand to be a lower CO2 content than Prudo and I think could be
and it may have already been represented in the public as a potential first starter for gas
for the pipeline project. Gotcha, thank you.
So, let me ask Commissioner Chaimalowski, has AOGCC opined about use of the gas from Northstar unit?
Chair Casell, this is Jesse Chimalaski.
No, the AogCC has not considered producing a gas uptake from northstar at this time.
Thank you.
Thank You.
Further questions on slide number six.
Seeing none, I'll let you go on to slide Number seven.
Thank you, Chair Geesele. The next slide is the Duck Island unit or as more commonly referred to, I think, is Indicot.
So this unit is kind of an offshore island that's four miles offshore and two to 14 feet of water.
714 miles east of Prudoh. Resources there are around half a TCF. So a little less
than 10 years out of Cookinlet. And infrastructure unclear that they could
actually produce today back to the Prudo Bay infrastructure with a gas line. There
is an oil line obviously. They currently do sell some fuel gas to
the infrastructure might need to be a little bit more beefed up in order to
export gas out of here. I think predominantly the the main challenge would
be that the CO2 content is it seems like basically on public data it's fairly
high and so it probably not you know is high on the target list as a point
Thompson or North Star for first gas into the kind of phase one part of the
pipeline.
All right, I see no questions.
Slide 8.
Thank you, Chair Geesele.
So as we kind of move through this,
we're looking a little bit further south down
the Dalton Highway.
south of Prudhoe Bay to the Alcade to Leith and Tulek River units. These are the units
where we were earlier discussing that Great Bear Pantheon and ADA energy have
been doing of exploration and appraisal wells. There's several wells that have
been drilled and have and most have found some some oil in and well logs,
There's been oil produced to surface.
The outcade one, I believe, has actually tested over maybe several hundred barrels of oil and
a couple of million cubic feet of gas,
I think is kind of the test rates from that will.
However, in general.
Yeah, they haven't really found like what we would say is a commercial rate as of yet
It's still very much in a exploratory kind of appraisal phase
The the I guess one of the good things about this
Kind of ongoing exploration is the gas that they're finding that's associated with
With the oil has is fairly low co2 as we understand it
this type of operation that you'd expect to see down here is the the reservoirs are much
as far as I can tell, tighter lower permeability is what I mean by that,
then what you see at Point Thompson or Brutal Bay or some of the mega fields like that.
So the expectation is that the development would probably be more like a lower 48.
I guess shale development with really long horizontal wells with multi-stage
fracks and those kind of things in them.
The well tests that that we see we've seen and have understood from some of the the public
Information about them. There's generally been a
Reasonable amount of water that's come along with them
So we had they either haven't tested the wells long enough to see that water dissipate
or in general, the reservoirs that they found
may bring a lot of water,
and so that presents some facility challenges
to handle that water and dispose of it.
The gas that comes along with it really,
they don't necessarily plan on re-injecting that gas,
so they would need a place to get rid of.
and the AKLNG line would be a natural place
and a good place for them to be able to do that.
So that's where this really ties into the gas project
is there's, as you see there,
potentially over seven TCF of resource,
that gas resource that could be there
and needing a place
for it to go essentially.
Yes, and you're done bar kind of thank you madam chair. This is this is all you know
Way out in the future. You know this
Is a little bit more speculative, but he mentioned the need to treat some of the gas before it goes into the pipe
Can you speak?
about where that exactly would take place.
So for example, if the main treatment facility is in Prudhoe Bay,
and this is south of Prudehoe bay, would it have to be sort of shipped up to the treatment
facility, and then put in the pipe to head back down, or there would be another treatment
facility down here?
Through the Chair, Senator Dunbar, my understanding is that...
The CO2 in this gas may be minimal enough that it doesn't need to be treated in order to get down to pipeline specs.
For the Prudhoe Bay field, the AKA,
the Alaska CCUS.
facility is kind of the the plan for treating like the Prudhoe Bay in other
future gas fields that have a high CO2 content and that would be I don't know
exactly where to point to it on the map but just south of Prude Pruder Bay
field I believe. Thank you thank you Mayor. All right Senator Wilakowski is it a
facility in place before gas is developed and produced for the gas pipeline.
Senator Wilakowski through the chair, I don't want to definitively speak, but it's not a state
authorization. I believe the federal Department of Energy Authorization does contemplate some
requirement for CO2 disposal in sequestration underground.
facility reservoir available to accept the carbon.
Senator Willakowski through the chair, I think that a project to execute that project,
I'd have to let AGDC and Glenfarn speak to kind of their schedule for that at a phase two step.
We have our
Leasing and licensing regulations in place. We also have the possibility for storage and existing oil reservoirs
And we understand the AOGCC regulations are in in public process now
They might be able to speak to a timeline
But we think we're ready to to receive such an opposition
But there may be operational considerations and on a time line that Glenn foreign would be better position to speed to
I'll let you proceed.
We don't have other questions on the slides.
So now we're on number nine.
Thank you, Chair Giesle.
And this is Derek Nottingham again.
And This is the final slide.
And the slide really kind of just summarizes some of these characterizations that we've
been talking about regarding the facility requirements or pipeline requirements as we
understand them.
the resource estimates that are out there.
And with that, I'll just kind of open it up for any further questions.
Thank you, Senator Rousher.
Thank You Madam Chair, so I was just wondering,
60 miles of pipe or so from Thompson to Prudhoe Bay.
That shouldn't take too long to build, would it?
Through the chair, senator Raucher.
I don't know that I can speak of the exact timelines for building pipe, but I
don' t think it would take too terribly long, you know, if you consider that
the pipeline from the North Slope to down the keen eye is going to be 800
a couple of years, maybe is what I understand.
So it would definitively be less than that
if you kind of consider what some of the pipe projects
that have been done recently on the North Slope
with Willow and Pika and those have
been accomplished in one or two winter seasons.
So.
Follow-up.
Follow up, Senator Osher.
Do you know what they've.
Acquired any permits for future laying of that pipe so far
Through the chair, Senator Rousher, I'm not aware of any but I
Maybe just kind of out of the loop on the information so for man. Thank you
Further questions for Department of National Resources or AOGC which is online
All right.
Thank you very much for being here today.
With that, that ends the presentations today, I do have some additional information I want
to discuss today and it does not involve DNR.
So thank you.
You looked a little apprehensive there.
These meetings, one of the things I kept asking my staff is I want to hear from 8-star.
We know that Glenfarn has 75% of this project, but 8 star is holding the other 25% on behalf
of state.
So I began pursuing it and on your desks are what I found out.
And we didn't really get much of an answer, so we dug into it and I think you can see here on the first page the eight star contact information from the federal Department of Transportation fast 41 project dashboard indicates that eight-star is made up of apparently Glenfarn individuals.
So, that seemed a little odd to me, but you have that document there.
And then, well, there's several documents here that go on and on.
details starting on a page. This is from, I believe, the Department of DCCD, Commerce
and Community Economic Development. And so you see the date star is a limited liability
company and their home state is Delaware. They have a mailing address on C Street in
an old dairy road in Juneau.
My staff looked into that and there isn't anything there as far as we can tell.
So perhaps there's more information we haven't uncovered, but it doesn't appear that that's actually a legitimate address.
and it was signed by Mr. Richards but again I'm not seeing who who's who are the
board members that are holding the 25 percent that allegedly is potentially our
share and then you see yet another corporate registration document so I
I wanted to hear from these folks how they're managing our 25 percent and it's difficult
to find any board members other than the people, the Glenfern staff that make up the entities
act. So I wanted to just raise that issue. It is a concern. Any questions? Yes,
Senator Dunbar. Is there a comment and a question? I think a lot of Delaware is
sort of a fairly standard place to incorporate a corporation because of
their very, well, we have a
Court of the Chancery.
Anyway, there's a variety of reasons why people go to Delaware.
Have we spoken or have your staff spoken with Frank Richards?
I mean, it seems like he's listed on these documents and is...
Is he an employee?
He's an employer of state, correct?
Yes.
Okay.
I can just...
I may...
Has that been...
Has he been forthcoming with your questions?
We will be pursuing that.
Yeah.
Okay?
Yes, Senator Klayman is it was your staff finding that there's no structures at all at the eighty five eighty-five address old area
Road or just nothing that looks like the company
Let me have my staff come forward and answer your question
Anything else?
Senator Myers did you have a question? Oh, no, I was I know what's at The building
I haven't I have been inside enough to know. What is that the particular suite?
But I Know what in that building but if he's gonna if if your stats gonna answer then I'll leave it to him sure
For the record into my harvest and staff to Senator Yiesel through the chair, Senator Klayman to answer your question
We we have not physically gone to the building, but there's not a
Company with that name listed on the
On the website of the Building owner and there are a number of other businesses that are located at that site that
Are listed all that but this entity was not
It is the entity that the eight-star entity is not listed or the other one that's listed
on the listing, hold on, called Corporation Service Company.
That would be the Corporation service company through the Chair of Senator Clinton.
So the corporation service committee was listed?
They are not at that address through property management company that we could find.
So I'll be digging into this more.
If any members get information, that'd be great for us to know.
Because I'd like to hear from 8Star.
We're hearing from Glenfarn.
Yes.
If I may, Madam Chair.
Another interesting thing of note was that on all of these filing documents,
what you see is that 8 Star GlenFarn and AGDC all share the same address
and suite at their Anchorage office.
So that was also of interest.
So yes, Senator Myers. Thank you. So I'm no expert in corporate law here, but
it's my understanding that eight-star only exists as a joint subsidiary of
AGDC and
Glenfarn, so to me it doesn't surprise me that the only contacts we have
Immediately translate back to one of those two companies
This is apparently true
And so I will be asking these three individuals,
there are names right here,
to please join us at a committee meeting
and tell us about the 25% and how it's being managed.
I'll just add a-
I said a disclaimer.
In my life as a private lawyer that works
in sometimes corporate world,
this address is familiar to me.
It's familiar to me because I have seen other companies that have this entity as a service provider.
I mean, the general, it's very, very common for business entities,
especially out of state business companies, because they have to have an in-state service
provider that's listed.
It is very commonly to them to be a company that basically accepts service for them.
And so I recognize this addresses when I've seen for other businesses that.
to have this general address as their service provider.
The odd thing to me is that I want to know who's in suite.
Is it 205?
I wanna know whose at the front door of 205, because it may well be that this-
I said Google that.
But that's the structure not in suite 205 at the building.
So it might be Smith and Company, such and such, and then Smith & Company may have three
or four businesses within suite 2005.
I don't know the answer, but I definitively recognize that company as one I have seen
as the in-state service provider for other businesses that I was looking up at various
points in time.
And there's a number of other entities that you say find an in state service
provider.
10 different businesses in Alaska that are more than happy to for
annual fee to accept service for your company and then they ensure that your
company is notified and that checks off certain service and process providers.
So I wasn't, I'm not surprised by the fact they have that as their service provider.
Very good. Thank you. Well, I just wanted to share that information with the committee
We will be asking those three people that are listed to appear with us
All right with no further business today. Our next meeting will Be Monday February 2nd at 3 30
We're going to hear comments from Narsal
Producers related to the gas pipeline and their participation in it
So at this time the meeting we'll stand to just let the record reflect the time is 441 p.m