Good afternoon, everyone. Beautiful day today on January 21, 2026. This is the House Finance Committee
I'm Andy Josephson, the chair of the operating budget. I'll call this meeting to order
Let the record reflect that it's 132 on the 21st of January of Wednesday
present today are
Representative Moore
Representative Tomaszewski, Representative Stapp,
Representative Jimmy is absent today.
Representative Galvin, representative Hannon,
co-chair Schraghi, co chair Foster, and myself,
as I know to cochair Josephson.
Also present today are our House Finance Committee staff.
Normally, we have them introduce themselves,
but we're in year two.
We have committee assistant Helen Phillips.
I think of her as one of my many bosses along with Jessica Gary and my constituents and others.
We have a new page to Lula Lestufka, Secretary Brie Wiley, and Secretary Leah Frazier.
And Representative Thomas Shefsky is here.
We also have our moderator, Emily Mesh, from the Legislative Information Office.
Looks like she's training someone.
Also committee members are presenters and the public should be aware that our committee business today has a hard stop at 2 55
In today's meeting we will hear the Department of Natural Resources present the fall 2025 oil production forecast
With us today from the department is Derek and Nottingham
Director for the Division of Oil and Gas and Travis peltier petroleum reservoir engine year for The Division Of Oil And Gas
Representative Allard is not here for the record.
So I'll clarify that record,
Director Noddingham and Mr. Peltier,
please come forward, put yourself on the
record and begin your presentation.
Thank you, Chairman Josephson,
members of the committee.
For the Record, my name is Derek Naudingam.
I'm the Director of the Division of Oil and Gas, and on behalf of Commissioner Designy, John Crowder,
I wanted to just say thank you for the opportunity to present the production forecast today.
He could not be with us.
He got called away to a cabinet meeting.
He does look forward to the coming session and engaging with the committee over various oil and gas issues.
would like to say just kind of starting out just to give a little bit of a high
level overview of the production forecast and then I'll let my comrade
here Travis kind get into the meat of it but this is a really exciting year
because this was kind the year we've been waiting for we're gonna see new
production come online from Pika and Travis will talk about that a
little more. We've seen lots of progress over the last year in the PIKA project
construction activities, facilities being installed,
lots of wells being drilled.
And so that is a very exciting thing.
We've seen lots
of activity on the Willow project as well.
So lots
of progress on, the big North Slope projects.
You'll also see some information on just ongoing activities
like what we've witnessed happening at a field
like Milney Point.
Very, very interesting story that Travis will elaborate on,
but lots of really good positive things going on
in the production forecast.
And you'll see, as we look forward
in to the next 10 years, we're seeing the
production increase from where we are today upward
of 600,000 barrels by the end of the 10 year forecast,
so with that, I'll turn it over to Travis
and let him walk us through the presentation.
Thank you, Director, we've been joined by Representative Allard at 136.
Mr. Peltier.
Alright, thank you.
For the record, my name is Travis Pelter.
I'm a petroleum reservoir engineer in the resource evaluation section of the Division of Oil and Gas within the Alaska Department of Natural Resources.
Just for some background, I graduated from the University of Alaska Fairbanks in 2006 with a
Masters of Science in Mechanical Engineering and have spent the past 19 years working in Alaska's
oil industry. Predominantly on the north slope is a petroleum engineer for BP. In my 14 years with
that company, i worked all the fields they owned from The Capark River Unit all way west to the
Lucky and I joined the Department of Natural Resources and my current position as the petroleum reservoir engineer and in 2022
I was asked to lead the development of the state of Alaska's oil production
Forecast and i'm honored to continue leading that effort and the team that develops the forecast
By annually for the State so just to set context for today
We'll be talking about the Alaska is oil Production forecast for The next decade and for your awareness the department of natural resources has been performing this analysis since 2016
The goal for today is to share the production forecast results not just for fiscal year 2025
But also the forecast for the next ten years
Including methodology and background and how the forecasts is generated
And mr. Peltier we've been joined by representative Underwood. We like to recognize our colleagues when they're here. Please continue
Before we get into the meat of the presentation, I'm going to just briefly show, and that way everyone has this for reference, a list of acronyms that might be used during this presentation.
The one I am only going focus on for now, since it's used repeatedly throughout this is for...
On the left column, the fourth one down, B-O-P-D,
whether capitalized or not capital-ized,
stands for barrels of oil per day.
The rest of the presentation, if we use acronyms on a slide,
I have them in the bottom of that page
so they can be easily referenced.
But this is just a reference for folks
who want to come back to this.
Today again, we're going to talk about the forecast preview.
We'll just show everyone what the forecasts looks like.
We will talk fiscal year 2025 in review.
We go through then the DNR fall 2025 production forecasting
approach and how we generated the next 10 year forecast.
And then we'll get into the results in summary.
And if there are other questions,
we do have some material in appendix.
We don't plan to go
through that unless questions arise.
Please continue slide four.
Thank you.
So the fall 2025 nor slope annualized forecast is on this chart and just to put everyone on reference for how the charts look
They're all going to be fairly repetitive on the left-hand access for this one
We have the fiscal year annualize average daily oil production. So for instance, you know fiscal your 2026 hour internal forecast
is around
460 oh man now 465,000 barrels of oil per day
You can see that on the left-hand side of the chart the the y-axis goes from zero to a million barrels per
Day and the data points are single years for fiscal year along the x-Axis
What we have here is from the Department of revenues revenue sources book the Chart that represents low official forecast and high
can also be found in the Revenue Sources book,
Table 6-8.
We overlay on there because we receive this information
confidentially, but we roll it up for this production forecast.
The operators of currently producing fields
to compare our forecast against theirs.
And so that's what you see in
the dashed line, overlying these charts as well.
You can see there is a discrepancy.
For fiscal year 2026, the operator forecast is higher,
starting in fiscal years 2027, it's lower.
And again, I just want to reiterate,
the operators forecast
is for currently operating fields.
So this does not include in the Operator Forecast,
future fields like PICA are not included,
whereas in our forecast,
it is.
Okay.
Okay, let's go to slide six.
So we're gonna take a look at how did we do last year? What happened with actual field production?
So the next few slides will not actually have forecast information. This is a review so the fiscal year 2025
How do we actually do?
Just to kind of reiterate I'll talk to the chart on the the right in a minute
But every year when we put these
this
Together for the forecast we're looking to have basically an uncertainty within the next fiscal year of about plus or minus five percent
That's kind of what we were looking for our range of acceptability on the forecast
For this past year actual fiscal Year 2025 production ended up being 0.3 percent greater than the forecasts that we presented to you last year
I'll talk about that chart here on the right
to kind of elaborate that, just transitioning.
Same axis, it only goes from 0 to 600,000 barrels a day.
What we have here are a number of items in the bar chart.
On the far left, the high side of the forecast,
the DNR high, was I'm going to round here,
about 510,00 barrels of oil per day,
the low range that we had in forecast
was 424, 000 barrels oil a per-day.
the actual forecast was, or sorry, the mean forecast we had presented to this committee last year
was just over 466,000 barrels of oil per day, and the
actual ended up being just under 468, 000 barrels
of water per days. So overall, we were within that plus or minus five percent range, which we are targeting.
Mr. Peltier, question from Representative Hannon.
Thank you, Chair Josephson.
Mr Paltier your forecasting seemed to be on point,
but it looks like the operators were over-optimistic.
Do you do follow up questions back to them
of where that 20,000 barrels they thought
we were going to produce, didn't produce?
Or is that because it's aggregated data,
we don't know who, you know,
maybe 20 companies each predicted
thousand or is there a specific hole that didn't get drilled?
Through the chair Representative Hannon
We have we since we have the data at the field level we've interrogated that internally
But we had not gone back to ask operators specifically why they were over or under their specific forecasts
Again, we use the operator forecast as a comparator, but we don't rely on their forecasts to generate our own
We do them wholly independently
Thank you, please continue. Okay, and I was going to mention this
So thanks operator representative hannon for bringing it up the operator line on the far right of this chart
The last year the summation for all of the Operator responses was just under
487000 barrels of oil per day is our comparator for last
Now there are a couple things that we look at when we're shaping this forecast every year
When we ask operators for feedback about how things are going, you know
There's a lot of times we get similar responses from the various operators should work both the North Slope and Cook Inlet Fields
One of the things that we continue to hear is that industry interest and we've seen this
in lease sales as well, continues in the brookie and top set prospects, both on state and
federal land.
We might have heard, you might've heard in news, sockeye two ways, exploration results
just to the west to point Thompson, to east of The Badami Fields that came out this past
winter season, and that just kind of exemplifies why various companies are interested in these
Other exploration activities and opportunities on federal leases have also increased with the current administration.
We're seeing four wells up for exploration just in the NPRA this year alone.
Moderate oil prices and capital discipline across the industry are headwinds for development.
We do see that as well with our various operators in response to their provide to us.
Oil price does affect their operation.
And then inflation, relatively high interest rates
and insurance challenges are affecting
North Slope exploration projects, costs, and operations.
Representative Galvin, then, Stapp.
Thank you.
My question is regarding the last bullet
around inflation.
I know that in the, last year we were,
I think we experienced a couple of.
reductions in inflation, we went from 5% in January of 25 to 3.7 in December, for example.
I just wondered if you have a sense from hearing from the operators, what would their ideal interest rate be?
Is that a little puzzled by that being a deep challenge of theirs?
Mr. Peltier.
Through the chair, Representative Galvin.
Thanks for the question. So when we talk about inflation, oil field inflation is generally
distinct from kind of CPI inflation numbers.
So there's just general inflationary costs through the chair.
That's what we're referring to. This would be, I'd call it oilfield inflation. It's usually not
an order of magnitude higher, but a lot of times I'm not going to say what the operators told us.
back in the, I think, kind of 2010 to 2014 time frame,
you know, the consumer price index might go up
at 2% per year, but oil field inflation
during that time was 10%.
So year on year when you're seeing prices increase
like that, it does get hard to continue to develop.
And that's what we're saying here is just
Oilfield inflation has been running hotter than the CPI inflation number.
Okay, thank you through the chair. Quick follow-up. So that would include things such as labor and
subcontractors and all of those pieces that they're just prices are going up.
Okay. Through the Chair, Representative Gavin, yes. Thank you. Representative Stapp.
Thank Coach here, Joseph. Through the chair to Mr. Peltier. Always a pleasure.
Thanks for being here. It's great to be back and great first meeting, Mr
Co-chair. Nothing like the oil production forecast to get us started on the year, I think.
So, regarding point three and four on first oil pricing capital discipline, we've seen
a kind of a remarkable investment in capital and not only in existing infrastructure exploration
wells and this year and last year from our wonderful partners in industry.
Do we know how we compare to other areas of the country given this kind inflationary
A place that people are looking at these plays that you mentioned sockeye too, and it seems like industry is going to
Relatively high risk to continue invest in our state. So that's my first question to the chair
Mr. Peltier
Through the Chair representative step
So, the comparison of inflation from the lower 48 up here, I can't unfortunately speak to.
I think what I could illustrate and share, again, this would be qualitative, not quantitative,
is that costs to operate in Alaska are generally significantly higher than they are in the
You know, you can talk to various folks who work down there versus folks
who worked up here, but, and again, this is qualitative, not quantitative,
but it might cost,
you know low millions of dollars to drill wells up down in the lower 48,
and to draw a similar wells-up here might be multiples of that.
Okay, I'll follow up.
Yes, follow-up.
Thank you, Mr. Critter.
Through the chair,
Mr Peltier.
So this one's going to be
relatively simple.
Given the fact that we have a
lot of capital investment
from industry in the slope,
and we are having new
production, even in
the face of moderate price
declines in, again,
companies performing capital
discipline and even layoffs in
some case, what would be the
worst course of action that
we could take as a
legislature to disincentivize
that through the Chair?
That may be for the
Director.
Yes, through the chair, a representative step.
I don't know that I can speak to what the worst course of action the legislature could take, but
I will say that maintaining a very competitive environment for
Alaska business, whether prices are low or whether they're high,
is probably the best course in action for the state.
You know, we are in a competitive industry.
There are other places for companies to invest their capital dollars.
And, you know.
So whatever edges the state of Alaska can maintain for its competitive advantage,
I would hope that the legislature consider that strongly.
You said it's west of Point Thompson. I've had the pleasure of visiting Point
Thompson and is it the Canning River is also west
of point Thompson? There's disputed land there that's still being litigated and
I'm just curious whether the interest you've described in the bullet is in that
river Delta in disputed area or is that undisputed area? Yeah, Chair Joseph Sin
I believe the Canning River is actually on the east side of Point Thompson the border between the NPRA and the state lands
It's a contested area and The Sakai 2a is definitely west of point Thompson
So nowhere near the disputed lands area for that specific river
Yes represent Gilman, thank you through the chair, I think I misspoke earlier when I was talking about rates
I really meant interest rates
Interest rates are dropping, I would guess that would be helpful, but it still says, though, that they are, the operators are suggesting that high interest rates
are still a problem, and that's what I really wanted to get at with the interest rate, not so much as inflation.
Do you have a comment on that, like what is an ideal rate then, if there would
Mr. Peltier or the director. I can give it a go. All right for the record. This is Travis Paltier
Through the chair representative Galvin. Thanks again for clarifying the question for
The interest rates, I believe this is more of a threshold for private loans in financing
So again, the if you're referencing interest rate that are put forth by the Federal Reserve
I know those are public, private industry typically has to pay a significantly higher interest rate to get loans for new developments.
I don't know what those numbers are, we could get back to you with some information about that, but I suspect that's going to be difficult because those were usually held very confidential.
I see through the chair, I may.
So you're referring to interest rates that are not the federal interest
rates, it's whatever is on top of that that through private lenders.
Is that what I'm hearing?
Representative Galvin. Yes, there's no need to get back on that. I think I can figure that out. Thank you
All right, let's go to slide seven if we're ready
Yes
So this is a chart showing similar information as we had on the previous one
We we the Department of Natural Resources introduced it last year. This simply shows the 12 month forecast broken out by month
We hadn't pre prior to last your release this information publicly
So, just to orient folks, because we'll see this chart again later on with the actual forecast embedded in it.
We have here on the left-hand axis and a right- hand axis.
The left hand access is the oil production rate in barrels of oil per day.
from zero to 600,000.
The orange curve that goes on the top,
that you see the high frequency fluctuations for,
are daily production rates.
What you'll see there overlaid with the purple,
and you can't really see it in the forecast with blue,
because early on in time we had a pretty good forecast
overlaying the actuals.
But you will see a divergence there at the end,
is the monthly forecast, along with
average of the daily run tickets monthly to compare what we put forth in a forecast internally.
Again, we have a monthly frequency, so we can see how those daily averages are turning into the
monthly. If you take a look on the right-hand axis, you have cumulative production in millions
of stock tank barrels. So that goes from 0 to 300 million barrels in the axis. That intercepts
Straight line effectively overlaying a dashed blue line. Those are the cumulative volumes and so those go to the right-hand axis
The forecast last year was roughly a hundred and seventy million barrels in total and that's about where we got to
We were again slightly under on the forecast actuals came in slightly higher
But just wanted to kind of share the chart for reference,
and this is what it looks like when you take a look at dailies
as compared to our monthly forecast that we hold internally.
And we'll, again, share actually an 18-month view later on
to show the effect of the PIGA development
that will be planning to come online,
that is planning come on line later this year.
Representative Hannon for Mr. Peltier.
Thank you, Chair Josephson.
Mr Paltier, just to make sure that I'm...
Understanding this correctly because if I look at this it looks like we start at zero
But that's just your start it zero at the first day of the fiscal year and
The only point that really counts is the conclusion at The cumulative on the far right. So it's not that you were under predicting
That dramatically the left axis telling us that it is The Cumulative Difference
Through the chair, Representative Hannon, thank you for the question.
Yes, the way I would take a look at this, and unfortunately again,
the cumulative forecast,
the dashed blue line, it's very hard to see because the orange line overlays it.
As you go through the year, there would be a gap.
If the forecast is off,
you'd see a get between the straight orange
line and the blueline that's underneath it,
and that the gap you would worried about.
If we're under predicting in any single month.
you'd start to see a divergence. And that's, I think, what you finally see there at the end of
the chart in May of 2025 in June of 2025. You can see up and up above the daily actual production,
the run tickets run slightly higher than the forecast.
And so that is where you see the orange relatively straight line down below that represents the
cumulative. Finally starts to outrun the cumulative forecast volume. But the difference here is
Yes, yes follow-up and I was
Thank you co-chair and mr. Peltier in the previous slide you used a range of a 0.3 percentage
Greater and i think you said you like to have it within 5% or was it 3% and so doing the quick math
We're within that range, of our cumulative forecast. Yeah through the chair representative hannon
Yes we are within the plus or minus 5 percent range. We are targeting yearly
All right slide eight, I believe
So again, we haven't gotten into more forecasts
This is a review of field performance and actuals for fiscal year of 2025
Just to kind of refresh folks
You know the oil fields that we have in the North Slope and have been producing for decades
Feels like the Prudel Bay unit the Capark River unit and every year we expect these legacy fields to you know generally see a year-on-year decline
They're mature, the operators are reinvesting in them and getting the most out of them that they can from an economic perspective,
but still just the age of the fields themselves. The year-to-year decline is what we typically expect to see out
of fields this large that have been producing for this long.
However, in fiscal year 2025, as compared to fiscal
year 2024, all of the North Slope production actually increased.
So the whole basin on the north slope went up roughly 7,000
barrels of oil per day, which is a great new story.
And it does show the increase of investment and reinvestment
on these legacy fields.
Would I have on the chart, uh, charts on
the right? There are two of them.
The top one is fiscal year annual average
daily oil production for the entire
North Slope going back to fiscal
year 2019. So you broadly see a
decrease back then from 495,000
barrels of oil per day with some
fluctuations due to the COVID pandemic
going from 2020 into 2021.
but broadly declining down to 2025 where you see the 468,000 roughly barrels a
little per day averaging for the past fiscal year. On the chart on the bottom
what we have is the breakdown just in change between fiscal your 2024 versus
fiscal years 2025 so we can talk about which fields explicitly increased in
production and those which decreased.
I'll speak to the chart. The bullets are the same for the bottom chart
So I'm just going to speak the the charts but the bullets on the left hand should correspond if you want to read the
Bullets as well the decreases that we have in the fields are at the Colville River unit the
Greater Musa's tooth unit
The Perda Bay unit, we'll see those of all declined.
That is mostly due to natural decline offset
with development drilling when you lump those in.
And then we have two other fields that have gone down as well.
That's the Endicot unit and the North Star unit.
There was no development, drilling, no new wells,
drilled either of those two units this past fiscal year.
So what you see there and those volume losses again
in terms of barrels of oil per day
is natural reservoir decline.
One point I want to make about per debate the unit itself makes over 200,000 barrels of oil per day
So having a decline rate less than 2% is pretty phenomenal for a field that large
This is the backbone of the volume that makes into the trans-elaska pipeline system. So the operator there is doing a great job
Ensuring that reservoir decline is mitigated as best they can do it
I'm struck by who parks performance given that it's also a legacy field at this point.
Is that fair?
That they're going great guns there, apparently.
Right.
So that's on the increases side, Chair Josephson.
So if we go on the, the increases last year, we did see increases at the Capark River unit,
I'll skip to that one since you brought it up. And the operator there, Conoco Phillips,
has done excellent base performance and they've done a lot of new drilling. There've been some
new projects that have gone on there. We had a project last, year we brought through here,
I believe it was called the Coyote Project or the KRU Nuna Torok Project, depending on
the version we had brought forth. I can't remember which one we shared.
That project has come online with great success
that affects the Capark River unit.
Along with that, they've had some additional positive,
well-resulted out of the Schrader Bluff unit,
drilling their viscous oil as well.
So the capark river unit has seen some nice,
positive benefits from the increased development drilling
they have had at the field.
Along With that the Badama unit also increased
for similar reasons.
They had a brand new well, B-133A.
Prior to that, this one new well actually out-produced the rest of the field combined.
So a very successful well for Badami.
Milney Point has been a perennial increase in production rate.
And that's been the infill drilling program that has gone on at Milne Point now for years.
We continue to see that production growth due to infil drilling.
We hope to see more out of Milney Point.
We'll see you next year when we meet again if that production rate continues to increase,
but I know the operator is doing what they can to maximize production out
of the field there as well.
And we have a specific slide about Milne Point in the future to talk about
the activities that have gone on there.
Then the kai check of gurik and point Thompson fields along with southern
miluvietch. Actually, I'll hold southern milvieth for a minute.
The kayakak and kaya check and guri can point
Thompson also production increases as well last year.
For Point Thompson specifically the large increase was because the prior
fiscal year the pipeline had been shut down for
a number of months. It froze during a production upset in January
and it didn't unthog in until the summer months when production was restored in
year 2024. So, fiscal year 2025 saw a nice production increase associated with that.
And then a new positive story, the Southern Maluvius unit is a New Field online. It was a
project for us last year and it's new to this chart. The production rate is relatively small,
just given when it finally came on in the fiscal years. But we've seen a lot of positive things
out of this and next year we'll even be able to share a more positive stories about that New
Mr. Peltier the point Thompson is known for gas and condensate is that right? Yes, and but this is not condense. This is oil
It is condensation production. Yes if they we call it oil production barrels of condence a per day barrels
of oil per Day the
Biggest difference when it comes to the liquid sales like that is there's a quality meter on your grade of Oil
So points Thompson will have its own different grading sold at its quality bank
But it's all lumped under oil production broadly, even if it is condensate.
Okay, Representative Hannon.
Thank you, Chair Josephson.
Mr. Peltier, because the point Thompson was a restoration, so
the chart is accurate compared to the prior year because it lost a year.
How does it compare to proceeding year before we had the pipeline error?
Are we up from that or are we?
through the chair, Representative Hannon,
that's a fantastic question.
I'm going to answer it in twofold.
One is I'll just get to the last bullet point on the slide.
Detailed field charts are publicly available for view,
so we can dig down to anybody in the public,
can use the following link,
and you can get down the well level
across any field on North Slope using that.
To answer your question specifically to Point Thompson,
if you were going back to fiscal year 2023,
you would see a large decrease in,
point Thompson 17 and that well did decrease in production from fiscal year
23 into 24 not just because of the pipeline. There were some challenges with
the well itself losing productivity and so while it is increased it hasn't gone
back to where it had been. The current operator is actually remediating that
and trying to refill the production facility and we'll see how that activity
Okay, slide nine
All right
Again, just for the record. This is Travis Peltier
We have a detailed slide here on slide 9 talking about the milli-point unit in the history of this from the prior operator
BP through the current operator hillcorp
We wanted to highlight a few things on here, but again just to orient everyone to the slide
This chart is slightly different.
It comes from a different system.
The left-hand oil axis is in oil and plus NGLs
or natural gas liquids.
That goes from zero to 60,000 barrels of oil per day,
represented by the letter K.
That's a Microsoft thing.
We couldn't change it, unfortunately.
So we had to leave it with K, it's not typically
an industry note.
We usually use the Letter M.
For so that's the oil production rates on the left-hand side and on
the right hand side of this chart we have water production
rates that goes from zero to two hundred thousand barrels of water per day.
What we had for oil
production the rate itself you can see in green just for easy reference on
color.
The water is represented by the blue dashed line but there's no coloring
underneath it.
What we see here going back all the way to 1995, this is a calendar year now, not a fiscal year.
These are monthly data points going to our latest data point, which was November of 2025.
In the prior operator BP, when the milling point was predominantly a Coparic light oil
field, Copark reservoir, light-oil field. The maximum production rate was in July 1998,
just under 59,000 barrels of oil per day. And while BP was the operator,
That production rate declined down to about 18,779 barrels of oil per day in November of 2014.
At that point in time, BP had sold the asset to a company called Hill Corp.
no-corp ticket over operator ship in November and have ever since been working on stabilizing
the field, which they did in the first few years of their operatorship, and then reinvesting
into the Schrader Bluff sands, the more heavy oil, viscous oil that BP had not developed
as much.
from that capital drilling program that's been ongoing since prior to 2018, but full-time since
2018. So along with that, Millie Point has invested new technologies in what is called
polymer flooding, so something else BP, the prior operator, had not done.
And both the new drilling along with the polymer flooding combined have seen field production
rates now increase over 50,000 barrels a day in aggregate.
So the last month we had data for was only 50 nine hundred and six barrels of oil per
day.
So I think it's a great success story showing that a new operator can come to the North
Slope, bring new ideas, new thoughts, technology, and execute well and do excellent things
Yes, Jim, may I add something to there?
Of course.
Yeah, thank you.
For the record, Derek, nodding him.
And I just want to point out that in, you know, I've been in the industry probably almost
30 years now.
I have to go back and look, but it's very rare you see a revitalization of a field where
you almost duplicate the peak production of oil.
layer down the road but it never usually gets back to that previous peak and the really
outstanding thing that's happening here is the makeup of the oil is more of a viscous oil. It's
from a reservoir called the Schrader Bluff which basically it's a thicker heavier oil than the
to handle that. So the operator has gone out and done a remarkable job in adjusting the
operation, how they're drilling the wells, but also in the facilities to make them and
adapt them to, handle this amount of oil again.
Thank you. And Hillcorp is known as a re-developer and someone who excels at this.
through the chair Travis Peltier so we have here on this slide is a status
update for some of the key nor slow projects this is not all of them but
the ones we want to highlight today just these five projects
I'm going to start off just in broad with the categories are so we have the project names
pick a phase one pick of phase two in willow our brand new projects for brand
new fields and then the last two projects the Colville River unit CD8 project and the
Share why there's a top and a bottom to this slide. There is a difference between brand new fields and the risk associated with that along with
Putting a new pad in an existing field generally lower risk lower cost
So with act let's talk about pick a phase one
Last year when we had the opportunity to meet the operator Santos was doing construction and drilling activities
Project's first oil was anticipated in the second quarter of 2026 and now we are in 20 26
And pick a phase one is more than 95% complete.
Commissioning works are underway in advance of that first oil.
And we actually now anticipate first
oil in the end of the first quarter of 2026.
The peak rate is estimated to be at 80,000 barrels
of a day for this project.
That won't be on day one.
It's going to ramp up to get to 80 thousand barrels
of oil per day.
But pick of phase 1, we're expecting
to make 80 thousands barrels of water per
day with the hope for expansion.
in two other adjoining fields, I'm told?
Yeah, Chair Josephson, yes.
Pick a phase two is how we've kind of classified that.
We actually have internally what we call
a pick a face three as well.
That is a, last year when we came again,
pick of phase 2 was in a conceptual engineering,
cost estimation stage.
We had seen public plans for that to move
to what's called a feed stage
or a front end engineering design stage in 2025.
and then a financial investment or final investment decision in 2027.
How that's kind of progressed over the past year. Now that we're in January of 2026,
Santas' focus is completing phase one. So rather than getting distracted by phase two,
they want to get phase 1 into first oil before proceeding on phase 2 of the project.
Phase two has traditionally had a new pad associated
with it and a production expansion.
And so we expect phase two to have an additional
80,000 barrels of oil per day potentially added to phase one.
So the total, if you add pick a phase 1 and pick
a Phase 2 together, you get 160,00 barrels
of water per days, potential when both projects are online
and at peak.
Fantastic.
Representative Hannon.
Thank you, co-chair Josephson.
Mr. Peltier, I have in the back my mind
that Santo sold or changed ownership.
Am I incorrect?
Or they just kept the new owners
but same name of operational company?
Sure, it's true health here through the chair representative hand and I think it depends how far back you go
So if I go too far, back, please forgive me
Once upon a time there may be the most I'll do the more recent reader iteration first
So Santas bought the company bought a company called oil search and they're both Australian companies
Oil search has an Alaska subsidiary called Oil Search Alaska. They're a 51% owner of
the pick-up field, both for Project Pick-A-Phase One and Pick a Phase Two, fifty-one percent.
The other major owner is Repsal, who has a forty-nine percent share.
If you go farther back than oil search, having the fifty one percent, I believe Rebsal had
a higher working interest donor percentage at one point in time in history, upwards of
a hundred percent but I'd forget the details and I have to get back to you on that.
But still with the in Alaska the name oil search Alaska. Thank you
Okay, and
the names for the pick of phase two are
One is horseshoe and the others. We'll hear these names a lot in the coming years qualca or something. Yeah
Coach or sorry chair Josephson
referencing Horseshoe and Quaka,
those are distinctly different projects from Pika.
So I'll have the map later on showing where those were at,
but they're wholly distinct units,
even within the North Slope.
Separate from pika?
And separate from pick a phase two.
Yes.
Wow, okay.
Yes, so you're gonna talk about Willow a bit.
Yes so continuing on the next major project we have
is a Conoco Phillips project.
last year when we met that project construction had started first oil was
anticipated in 2029. You know the the end date I know I'm going to kind of skip
on the first list that remains on track in
20 29 but the project is now more than 50
percent complete. The Willow central facility is currently
being constructed in
Oh, Texas, got taken out of it appears.
This plan for transit to the North Slope in 2027.
So from where it's been constructed,
we expect to see that Willow central facility up here
next calendar year at some point.
So pretty exciting, the Willow project itself
is expected to have a peak rate
of 180,000 barrels of oil per day.
One thing to distinguish this project is it is mostly located on federal I think it's all located
on Federal lands. We'll have a map showing that in the future whereas pick a Phase 1 and pick
a phase 2 are a mix of state and Alaska native acreage. Moving on to the projects that are new
paths within existing fields we have the Colville River Unit CD8 pad. So this is a project that
Early in 2025 with the environmental impact statement undertaken
by the United States Army Corps of Engineers as the lead agency.
So where we're at now in January of 2026 is the U.S. Army
Corps Of Engineers has created a notice of intent as of September 9th
of 2025 and stakeholder engagement is ongoing.
There's a draft environmental
impact statements comment period in effect now and it lasts until the fall
Shortly after that, a record of decision for the project is planned for early 2027.
The project's expected to come online for first oil in 2030.
So, still a ways out, but work underway.
For this one, we didn't have a public estimate, so we are sharing our internal estimate
for a mid-case for CD8 project,
so the DNR rate estimate for this is about 20,000 barrels of oil per day in the mid case.
Sorry
Thank You co-chair Josephson through the chair
So all these projects here 80,000 160,00 180, 000
that kind of takes me back to slide four where the
North Slope
Forecast the high was about I mean just off the chart here. I'm looking at about
975, if I just kind a guesstimate for the hi forecast and it's
All due to these projects we just talked about is there anything that's going to derail those projects
Do we see I mean we're being optimistic obviously we want to be optimistic
But is it anything? That's gonna derail?
Those projects or do we kind of anticipate that our high estimate on that forecast page is going
To be pretty close to being what we gonna see
Mr. Peltier, yeah, through the through-the-chair representative Thomas Shasky
The way I'd kind of look at slide four, yes there's a high forecast and a low forecast,
when we put these together the official forecast is what we use for these, not these estimates,
but these numbers represent our mid-case ranges that we have in there. So what I would call the
When they sum up in getting just under 700,000 barrels
of oil per day, I think is a more representative case
of where they could be.
I'd kind of mention plus or minus 5% per year
on a certainty for the next year on the forecast.
Each year that uncertainty grows.
So we're never sure if a project will be successful or not.
We hope in bulk all the projects yield a success case.
And we'll look at those later on in the slide deck.
I don't recall the Slide number, but we do have a forecast
That's it.
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But again, with the uncertainty, the high case and low case, there's a chance that some
projects don't come online and you don t see these large volumes and that's what the low
case is meant to represent is kind of what a low range can be and it's the same for the
highcase.
If the volumes are significantly better than anticipated, you know, I'd say the probability
is not as high as the official case right?
That's where we're going.
But there is a change that could be significantly bigger than we had originally planned as well.
and the low cases are meant to represent
as just that band of uncertainty.
And that's why it increases through time.
Thank you.
Representative Stepp.
Thank your co-chair, Joseph, to the chair to Mr. Peltier
or Mr Noddingham.
So just want to take kind of a bird's eye view
at this, taking a step back.
We have in front of us a chart that talks about basically
an additional 400,000 barrels.
a day in production and just putting that in context you guys been at this a long time
like when's the last time you've been able to sit in front of a legislative body like this
and talk about these projects and there's probably half a dozen projects that aren't even on this
list that are kind of floating around there sockeye too you mentioned um at these levels of new
production in really our state's history through the chair either gentleman mr. Nottingham
Chair Josephson, for the record, I'm Derek Nottingham.
I've been in this role for four years and we've
been talking about these projects all that time.
But we have seen them go through various stages
and lots of challenges over that
time, the thing that's different about this year
There are literally boots on the ground.
There're facilities being installed.
There's lots of money being spent.
Like Pika is at a point where there's no, you know,
there is no going back.
There is going to be production coming online.
Willow is very much into the project.
So these things are becoming reality rather
than concept at this point.
I hope that kind of gets to your question,
Yeah, follow Mr. Coachear. Yes,
follow up, where was the step?
Yeah. I think coachere through the, through
the chair. Yeah no, the reason I bring
it up is because I mean, this is kind
of like an historic moment in the
state's recent history, right? We've,
we've talked a lot about declining
production, I'm 38 years old,
right, so this would be the first time
in my lifetime that Alaska is actually
going to see an increase, like a
substantial increase in production.
I am not talking about 2000 BPD
year day or something like that,
but this will be a substantial
increase and production and I,
Kind of take the time to recognize that that moment came with a lot of grit a
lot a challenge massive capital investment through industry and a
lot at time. I'm old enough to remember when we talked about our last tax
structure that we were gonna have fruits of our labor and production and you
know they might have been wrong on the timeframe but here we are you know over
a decade past the road kind of seeing those things come to fruition. So with
that being said I do have a question regarding
Other projects that have been out there,
I'm sure you'll talk about in the future,
that I had did not make the list.
So, SOC-I2, for example,
and some of the other minor kind of projects.
So I am curious what determines whether or not
you put a status update on a list on this slide
and what determinants that you don't through the chair.
Mr. Piltier.
For the record, Travis Peltier, through the chair,
representative Stapp, to answer your question,
what projects make it on this list and which ones do not?
So this specific list, I wanted to put the large projects
that are either right around the corner,
or extremely material to the future production forecast.
So that's what made it in this top five list.
You call it a top six if you include iPad, no pad separately.
Later on we'll have a map showing all the projects that were included in the production forecast for the North Slope
And then there's one project for The Cook Inlet as well that we have in here
In the aggregate forecast as Well those projects we do
discuss every year
The criteria for that if you know if your interested in The details is really around do we Have?
Development Plan is this a known resource?
Does the operator actually have an intent to develop this within the next ten years?
There's a lot of discussions around what does and does not get included.
So if you're also talking about years past,
some projects that have had challenges that we've dropped from the project list,
you might remember something like Liberty as a for instance.
We didn't think that one would come online in the next 10 years,
so it's no longer a project we're including.
So there are projects they have been on and projects could have fallen off and we have a-
That's the criteria is basically at those is will be on in the next 10 years is their development plan has there been a known resource actually found to support that
In a quick last quick fault. I'm sure follow representative step coach here through the chair
So I am glad you mentioned Liberty cuz I I always kind of curious when we talked about these projects
We don't think about all the times that and it's not been that often
But we have companies that are spending billions of dollars at their own at-risk capital to kind
Of develop these products and sometimes they don t work out
I know that so one of the other representatives mentioned that I mean how often does that happen?
How often doesn't a private company go out and spend tons of money in Alaska and then
You know, they go for broke and then they don't come up with anything and now they're on the hook for all that expense to a chair
Look through the chair representative step. I'll share a story about I guess two different projects for an operator
It no longer works up here
But if you go all the way back to Prudhoe Bay, Prude Bay is an amazing story, right?
It's a field that when it was originally developed, only expected to make 9.6 billion barrels of oil,
it's significantly over that.
Now, billions of barrels over.
Billions of burrows over there.
But then you have other projects that haven't worked out in the past.
Per the operators' original expectations, again, picking on BP
since they're no longer here, is the Badami field.
If you take a look at their expectation for that field, it
in peak, I think it was around 35,000 barrels of oil per day.
And it came nowhere near that.
I mean, the fourth day of production was peak rate.
If you had the daily data, and it's just under, it is under 20, 000, but I
think that was 11,00 total.
The monthly production rate averages significantly less than that,
and a decline down to about 1000 barrels
of water per
day, again,
I'm rounding here roughly for most of its production history.
until the B-133A1 was recently drilled.
So I'd say that one didn't work out in total.
Yeah, thanks.
I'm thinking of Shell's efforts in the Beaufort Sea.
Of course, there's notorious.
And there was a, I think, Calus wanted to develop Smith Bay.
Is that right? And that didn' happen.
Although Ugaruk is near there, maybe?
Chair Josephson I can speak to that for the record Derek Nottingham. Yeah, Shell did make efforts
I
Can't remember the exact year but to to explore in the Beaufort Sea that turned out to be very expensive and
very hard to plan for it cost them a lot of money and they essentially
Kind of a band in those efforts
so the the recognition
that Alaska has a lot of resources there.
There are extreme challenges some places,
you know, where the location is so remote
that the equipment to do those kind of operations
is, so specialized that it gets really expensive
and things have to go almost perfect
to find the oil, appraise it.
and develop it. So it does present a lot of challenge. Smith Bay is another area where a
lot resource has been found, like you mentioned by Kaylas back, I can't remember those exact years
either, but it is in a remote location. It's state land, it's out in state waters,
the previous federal administration presented a lot of challenges for operators,
explorers to go out and explore even state lands because of the access generally had to be through
the NPRA. So those kind of things are, you know, our history of development or resources are
kind a lace with some of those really logistical challenges, some
Representative Moore question. Yeah, thank you chair Josephson through the chair
Can we get an update on the pika road access with it being on federal lands and having the state and
Boundaries and such in the summer. I know there were some issues and then in winter
We use the ice roads to get there and that doesn't seem to have a lot of jurisdiction issues
But where are we at with update? On that?
Through the Chair
Representative more
The PICA road access issues are pretty much resolved in that Conoco and Santos have come
to a use agreement, a mutually agreed to use agreements, there was legal action that was
I believe that I'll get the, I'm not a lawyer, so I will kind of try to step through this as best I can.
But there was a ruling,
I think in Superior Court against the state's position on that.
And in our efforts to bring that to the Supreme Court during that time,
The two companies mutually resolve that issue with a commercial agreement and therefore the,
I believe the Supreme Court ruled it a moot point and vacated the Superior Court's ruling on that,
but we can get our Department of Law to kind of follow up on the specific details, but I
believe that's where that is. Follow up, Representative Moore. Yeah, thank you.
Thank you for the update, and so there's no projected delays for Pika going online
Because of the road access. Yeah through the chair represented more. That's that's correct. Thank You
Let's go to slide 11
For the record, this is Travis Peltier
Do you want to chair josephson could I just finish the last project?
I'm okay. Thank you. It's like 10 so on slide 10 the very last
Project I'll just address this very briefly is a brand new project in the Prudhoe Bay unit
This was not included in a projects list last year
We didn't present it to this group last last
Year and this is project again hillcorp is proposing to move forward on its two new pads in
the prudoe bay unit
You might see it referred to in the news as Omegapad and iPad.
You may hear it refer to as Project Ta-taiga.
It all refers to the same two pads being developed
on the west side of Prudhoe Bay.
The first pad is expected to come online with first oil
in 2028, and the second pad expected
to comes online sometime between 20-28 and 2030,
depending on when the final investment decision is made.
FID will be in 2020 to 2030 with first of all two years after final investment decision. Sorry for that, misspeaking.
Peak rate for both of those pads when online could be as high as 40,000 barrels of oil per day.
Okay.
Slide 11.
Slide, moving on to slide 11 in the Cook Inlet Basin. So we're just again showing highlights from
the basin itself from fiscal year 2024 into fiscal years 2025.
Cook Inlet Basin declined roughly 8%.
So again, the Cook inlet basin is actually
the most mature basin in all of Alaska's assets.
This has been on since the late 1950s for all the oil fields.
A lot of the oils fields that are down there
have been online for over seven decades.
So quite a long time.
So, again you're expecting to see
you on your production decline.
8% for Cook and Land where it's currently at now
is about 692 barrels of oil per day.
Production drop.
And just to kind of highlight, the Cook Inlet Basin oil supply
supplies in-state refineries.
And so it's pretty critical that we continue to maximize
this resource as best we can.
Hillcorp operates a lot of the fields down in the cook
inlet.
Their priority is natural gas development
out of necessity for consuming to ensure homes are heated,
So if we take a look at, I know I'm being cognizant of the time,
I am just going to jump down to the production chart where we have production changes and just in bulk.
I'll say that again, there's not a lot of new wells being drilled at the existing fields down in the cook endlint.
That's why they all have, production drops.
All ever experiencing natural decline. There is well work that Hill Corp does at all the fields sometimes
Like you see with readout shoal the production that is or sorry the the wellwork that has done actually
Overcomes the decline rate that you'd have for the year
So that's why the read out shoel number is positive was the work. That was done there over the years
It's not a new well
It just it ended up being a net positive number everything else, you know
They're working on doing what they can to manage field decline, but it's still in that negative
Thank you, Chair Josephson, through the chair.
You indicated that you said the primary focus in this area
is gas production.
Do you anticipate that if a gas line were to happen,
that there may be a shift in the region
to focus on oil a little bit more?
Or is it just unknown?
Yeah, through the chair representative Bynum
I think it's a great question and I'll be honest. I don't know the answer to that
My assumption is that the operators will do what they can to maximize the value of their existing fields regardless of if there's
A natural gas pipeline down here or not
Thank you
slide 12
So now we're going to transition into the production forecasting approach the methodology that we use to build a forecast
Just to kind of highlight the stability that we've had here. There've been no changes in methods used from the fall of 2022 in spring of
2023 forecasts until now. I do think last year
I brought up that
We had a math error that
We found and we continued to keep that analytical error out of the forecast
You have been losing sleep
Representative Galvin why thank you through the chair
This is a question that's related to forecast, but unrelated to what you have on paper here.
We know there was an audit done at some point that talked about whether or not we were negotiating.
If the oil companies had written off the appropriate amount of write offs and then we're giving the state the
appropriate about due to the State.
And I just don't know where that.
Is right now and if it's appropriate if you could give us a heads up on that just because
At one point we were hearing from various sources that it could be
You know what we went from hundreds of millions to kind of to zero in terms of our
Negotiating ensuring that the state was getting its
full due amount based on negotiations around its write-offs.
So, I thought I would ask you about that.
I know that a sister agency is pretty involved in that as well,
but you have a comment.
If you, if you haven't anything, because it helps us to know
whether or not we can expect any funds toward that end.
Yeah, for the record,
I can't speak to that, right?
Okay, representative Gallopologies. Thank you
All right for the record
Please for this record Travis Peltier, so again just to kind of go over how do we build this production forecast year-on-year?
taking a look at the top
The bulk of the production forecast is done using what we call the Cline Curve analysis,
and it's for all the producing pools on the North Slope and the Cook Inlet.
We treat all of individual pools in the north slope separately, and then we actually have the
rolled up as a single pool and that we that is what you get see reflected in the
Department of Revenue Revenue Sources book. There were roughly 41 pools
along the Alaska North Slope and then the cook-inlet producing as of June 30th 2025 and so those all
represent the the entirety of what we do for production decline on the decline curves
Along with that, we actually work with through the Department of Revenue,
in-person and in writing interviews with all of the operators,
both on the North Slope and the Cook Inlet, and
in those conversations and along with reviewing our plans of
development that we have in house already,
worthy of considering under development and under evaluation that we reviewed.
These projects use confidential information from the operators so we don't typically report
on them individually unless the information we know is already public like we had on a prior slide.
And the production from these projects is risked and adjusted for scope, chance of occurrence and
start date. So scope of contribution represents the oil production rate so how much oil
12 of these projects are located on the Alaskan or slope one is in the cook inlet
And I'll have a map of the Alaska nor slope here on a future slide
Moving on to slide 14 we also break the production forecast out into various categories of production
So that's for ongoing and future production,
we have for the current production what we call CP.
So you'll see this acronym repeated in future slides.
This is the ongoing production from the existing field.
So there's 41 pools that we talked about on the prior slide.
We do take into account well and facility uptime
in our forecasts for these forecasts.
The operator spending to maintain that base production
and any sort of changes in reservoir management as well.
We reflect that in out forecast as best we can.
Along with that we do get a sense for future projects under development and under evaluation
and what we mean by that is any production that requires new investment so that's drilling new
wells or you know putting in new production facilities new projects. The rate contribution
there is uncertainty in future well performance so when you drill a well in the legacy field
it's not going to produce the same as it did 20 years ago so getting a
Along with that, we have to take a look at scope, so how many new wells are coming in,
how much facility capacity is being installed, those all go into our evaluations in the under
development category, along with the Under Evaluation category.
The under evaluation category also has timing risks associated with that so uncertainty and timing
and prior presentations and we've had stuff like pick a phase one has actually had a timing
risk associated. With it and in this one since it's so near that that project timing and certainty
has shrunk significantly but all of our other projects like Willow the ones that we talked about
before pick of phase two we keep that uncertainty in timing. And that is all represented through
And then there are commercial risks, but also get taken to account. So oil price for instance if you have a break even oil
Price, you know this doesn't make economic sense for this project to come on if oil prices
You know higher low so those are also taken into account for our production forecasts
Okay question from representative Bynum. Thank you chair josison through the chair. I think you mr. Peltier
There's a lot of questions they get sent to us
Talking a little bit about global volatility in oil markets, and we know that
Volatility specifically in the northern hemisphere do directly impact oil prices
I do understand that Alaska's oil market is very different than maybe the Gulf
Oil market, but do we anticipate that there would be any?
climate condition
That would impact production in Alaska where we would curtail production at all because of that global volatility
Can I ask you a follow-up before answering? Sure. Can you explain what you mean by climate condition, please?
Well, I'm talking about the
talking, about
volatility in the oil markets, so
Specifically, there's a lot of discussion in news about Venezuelan oil or what might be happening in
the Middle East
those production
Volatilities obviously impact prices, but is there a condition that would
potentially impact our production here in Alaska.
Mr. Peltier.
Yeah, through the chair,
Representative Bynum, for the record,
this is Travis Piltier
I don't necessarily see the volume of oil being affected from legacy fields with things
like Venezuela being diverted necessarily to the United States for fineries along the
lower 48.
And the same thing with the Middle Eastern supply.
In the near term, I do not see that affecting, again, legacy field production.
Oil prices were near $100 a barrel.
And starting around then,
Middle Eastern fields ramped up production
in a fight for market share.
And oil prices dropped pretty precipitously
from 2014 into 2016.
And so projects, you'd start seeing those get deferred.
So that absolutely affects future production
for the state of Alaska.
but not a near term effect.
And if you go back to a
near-term effect, if
you take a look at the
COVID pricing in April of
2020, the spot price for
WTI, I can't remember the exact
number, but got down
something like negative
$40 a barrel, yet the
legacy fields in Alaska
continue to produce.
So that's, that I think an
important note that you can
have a pretty wild swing
and oil production price
or sorry, oil price.
But the fields are still
going to produce oil, the companies still need to make money, and with the exception
of negative pricing, typically they try to maximize volume.
Thank you.
Yes.
Yes, Representative Schrugg me.
Thank, you, I guess in a similar color,
I'm curious if they're the need for capital to
make investments in other markets.
I know there's a lot of pressure to ramp up production.
in Venezuela with the need for capital to make those investments have any potential impact on the development in
Alaska and our ability to bring some of these projected
barrels online
co-chair
Co-Chair shuragi
Thanks for that question. It's a great question in a we as one we're continually asking our operators as well through our confidential
Discussions with them the short answer is I can't tell you today if there are any effects with that right now
In broad brush the state of Alaska staying competitive. It's obviously very important for us right having a large resource base in
A competitive place to do business is very
Important but in terms of is capital currently being diverted from Alaska projects to the lower 48 or to
Overseas locations. I I have nothing I can share with you today on follow. Yes follow co-chair shorty
Thank you, so conceivable not necessarily
In your forecast, but conceivable that capital needs elsewhere could impact us here
Are there how much exposure is there? How many companies?
That are in our forecast are also
Contemplating to your knowledge investment in Venezuela or others. I know I believe I read that Hill Corp was
Potentially pursuing investment and Venezuela, there are there others that I should be aware of
Mr. Piltier through the I guess co-chair shuragi
So I don't have a number for you today, I mean I read the news and I saw the names of the companies that had CEOs represented at the White House with which I could tell you there was at least three companies
that work in the state of Alaska, whether operator or non-operated, that were at that meeting and only one of them said that they weren't interested in Venezuela at
the time or they'd have to think seriously about it I should say.
more optimistic than that.
But I can't tell you if they're already
diverting capital or not.
That's beyond what we look for in this forecast.
Thank you.
Yes.
Representative Stapp.
Yep.
Thank You.
Just could you just send to the chair to Mr.
Director Naim or Mr Peltier who ever can better
feel the question.
So curious on this Venezuela question, I mean,
if we're worried about capital flight from Alaska
projects, wouldn't the best way to guarantee that we
would have that would be to do big tax increases
on companies while they are looking at moving capital
through the chair.
The chair of Joseph's Center, through
the Chair, Representative Stapp.
It's a very interesting question.
I don't know that I have the answer today for you.
Yeah, follow up, Mr. Coacher.
Yes, I'll represent Stap.
Because I'm curious, if we're worried about other places
in the country having competitive projects,
you would think that we probably wouldn't want to talk about
making doing business and Alaska a lot more expensive
just a thought to the chair.
Okay, are we ready for slide 15?
I know I am through the Chair or sorry for the record Travis Peltier slide fifteen. All right
here we are the major projects under evaluation in the under-evaluation category that are considered for
the fall 2025 forecast on the north slope of Alaska. I'll speak to The Map but basically these projects
I know Pika is planning to come online, but since it was not yet online by June of 2025,
it's still considered a project.
These have a higher risk factor than the currently producing fields,
but they are all known discoveries with identifiable operators, and they require major investments.
So this is the general characteristics of what we put in for major projects on the slope.
That list, if we go from west to east on a map, you can see the will of development
That's all on federal land and a federal unit in green.
Moving over, this is, I think what we talked about,
the Horseshoe unit, the horseshoes project is just south
of that with a mix of state and federal acreage.
The Colville River Unit CD8 project
is
You'll see the southern part of the Colville River Unit.
There's a green triangle representing where that is at.
You have the Pica Unit, again, just to the east of that, Pika Phase 2 and 3
and the pica unit development are along a north-south line
in the Hashed Unit that says non-producing state lease.
And as we continue to go west, we've got the Quaka Midcuck,
just the unit right,
just for the west or sorry, the East of Pico.
And then the Prudhabe Omegapad, we're going to skip the Kapark River unit.
We don't have any major projects in development for them right now.
They're executing the Coyote project and the carrier unit or project still,
but those moved into currently producing pools.
So the prudHabe unit has the OmeGapAD, iPad projects on the map listed there.
And we go south of the Perudhoe unit to the Pantheon Great Bear projects for Theta West,
And that is it for the projects that we carried for this one.
We don't have anything east of Perdabay
carry as a major project for
this forecast period, okay.
So let's move on to the slide 17, the fall 2025
nor slope annualized forecast.
We already discussed this chart earlier on. I believe it was slide four. So I'm just going to
cut to the bullet points because I know we have limited time left and the DNR forecast in the
The annualized average daily statewide production is 464,500 barrels
of oil per day, with which north slope production
is 457,000 barrels of
oil, per
day. The range on that from the low to the high case is 418,400 barrels
of
oil
per
day and a high
case
is
495,300 barrels
of
oil
per
day the new
operator
lines. This is distinct from
the one that we had seen.
Showing the you know actuals versus operators
This is the one that we've rolled up for this fiscal year the operator line for
This one is four hundred and seventy six thousand barrels of oil per day
In the long term we see the forecasts oh
Right so the operators long-term forecasts again does not include
New fields, right? So this is again existing production out of the existing fields that are already online
And that does fall within our high to low range
It does diverge at the end of forecast period because we don't have those new projects in there
So I just wanted to reiterate that again
Um, and the differences that we have between the low case, the official case and high case
is due to the uncertainty analysis and all of our projects.
And again, our uncertainty ban increases with time.
There are just things in the future you don't know when they're going to come on from a
timing risk.
If they are going be successful, what rates new fields will actually...
produce that. And then the other item of note is the
production forecast assumes operator plans are static
right at some point in time we just have to stop making
assumptions. So this assumes all those plans and project
drivers remain unchanged. We'll do of course an update for
this body in the spring in a few months I believe that'll come
out mid-March sometime and we'll give an
update on how those assumptions have changed as well.
Slide 18. Oh, sorry, Reverend Thomas Schatzke from Mr. Peltier. Yeah, thank you through the chair
Mr Piltier, so I'm looking at this slide and it looks like between 26 27 is pickle one
I am just assuming since that's coming on in March imagine the end of the year. We are going to have approximately 80,000
29 through 31. I assume that is willow that large increase for 100
80, 160, but then from 31 to 35 that's about a hundred and hundred thousand that
is the other pick a two, would you reference pick three on a previous slide, is there
an estimate on pick of three, on how many barrels per day that could be happening there?
Mr. Piltier.
So pick a phase three to answer that question specifically, we don't view that as an enhanced production capacity out of the facility.
We view it as a new pad filling olives that will open up as pick of phases one and two decline through time.
So it'll be a New Pad with wells that get drilled and basically fill the space that opens up.
So a continuation of peak rate of pick facility in the pick unit overall.
So the next slide on slide 18 again for the record. This is Travis Pels here
We wanted to show this year last year
We showed a 12-month future forecast with all the questions around PICA and when that rate will be seen
We're actually showing an 18 month snapshot
So slightly farther on a month by month basis from the previous chart
What we also have here is the actuals through January 14th,
2026 because we had them.
We can compare how does our forecasts look versus where we're actually at now.
This is forecast pencils down was late November.
How are we doing and we can see right now that the actual production forecast for the North Slope is slightly running slightly higher
But generally on trend with our actuals
You don't see much of a divergence if we skip to the cumulative production line the bottom one that goes
starts at zero and
Since this is now an 18 month forecast goes over 260 million barrels a day on the right,
there's not much of a divergence between the forecasted cumulative volume and the actual cumulative
volume. What we wanted to highlight with this though is that we know pick a phase one is
anticipating to come on at the end of the first quarter. We don't think it's going to
come at again that 80,000 barrels day of production rate. So you'll see a nominal increase there
The big reason for that is the legacy fields in the North Slope are seasonally constrained.
A lot of them produce a lot gas, and as it heats up on the north slope, their ability to produce oil goes down.
The other thing is for the reason they actually do turnaround activity or summer maintenance
for all the facilities on North slope and there are some large turnaround activities
expected to happen in June, July and August of time frame.
And so as we expect to pick it to ramp up, we're expecting these facilities to actually slow down.
And, so, what you finally see is this large production increase in August of 2026,
and that's the cumulative response of pick-of-phase 1 ramp-up along with those facilities ending their
summer turnaround cycles. And then production increased from there as you enter colder months
All right, this is where we're going to break out the Alaska statewide annualized forecasts versus their forecast production categories that there are two charts again the annualize annual average daily oil production
zero to 700,000 barrels a day is on both charts just to show the relative contribution of the
existing base production with new projects and new drilling. What we have here on the chart on
the left also has an overlay of spring of 2025 production forecasts. You can see how things have
changed from the most recent update to this one. And what we typically see or what have seen is
there's been a lot of stability. The spring 2025 forecast I think by the numbers was actually
a little higher than what we have. I'd have to go look and see what it was.
But slightly higher for fiscal year 2026. This is a small reduction
from what We put out last fall for
fiscal years 20 26th and last spring as well.
But you see that those existing field decline earlier. I believe there was a question about you know seeing
Roughly 400,000 barrels of oil per day of production increase from new projects
How do we see? That kind of come forth and you?
See these legacy fields decline on the blue chart and we do expect that to continue through time
So as you bring new fields on a lot of it is actually just replacing oil that's being lost through production decline
The orange curve represents new drilling, so that's just the next 12 months of new
drilling in existing fields, and while it might be the smallest of the curves, it
does show a material impact on the production forecast and the continued
value of that drilling as we go point forward. The rest of
the drilling and months 13 through 120 of
the forecast are contained in the gray,
and so if I go over to the chart on right then the under evaluation
These are the future projects now,
just overlaid against each other.
So you do see the spring forecast versus this forecast.
Again, we have slight differences.
I didn't necessarily correct the Spring forecast
with the Torek projects and the Conoco Phillips projects
that were being executed at the time.
I wanted to leave them on there just to show the relative
contribution that projects like PICCA coming on will have
in the near term, which is to say that it's going to be a quite
a large project that we're going
to see here coming in.
You do see there's a gap that develops kind of in the 2028 2029 2030 time frame
And that has to do with the uncertainty of some projects that we've talked about like pick a phase two
We weren't sure when they were going to come on relative to our expectations last year
So the uncertain to you opened up on that and that's why you see a production
Change from last years expectations versus this years
Representative Bynum, just a really quick follow-up.
Quickly for Mr. Peltier.
Thank you, Chair Josephson.
Really quick, all these projections
just take into consideration the current known information.
Does it take any, are you guys looking at all
at potential of favorable administration,
opening of NPRA challenges to Willow, two-pad?
three-pad so that kind of thing are those in any consideration and if so is that
something you bring back at a later time mr. Pildt here yeah through the chair
representative Bynum it's a great question and something we actually
debate internally a fair amount what I would say for this specific forecast is
we did not take into account any actions of a new federal administration with
respect to Willow you know we know there's new exploration going on in the
And a lot of these exploration wells, we're not sure because there's no found oil,
there is no defined project yet, how that's going to play in the production forecast.
So while we are excited to see the activity and we want to know how it's
going play out in a production broadcast,
we have not included any barrels associated with that exploration activity.
Thank you. All right, let's wrap up with page 20 and give us some re-absent.
So the production forecast continues to use the best information we can gather from both
the Department of Natural Resources and the department of revenue.
We try to make this as accurate as we could both near and long term.
It is a static view on production.
Again, assumptions change from business plans change, our assumptions become outdated.
We update them as best we ca.
The DNR's fall 2025 outlook does show mean annual production starting at approximately
465,000 barrels per day, increasing to 685,00 barrels of oil per
day at the end of the outlook period.
And I think for that, I'm just going to skip on,
because I know you guys are short for time
and skips the final slide, which is to say thank you
on behalf of the Division of Oil and Gas
in the fall 2025 production forecasting team.
It's always an honor to come here and share the work.
So on the behalf the entire team,
we just wanted to thank thank-you.
Mr. Piltier, thank for your good work and director,
Nottingham, we appreciate your being here as well.
We saw some good news there, certainly, maybe not for this legislature, but for future legislatures in the relatively near term.
Anything else either gentlemen would like to add?
I'd like thank our guest from Division of Oil and Gas for their presentation.
Our next House Finance Committee meeting is scheduled for tomorrow, the 22nd of January at 130.
At that meeting, we will hear the Department of Revenue present its 2025 fall revenue forecast.
With that, we're going to adjourn this meeting at 2.56.
Thank you again.
Thank You.