Call the Senate Finance Committee meeting to order.
Silence your cell phones, it's a couple of minutes after 11 o'clock.
We do have time constraints.
Many people want to go to the luncheon.
So we're going to be out of here, try to
be on here by a quarter two.
let's try to get done. We have, joining us today, we have Senator Stidman, Senator Olson,
Senator Keel, senator Merrick, and Senator Cronk and senator Kauffman.
We are going to be dealing with the production forecast from the Department of Natural Resources.
We're going have the presentation by Commissioner Designite John Crother.
Please identify yourself, come forward, identify
yourself and identify your team as well.
Thank you, Chair Hoffman.
For the record, my name is John Crother, Commissioner Designee
at the Department of Natural Resources.
Appreciate yourself Chairman and members of the committee.
In light of our time constraints this morning, I'll just be very brief for an introduction
Let my team do a quick introduction of themselves, and then we'll proceed right to our presentation
In short summary, we're here to present our production forecast is something we do annually
And we are continuing to see a tremendous amount of activity in the slope and we will summarize that today
Consequently our our Production forecast does at 10 years out have us over 650,000 barrels per day in in
the 2034 window, which we think is a very significant is
Part of the hard work of that apartment and part of all the investments that are going on in the slope right now
So very exciting story to share today. We'll move quickly in light of The Committee's schedule limitations
I'll let my team introduce themselves and we'll look forward. Thank you
The record I'm Derek Nottingham the director of Division of Oil and Gas and I will be very brief and just turn it over to Travis at this point for
the presentation
For the record my name is Travis Peltier
I'm a petroleum reservoir engineer and the resource evaluation section of the division of oil and gas within the Alaska Department of Natural Resources
I graduated from the University of Alaska Fairbanks in 2006 with a master's degree in mechanical
engineering and have spent 19 years working in Alaska's oil industry since. In 2021, I joined
the Department of Natural Resources in my current position and in 2022, i was honored to ask to
lead the development of the state of alaska's Oil Production forecast and i'm honored
to continue leading that team today as we present to you the forecast that we developed by annually.
Today, we'll be talking about Alaska's oil production
forecast for the next decade.
For your awareness, the Department of Natural Resources
has been performing this analysis since 2016.
So that will keep moving on.
I'm just going to briefly say that the second slide,
I am not going address it all other than it's
a reference list of acronyms for folks to have in the future.
Any relevant acronYms are also listed at the bottom of every
slide that we have as necessary.
Today the agenda is going to focus on a forecast preview a review of the fiscal year 2025 in review
We won't be talking about forecasting much there, but just how fields have actually done and then we'll transition on to the fall 2025
Forecasting approach and results. We do have some material in an appendix
Which we do not plan to present unless relevant questions show up
So just to show everyone now we're on slide four here for the fall 2025 North Slope annualized forecast
I'm just gonna chart talk about the chart elements before to move on since the charts elements are gonna be
Fairly repetitive through this presentation
We'll see this on a number of charts where the fiscal year annualized average daily
oil production rate listed in barrels of oil per day is on the left hand or the y-axis.
And then we'll have fiscal years on most charts on
the bottom. This is a fiscal-year chart. Some will have calendar years. I will specify that
for the one that we have that for.
Along with that, this chart is made up of the Department of Revenue, Revenue Sources
book, Table 6-8, where the low official forecast in high can be found.
This is however charted up for reference.
And you can see that our low forecast, our high forecast brackets, the official forecasts
put out by the department of Natural Resources and published by The Department
of revenue, when we're producing around 465,000 barrels of oil per day in fiscal year 2026.
Projects come online that climbs through time to the high 600,000 perils of
wall per day and that's what makes up the official forecast.
Every year the department has confidential discussions with operators across the North Slope and the Cook Inlet,
and so we actually receive from them their views of a forecast as well.
We create ours wholly independently, but we sum theirs up to see what it looks like,
only for operated fields, so fields currently on production.
And so that's what makes up the operator line that you see here on this chart.
So for the next few years you can see that the Operator forecast starts higher and then goes lower than hours.
And that's again because new projects like pick a phase one are not included in the operator forecast
All right moving along this is interesting just real quick thank you, mr. Chairman
I know we're really short of time, but I think we need to start taking a shift in our
barrel production
Forecast and clearly de no any and I'll be working with Department of revenue with this also because for those watching at home revenue
covers the production tax, property tax.
And you guys do the royalties.
But we have a significant issue dealing with GVR barrels.
And we at the table need to know, and the public
needs to to split of the barrels into what category
GV are they fall in, 20% or 30% gross value reduction.
creates the new barrels and it's a significant issue so we'll be asking for projections on
the legacy barrels in both categories of GVR barrels from your department and then asking
revenue then to break down the revenue forecast amongst those categories. Otherwise, it is
going to be very difficult for many members to understand why oil production is going
And that's not going to be a fun issue to deal with.
So I think that sooner we delineate it
than the magnitude, the better.
And it's a little different than historically
because we've always concentrated on just
the aggregate barrels.
But we're looking at and think about a 17% of GVR barrels
from 3% last year.
So it is going escalate to 40% barrels by 33.
major shifts
Been money to make money. Yep. Thank you senator stegman. Do you have a response?
Just
Chair Hoffman and senator Stegmann. We're absolutely happy to work with the department in the committee to share more information. Yeah
Thank You, please proceed
for the record traps peltier
So moving on to fiscal year 2025 in review again we will have only some
ancillary forecast on here this is a review of how did we do last year when we
came and presented this fiscal years 2025 forecast again just given the time I'm
only going to hit the highlights here last
year we did present a forecast um DNR mean forecast at the
time was just under 467 000 barrels the actual production for last
Typically, we are looking to get plus or minus 5% on a forecast for what we consider an acceptable range
Last year we were within zero point three percent. So we did all right
And if you take a look at the summation of last year's operator forecast
You can see if we had just used their number they would have forecasted an aggregate of just over
486,000 so actuals came in less than the operator roll up as well
Again, just for the sake of time, I'm going to read the factors shaping the forecast rise
in bullets and we can stop if we have any questions along the way.
Just a couple of positive highlights and some challenges to address.
Industry interest in the Brookian Topset prospects, both on state and federal land, continues.
We do see, continue to see industry interest in the brookie and
topside plays across the entirety of the North Slope.
Along with that, exploration activities and opportunities on
federal leases have increased with the current administration.
So we see four wells being explored right now in
the NPRA. That's the plan for this winter.
We'll see how those results turn out in
the fullness of time, of course, but it's exciting to
see exploration continue and increase.
Along with that we do see that moderate oil prices and capital discipline across the industry are headwinds for development generally
So lower prices typically lead to restricted development
Higher oil price is of course the inverse of that is true
And then the last bullet point inflation
Relatively high interest rates and insurance challenges are affecting or slope exploration costs and operations
For and for the public's information and PRA stands for
The National Petroleum Reserve, Alaska. Thank you
Senator keel thank you, mr. Chairman if the low 60s are moderate oil prices. What's low?
Okay through the chair senator keell I'd say probably anything in the industry less than $50 a barrel would be considered
very low at this point in time. 60 is uncomfortably low. If I'm going to make it qualitatively a
This is a new slide that we started introducing last year.
This shows a monthly breakout of how the fiscal year 2025 forecast was going to look when we presented it last
year, there was not a full year of data behind it.
We'll have something later on to show the effect to pick a phase one.
on an 18-month view, but I just wanted to reintroduce everyone
to this slide since it was new.
So this just shows how we did versus the forecast.
I think we can all understand the monthly forecast if we go
to the left-hand side of the chart where it says oil production rate.
That corresponds to, I'll call it a high-frequency line
for actual daily data that we get.
We can plot along here for the orange line with all the, no.
Without a better term squiggles in it and then you can average those per month
That's what you see the monthly flat bars
Represent is that forecast
with an average for the month and there's not much of a difference between blue the forecast line in the
Purple daily run tickets monthly average until about the May 25 June of 2025 time frame
And so that's where our forecast versus actual started to verge in the positive for actual production
Now to bring everyone to the left or the right-hand side of the chart where you have cumulative
production on the year, that stands for millions of stock tank barrels of oil.
The expectation was that last year we had produced roughly about 170 million barrels
of Stock Tank oil for the entirety of a 12-month forecast, and that's about where we ended
up, around 170 millions barrels.
The important thing to note for this chart that looks like a straight line is you're
looking for a divergence between the dash blue, which is actually under the orange.
were so close you do not see much of a divergence on here until the end of the period.
Moving on to slide eight, this is, again, not forecast.
This is however just actual, so I wanted to get a sense
of how actual North Slope fields are producing
and what major activity has led to any changes
that we've had up here.
The highlights, just to bring it up, you know,
we expect all fields, a lot of the fields on the North slope
are legacy fields.
They've been online in producing since the late 1970s
or early 1980s, the backbone of
the Alaskan oil industry right now.
We're expecting these legacy feels to see a year
on your decline.
it's natural. Operators do reinvest in those fields to try to...
Slow that or rest that decline and even see production increases. So just want you to know that
And last year, I think there's a positive story in terms of fiscal year 2025
Overall on the entire North Slope production
Increased by roughly one and a half percent
So roughly a seven thousand barrel per day increase year on year due to the efforts of the operators on The North slope
Overall, that's A great story
Again, since we have a limited amount of time
I'm gonna skip the chart on top right and I'll just hit a few of The highlights on
bottom right. Some of the highlights I want to point out, the Prudha Bayfield looks like
it has declined about 3,000 barrels of oil per day. Just a point of reference, this field
produces over 200,00 barrels per year on average. You'd expect a decline right there to be,
you know, closer to 10, 000 barrels a day, but the operator has been doing a lot of reinvestment
projects and parts of the field online managing their well stock as best they
can and so they had that decline last year only at three thousand barrels per
day year on year which for a field of that size is spectacular result
On the positive side, if you focus on the Caparic River Unit,
a similar development here, they've conical Phillips is the operator of the
Capariic river unit. They've had excellent base performance, meaning they
have managed their existing well stock along with bringing on a few new
projects over the past few years. In years past, we've talked about a
coyote project and then last year there was a KRU
Nunatoroc project along drilling in their Shrader Bluff
The well results have been very positive, and so year on year, the Capark River unit actually increased dramatically in production as well for a field of that size.
And then a perennial story we've been sharing is for Milney Point.
We actually have a slide later on on that, so I'll just suffice it to say that last year Milley Point production increased another 4,000 barrels per day.
And we'll have some highlights here in a minute.
Questions, Senator Stedman?
Mr. Chairman, if we could, a little more explanation back to the Committee on Point Thompson.
Pointe Thompson looks like there's some development,
hillcores up there doing a very expensive well, and we're moving forward with Pointed Thompson,
but the issue with pointe-Thompson, it was a loser when we did it financially.
Because of the billions of dollars we put in credits and
They were more or less forced into it, but I'm curious on on the financial status of that decision
It should be turning to be more positive now after a decade or so
And we've also have to deal with the tariff the additional tariff coming out of point Thompson
So I'd like to know the history of the tariffs the last since and its inception because a tariff should
Be coming down also and making more point. Thompson more
profitable so it'd be nice if we can get later on some information back on the
on that point Thompson in isolation. Thank you Senator Stegman. Please proceed.
For the record Travis Peltier. Moving on to Milly Point is the highlight slide we
just wanted to kind of cover in detail.
Some of the positives we've seen it in Millie Point over the past few years, especially since Hillcorp took over
Operatorship in November of 2014
What you see here is a calendar year now the only calendar your production chart we have
Going all the way back to 1995 when BPD, the prior operator, took over our
operatorship of the Milney Point unit. On the left-hand side you have oil daily
production rates. This goes from 0 to 60,000 barrels a day for reference. We do
have water daily production rate on the right- hand side as well. That's
represented by the blue dashed line. Again, just for brevity, we'll talk only
about oil here.
And in July of 1998, when BP was operating the field,
the only point was designed for Coparic aged reservoir.
It has relatively hotter oil, lighter oil to go through
its production facilities, and BP
was able to hit a maximum, monthly...
annual average, sorry, monthly average rate of 58,893 barrels per day.
So that was the highest production rate in milli-point history.
After that, you know, BP continued to develop the caparic,
but the play eventually kind of started to decline as all reservoirs do.
And there was some Schrader Bluff development, which is a shallower horizon.
The oil is colder, heavier, thicker, harder to produce.
And at some point in time, BP decided to sell the field to Hillcorp, sell
the operatorship. HillCorp saw a large opportunity to implement new technology,
to develop that thicker, heavier viscous oil. So they implemented polymer flooding
and a continuous drilling program, circa 2018. And what you've seen ever since
with that continuous development is this.
as a dramatic increase in oil production out at Millie Point.
Combinating in the last month that we have data for,
where Hillcorp's operatorship high average
was 50,906 barrels per day again.
Pretty positive story, and I'll see if Derek
has anything else you'd like to add for this.
Sure, I'm going to go.
Yeah, for the record Derek nodding him.
I just wanted to point out, it's very rare
you see the primary peak production and then the the decline and
then a rejuvenation of the field and the production actually achieves the same
level of magnitude as that primary peek you know so very very close to the 50
Plus thousand barrels that was achieved back in the what was that the early 2000s late 90s
That's a very rare thing the operator has done an outstanding job here as Travis mentioned
Being able to adjust their facilities to produce this more viscous oil and Hill Corp
Has just recently taken ownership of the aguric and the kayachook
fields which are very, very similar in the reservoir type and operations. So we're excited to kind
of see what they're going to do with those fields as well.
Senator Stegman, did Senator Frank?
Just again for additional information. I think we have nine conditioning plants if I remember
right. If we could get the department to get back to us on the status of the oil ratio of water
And the capacity of those plants, I think they've had a lot of work done to them over the years.
And as I recall, a decade and a half ago, they were all running at capacity, except for one.
So we can get that updated.
I mean, in your old files, you'll find some work that the finance committee had.
You guys do years ago.
But it'd be nice to get it referenced again.
Yes, thank you, Stedman, Senator Crock.
Thank you Mr. Chair.
This is a quick question.
Is there any way to get a number of how much money
Hill Corp invested to give that oil production back up
to the $50,000?
I mean, we talk about investment back in, you know,
I would be really interested in other people
to understand how many money they reinvested
to be the production.
I suspect that is probably confidential data, the Department of Revenue would potentially
have access to a limited distribution.
The operator may be able or willing to disclose that as well, but from the department's perspective,
we certainly understand significant drilling activity, so rigs, crews, and then also work
on the facility.
Thank you, Senator Cronk.
Mr. Peltier, please continue.
For the record, Travis Pelter, through the chair, co-chair Stedman,
we will get you the updated file I know the one you're talking about.
And one plug, too, just before we leave this slide,
we do have public information from the AOGCC available in charts.
There's a link there where it says detailed field charts,
if anyone is interested, you can go dig down to the well-level
at any field across both Alaska's North Slope and Cook Inlet
and get any production information or well injection information you'd like to.
So I just want to put a plug in there that's publicly available for anybody.
Except for cost.
Wow, it's just it just oil gas and water production. Yes
So, again, I'll keep this brief since I know we were oppressed for time here, but we did
want to highlight five projects that are coming across the North Slope that
are very material to the production forecast over the next 10 years.
That's Pick a Phase 1, Pick A Phase 2, both operated by Santos, Willow operated
by Conoco Phillips, the Colville River Unit CD8 project, which is a new pad
within an existing field, also operated,
but also, operated with Conaco Phillips.
in any prior forecasts operated by Hillcorp,
the Prudhabe unit Project Taiga,
which involves two new pads being developed.
Omega pad or opad, you might see either of those
in the news, it's the same pad,
and then iPad would be the second pad developed,
again, just for brevity, I'll go through
these relatively quick.
Pick a Phase 1 is a new project.
It's very exciting, expected to come online
in the first quarter of 2026, so that's this year,
and have a peak rate of 80,000 barrels of oil per day.
Again, we have slide later on to show the effect of picka
over the next 18 months, combined with other activities
that will be happening on the North Slope.
So when we hope to see that oil production come through,
the uncertainty on that is significantly less
on time constraint given it's only a few months out.
Pick a phase two is intended to follow pick a Phase 1
Santas the operator is focused on finishing that project first before they move on to pick
a face to and the peak rate out of pick of phase 2 is expected to be 80,000 barrels in a day in
Addition to phase 1 so for a total of a hundred and sixty thousand barrels of oil per day when both projects are online and at peak
What's not on here?
But was asked about a number of times is there is a pick-a-phase 3 project and that's intended
Space opens up in the production facility. There'd be new pad new drilling happens to fill that space
That would be a pick of phase three and it's not on this slide, but it is in production forecast
Moving on to the next big field that we've all I think heard about a number of times over the past few years is willow again
Operated by conic of phillips and that project is now more than 50% complete and remains on track for first oil in
2029 the will of central facility modules are currently under construction and they're planned to transit to The North Slope in
2027 the peak rate for that facility is expected to be a hundred and eighty thousand barrels of oil per day
And then, moving on to what I call new paths, just as equally important, new
paths within existing fields, the Colville River Unit CD-8 project.
Count of the Philips started an environmental impact statement with the U.S. Army Corps
of Engineers as the lead agency last year.
And notice of intent was created on September 9th of 2025.
Stakeholder engagement is ongoing.
Comment period is expected to wrap up in the fall of 2026 in a record of decision for that project by early 2027
first, I was expected it to be
2030 and
We don't have a public rate estimate for this
We wanted to share with this committee our internal rate estimates for the mid case of about 20,000 barrels of oil per day
And then the last project, I'll just kind of skip again.
I know we have less time perhaps than normal,
but the Omega pad and iPad projects
operated by Hocorp are brand new.
Expected to be a couple years apart,
Omega Pad will be the first one.
First oil for that is expected in 2028,
so relatively close here in time.
Another couple of years after that,
two to three years we expect iPad to come online.
Peak rate for both of those pads being online
should be around 40,000 barrels of oil per day.
Chair Hoffman, for the record, Derek Nottingham.
I just want to add that project,
Tayega is basically a continuation
of what Hill Corp has been doing at the Millney Point field.
It just kind of carries into the Prudhoe Bay area.
And so again, that redevelopment profile,
that increased production that we saw in Millley Point
and kind expect some of those same type of activities
to occur there.
Thank you, Mr. Nottingham
Mr. Peltier, please continue for the record Travis Paltier
So now we're going to talk about Alaska's other oil and gas
production base in the Cook Inlet.
So again, what we see here, I'm going
to skip the chart again on the top right,
other than to know that this is a mature basin.
The first fields came on in 1958.
So there's been over seven decades of production
out of the cook inlet, it's a fascinating engine
for the state of Alaska and continues
to be very important.
One note is that oil from the cooking
in that basin is critical to the in-states refinery
that we have down there.
And then Hill Corp, however, is prioritizing natural gas development out of necessity for
South Central needs.
So there's not a lot of oil production drilling, oil, well drilling going on in the Cook Inlet.
And so what you typically see here again is since they're trying to manage the well stock
as best they can, gear on your oil decline out the cook Inlett oil field specifically.
If anyone is noticing the redotch hole did have a production increase year on year and
that's because some pretty good well work came out of that well.
They are still managing the wells, they're just not drilling new ones.
So the re-dotchhole did see a reduction increase, everything else was a decrease and I will
move on again for brevity.
So moving on to slide 12, just a brief note, for the past three years or so we have not
Create the production forecast with the exception of removing a mathematical bias last year.
That mathematical biased is still removed.
Moving on to slide 13, how do we build the forecast?
So just in summary, the way we built the forecasts is we use AOGCC data of all the publicly available
That sums up to about 41 pools across the Alaska North Slope
and the Cook Inlet that are producing as of June 30th, 2025.
So to be considered, you know, in the forecast for client curve analysis,
you had to online by that time.
There are, however, projects that come on in
the middle of forecast period.
For instance, Pickett is anticipated to come
on, at the end of March of 2026, the Middle of the fiscal year 2027 forecast
period, we leave that as a project along with 12 other projects
based off of conversations that were confidential
from operators along with publicly available
plan of development documents.
So we review all of that and create our projects list.
The ultimate number of projects,
other than infield drilling on the North Slope,
is we have 12 distinct projects on
the Alaska North slope and then one in the Cook Inlet.
We break these out into different categories
of production as illustrated on slide 14.
For the existing fields that were online,
as of June 30th, 2025,
we lump those into what we call current production.
So that's all the production from existing field.
We consider well up time, operator spending
to maintain base production,
and any changes to reservoir management
that are expected for those fields
when we create our production forecast
and adjust them for the future.
Along with that, we have two additional production categories,
the under development in the Under Evaluation category.
In brief, the under-development category, UD, is effectively in-filled drilling, so new
money that's being spent, new capital is being deployed to existing fields.
All of the new projects and drilling outside of one-year window,
so drilling in years two through ten, and all of
the projects are in the Under-evaluation category by definition.
A map of where the projects are, again, this is the 12 Alaska North Slow projects.
They cannot be online and producing by June of 2025, so again they were offline at the
time or they had not yet been put into production, I should say.
We do have a higher risk factor associated with these new projects than we do existing
fields, but they all have to be known discoveries with identifiable operators and require major
investment to considered in our list.
Those 12 North Slope projects are the Willow Project in the east.
These actually, this list is, sorry, in west.
This project list, is going to transverse from west to east,
the Willow Project is the farthest, most west project on federal land,
followed by the Colville River unit,
Narwhal CD8 project, which has mixed acreage,
horseshoe stirrup, just to the south of that,
ultimate mixed-acreage.
The picket unit which is non-producing,
as we've talked about,
but it has three projects within the unit boundaries.
The pick a unit development pick of phase two pick
a phase three and then as we continue to go to the east we
see Quaka and Midcock now on state lands and in the
Prudhoe Bay unit again farther to east the Omega
patent iPad are on the very western edge of the Prude
Bay Unit and as director Nottingham mentioned just south
of The Millney Point Unit so a continuation of
the trend that Hillcorp has been very successful with.
And then the last three projects for the Alaska North Slope we considered for this year are south of Prudhoe Bay, and that's the Theta West, Talitha and Alcade projects.
Senator Stedman.
Just briefly, could you get back to the committee on the, I think it's Pika that is coming on this
year that gives us kind of an anomaly blip up from our historical projections.
So if you could break those barrels out for us per day, it should be easy to do.
for FY 27.
Commissioner.
Senator Sevein, through the chair, John Crowler,
for the record.
Be happy to share that with the committee.
For the Committee's reference, the project
is expected to come on this quarter,
so in the coming months, come
on at a rate of maybe 20, 30,000 barrels per day
at the startup, and then ramp up through
the the next coming month, in this year,
reach 80,00 barrels a day.
But we'll share the information with
the Commission.
Senator Stegman.
Yes, just the aggregate.
per year barrels for this year next year, that would work.
I don't need anything too fancy, but that'll make it easy to keep track of the underlying production.
How it's moving versus these two additions.
Understand, thank you Senator.
Thank you, Senator Stidman.
Mr. Peltier, please continue.
For the record, Travis Piltier.
So we're moving on to slide 16 now, the fall 2025 production forecast results in summary.
So this is a chart. We've already seen this one on slide 4.
So I'm not going to go over the chart again, but I will talk about the bullet points that we see here on the short term.
The DNR forecast for fiscal year 2026 annualized average daily
statewide production is going to be expected to
be 464,500 barrels of oil per day with nor slow production
averaging 457,000 barrels
of water per Day. Again, we do put a range on here.
It's roughly plus or minus 5% is how it turns out.
So the low end of the range and the high end
of range goes from 418,400 barrels
of work a day to 495,300 barrels
The operator line for fiscal year 2026 sums to 476,000 barrels of oil per day.
So you can see our forecast summary versus theirs is about a 19,00 barrel of
oil-per-day difference. In the long term, our forecasts is gauged by a comparison
between both the operator's aggregates and our internal forecast. We're hoping
that we're happy to see that the Operator long-term outlook falls within our range
There is a large discrepancy, don't get me wrong,
but it's not massively different.
And then the outlook, of course,
assumes that production plans from the operators
remain unchanged.
So as activity changes, our assumptions become outdated.
We have to adjust the forecast.
And we do that twice a year.
Once in the fall, which we wrapped up in late November,
early December, and we'll refresh this again
for this body in March.
Moving on to slide 18.
So I promised an 18-month view of daily data
from a chart we'd kind of shared earlier.
So this is the daily actual rate.
And again, the high frequency line
is that daily run ticket monthly.
And then you have a forecast line in blue
that you can see early on in time
for July, August, September, October, November, and December.
It just so happens that the Daily Run Tickets monthly data
in the forecast matches up quite well.
So there's no real discrepancy there.
Again, if we look at the cumulative production barrels,
what we looked for is kind of a break, you know,
how much gap is there between the dashed line
that pretty much goes up straight
versus that orange line.
As long as they are tracking together, things look good.
We're happy about that as we put this chart together the last data
We had day we had data for when we have to submit this was January 14th
And right now we're running a little over but I wouldn't get you know
I always get more excited in the June timeframe than I do right?
Now so
What I wanted to highlight however was we we've talked a lot today about pick a phase one coming online at the end of March
2026 and that ramp up is gonna start
I don't want to say slow, but it's not going to start up at 80,000 barrels of
water per day. We're expecting initial production at a fraction of that and to
hold steady while the new operation starts up and the operators figure out
how to best optimize and run the plant.
We do however expect that ramp up to occur in the summer of 2026.
That does coincide with summer turnaround activity from the legacy fields.
So as summertime temperatures increase,
are less efficient on gas processing,
so you naturally see oil production decline anyway
in the summer months.
So along with that, those operators take the time
in a summer to do summer maintenance
and turnaround activities.
So as pick is ramping up at the exact same time,
the legacy field will be going
into the Summer Slowdown phases.
And so those activities will finally ramp up
in end of the December, August of 2026.
That's when you see a large production increase
on this chart, and that has to with the pick
combined then with the cessation of some return route activities with
the legacy fields on the north slope. So that's why you see that production
increase finally in fiscal year 2027.
Moving on to slide 19, I believe this is the last slide that we have with charts.
The Alaska statewide annualized forecast production categories.
I just want to highlight both of the charts, again, for brevity.
What we had on the left-hand chart is production forecast categories,
again the current production category in blue, which shows the importance of
the legacy fields. The next 12 months only of drilling within those legacy
fields is under development or the orange wedge that
While it's a small wedge, it is a very material wedge.
So it very important that we continue to see drilling activity across the North Slope
and then in the under evaluation, that gray wedge all the drilling in years 2 through 10
along with the new projects are included in that.
Overlaid on this is the spring of 2025 production forecast
just to the see the change from last year to this year.
The time uncertainty for us on pick a phase one is extremely narrow this year, whereas
in years prior, we still kept a relatively large range of time uncertainties.
That's why you see in 2027, this current forecast exceeding spring of 2025's forecast in the
near term.
If you look at the chart on the right, again, the gray bars, they're very similar in time.
We do have some projects shifting out kind of in the three to five year time frame where
the time uncertainty increased from various operators.
Because of that, you do see a gap showing between the spring of 2025 forecast on projects
only and this current forecast.
Pipeline back in the day
2 million and what?
Yeah, I was a director notting him was just reminding me it's a two million barrels of oil per day was it was around peak
I can't recall if it is two or two point five
But definitely in The Order of magnitude two Million barrels a boil per Day. I remember those days. Oh, which they could come back
But the further question is
It is expected that the oil production on the slope
will continue for decades to come.
Chair Hoffman, yes.
Are there any additional questions
that finance members may have of the department?
Do you have any closing comments, commissioner?
Yeah, Chair Hoffman, my colleague Travis, I think, may have some closing comments as
well.
I would just say as we shared at the outset, we have a good news story here to share today,
and that's that there's enormous amount of activity occurring, enormous amounts of investment
occurring and we're seeing production increases.
And we'll work with the committee to provide additional specific information on the topics
discussed today.
A little bit hectic, but that concludes the work that this committee has today and our
next meeting will be tomorrow, Friday, January the 23rd at 9 a.m.
We will get the revenue forecast from the Department of Revenue.
Anything else to come before the meeting?
With that, we will adjourned.