Legislature(2025 - 2026)ADAMS 519
01/22/2025 01:30 PM House FINANCE
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| Audio | Topic |
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| Start | |
| Presentation: Production Forecast by Department of Natural Resources | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
HOUSE FINANCE COMMITTEE
January 22, 2025
1:32 p.m.
1:32:39 PM
CALL TO ORDER
Co-Chair Josephson called the House Finance Committee
meeting to order at 1:32 p.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Andy Josephson, Co-Chair
Representative Calvin Schrage, Co-Chair
Representative Jamie Allard
Representative Jeremy Bynum
Representative Alyse Galvin
Representative Sara Hannan
Representative Nellie Unangiq Jimmie
Representative DeLena Johnson
Representative Will Stapp
Representative Frank Tomaszewski
MEMBERS ABSENT
None
ALSO PRESENT
John Crowther, Deputy Commissioner, Department of Natural
Resources; Travis Peltier, Petroleum Reservoir Engineer,
Resource Evaluation Section, Division of Oil and Gas,
Department of Natural Resources; Derek Nottingham,
Director, Division of Oil and Gas, Department of Natural
Resources; Representative Elexie Moore.
SUMMARY
PRESENTATION: PRODUCTION FORECAST BY DEPARTMENT OF NATURAL
RESOURCES
Co-Chair Josephson recognized House Finance Committee
nonpartisan staff and LIO staff. He relayed that the first
order of business and the legislature's constitutional
responsibility was to pass a budget. He stated that the
committee would focus on the operating, mental health, and
capital budgets. He relayed that Co-Chair Schrage was in
charge of the capital budget and Co-Chair Foster was
responsible for legislation. The committee would hear a
presentation from the Department of Natural Resources
(DNR).
^PRESENTATION: PRODUCTION FORECAST BY DEPARTMENT OF NATURAL
RESOURCES
1:36:35 PM
Representative Josephson invited committee members to ask
questions along the way.
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, introduced himself. He relayed that the
department had a significant amount of positive information
to share.
TRAVIS PELTIER, PETROLEUM RESERVOIR ENGINEER, RESOURCE
EVALUATION SECTION, DIVISION OF OIL AND GAS, DEPARTMENT OF
NATURAL RESOURCES, provided a PowerPoint presentation
titled "Fall 2024 Oil Production Forecast," dated January
22, 2025 (copy on file). He shared that he joined the
department three years ago and had been working on the oil
production forecast since that time. He detailed that the
presentation would address Alaska's oil production forecast
for the next decade in addition to how the forecast did in
the fall of 2023 with respect to 2024.
Mr. Peltier began on slide 2 showing a reference list of
acronyms. He noted the appendix included two additional
slides including a table showing royalty by different
property types and a map of units across federal, state,
and joint properties showing the difference in royalties.
He did not intend to cover the appendix slides during the
presentation.
1:39:40 PM
Mr. Peltier reviewed the agenda on slide 3. The
presentation would include an introduction and forecast
preview, the FY 24 review with a focus on the North Slope
and Cook Inlet basin, the DNR fall 2024 production
forecasting approach, and the fall 2024 forecast results
and summary.
Mr. Peltier turned to a graph on slide 4 titled "Fall 2024
Forecast: North Slope." The y axis of the chart showed the
fiscal year annual average daily production of barrels of
oil ranging from zero to 1 million barrels per day. He
noted the graph showed annualized average numbers with just
ten data points. The x axis showed fiscal years 2025
through 2034. The middle blue line on the graph reflected
the fall 2024 Department of Revenue (DOR) official forecast
in the Revenue Sources Book. He noted the DNR production
forecast was incorporated into the Revenue Sources Book by
DOR. The graph also included a high and low forecast. There
was always uncertainty in the forecasting and the
department never knew for certain how things would work
out. He detailed that the high and low forecasts for FY 25
started out at about plus and minus 5 percent respectively.
Uncertainty grew over time, which resulted in a broadening
spread in future years.
Mr. Peltier explained that DNR had confidential
conversations with operators to compile information. For
the purposes of the North Slope forecast, DNR aggregated
all of the operator forecasts for currently producing
fields and used the information as a comparison with the
department's expectations. The operator forecast [shown as
a dotted line] was the summation of all the producing units
on the North Slope going into the future. He noted that the
DNR forecast included future projects, but the operator
forecast did not. He explained that future projects such as
Pikka were not included in the operator forecast because
the department did not request the information.
1:42:43 PM
Mr. Peltier moved to slide 6 titled "FY2024 as Forecasted
by DNR in Fall 2023: How Did We Do?" He began with a chart
showing FY 24 North Slope forecast on the right side of the
slide. The chart showed the fiscal year annual average
daily oil production for 2024 going from zero to 600,000
barrels of oil per day. The high and low scenarios shown on
slide 4 were reflected in the bar chart as approximately
519,000 barrels and 422,000 barrels respectively. The
official forecast was approximately 470,000 barrels. Actual
production during FY 24 was 461,000. He noted that DNR
forecasted roughly 2 percent more than the actual
production. He explained that the actual production was
within DNR's range of acceptability of plus or minus 5
percent, but DNR's forecast was high. He added that the
operator forecast was very close to DNR's at around 468,000
barrels, which was also high compared to actuals.
Representative Stapp believed it was the third consecutive
forecast where the actuals were lower than DNR's forecast.
He understood there was margin of error in the forecasting,
but he was curious why the state's forecast had exceeded
actuals several years in a row.
Mr. Peltier answered that the department worked annually to
determine whether there was a bias in its forecast and
whether it was doing something wrong in its calculations.
He relayed that the department had identified a calculation
bias the previous year. He pointed to the second bullet
point on slide 6 that reported DNR's forecast was
approximately 2 percent higher than actual FY 24
production. He clarified that 1 percent of the 2 percent
difference was a result of the calculation bias, which had
been addressed and fixed for the current year. The other
couple of major unforeseen components that occurred the
previous year related to oil field operations. He explained
that the Point Thomson sales line froze in mid-January and
did not resume operations until late May. Additionally, the
total well count expected by the department had not been
met. He would provide further detail on a future slide.
1:45:44 PM
Mr. Peltier continued to review slide 6 pertaining to
forecast factors currently on the horizon. He highlighted
that there was continued industry interest in the Brookian
Age plays (i.e., Nanushuk) on the North Slope. There was
substantial activity and exploration drilling in the east
and development plays (i.e., Pikka and Willow) on the
western part of the North Slope. He relayed that recent
federal regulatory and leasing restrictions had presented
challenges, which may change materially with the new
administration. He noted that with Pikka and Willow ramping
up their construction activities there had been equipment
constraints on the North Slope. Overall, the operations
costs had been impacted by resources being used by
construction activities.
1:47:00 PM
Mr. Peltier turned to slide 7 titled "FY2024 as Forecasted
by DNR in Fall 2023: Monthly Forecast with Daily Actuals."
The chart showed oil production daily rates from zero to
600,000 barrels of oil per day. The chart showed monthly
forecasted data reflected by a solid line overlaid with the
actual Trans-Alaska Pipeline System (TAPS) North Slope
production on a daily frequency. The chart included a
dotted line reflecting cumulative production going from
zero to 300 million barrels on the right. He highlighted
that actual production varied substantially; it was
impossible for DNR to forecast daily variations, but the
forecast was relatively close. He pointed out a separation
occurring beginning in January reflecting the Point Thomson
sales line freeze along with the cumulative affect of the
number of wells drilled on the North Slope and some
variations on the forecast for various fields.
1:48:40 PM
Co-Chair Schrage asked about the impetus behind the slide
and the month by month forecast.
Mr. Crowther referenced the earlier question by
Representative Stapp about historical accuracy looking
back. The department thought that adding more information
and more historical detail would help explain the small
variances and give more credibility and information to the
legislature and public. He noted that the committee would
see the same format later in the presentation as well.
Representative Hannan asked if the department went back and
adjusted the 1 percent in FY 24. Alternatively, she
wondered if the calculation bias had only been addressed in
future forecasts.
Mr. Peltier answered that DNR did not fix the calculation
bias for prior years. The presentation included the
calculation bias. The change would only appear in future
forecasts.
Representative Hannan asked if the future was FY 25 or FY
26.
Mr. Peltier answered FY 25.
Representative Galvin observed there was a slip in
production in May through August. She thought it was fairly
normal to see a slip during that time. She asked if there
was anything outstanding that occurred to result in the
decline.
Mr. Peltier answered that the summer months were
exceedingly hard to forecast. He explained that major
facility turnarounds occurred during that timeframe. He
believed the downturn shown on the slide was indicative of
the turnaround season on the North Slope in the major
facilities. He shared that DNR had not gone back to take a
look at which facility was down at the time for the
forecast specifically. He noted that there was a recovery
in very early July.
1:51:40 PM
Mr. Peltier turned to slide 8 showing a summary of North
Slope production comparing FY 24 with FY 23. He relayed
that all fields were expected to decline year-on-year. He
noted that a decline may not happen every year, but
generally over a two-year period a decline in production
was expected in existing oil fields. The top chart on the
right of the slide reflected [North Slope] annual average
daily oil production from zero to 600,000 barrels. In FY
18, production was at roughly 518,000 barrels per day.
Production had declined to just under 461,000 barrels per
day in FY 24. He noted that the decline was not atypical in
a place like Alaska's North Slope. The change from FY 23 to
FY 24 was about 4 percent or a decline of about 18,700
barrels per day.
Mr. Peltier addressed a chart on the lower right of slide 8
showing production changes across North Slope assets from
FY 23 to FY 24. The chart listed decreases first, which
resulted in the 18,700 barrels per day. He noted that
increases were shown at the end of the chart. The Colville
River, Endicott and Kuparuk River units were all
experiencing natural decline offset with development
drilling. He stated it was good to see continued
reinvestment in the fields but it was not atypical to see
decline. He explained that Nikaitchuq, Northstar, and
Oooguruk fields were all experiencing natural decline and
did not reflect anything atypical. He noted there had not
been any new drilling to offset the decline and it was what
was expected from a mature field being water flooded. He
relayed that Prudhoe Bay was the largest oilfield on the
North Slope, producing well over 200,000 barrels of oil per
day. He detailed that the decline number looked high, but
it had to do with the fact it was such a large producing
field. Additionally, there had been a relatively deep
turnaround in Prudhoe Bay in August 2023 that impacted FY
24. The last decrease shown on the chart pertained to the
frozen sales pipeline at the Point Thomson field in the
first half of 2024.
Mr. Peltier addressed increases on the North Slope in FY 24
on slide 8. The first increase was at the Badami field
where well work brought one of the field's biggest wells
towards the end of FY 24. The Greater Mooses Tooth Unit had
a new pad called GMT2, which the operator had continued to
develop, resulting in production growth. The last increase
was on the Milne Point field. He elaborated that the field
had continued to see year-over-year production increases
due to the operator's activity.
Co-Chair Josephson recognized Representative Justin
Ruffridge in the room.
1:55:40 PM
Representative Stapp asked for a summary showing the fields
in aggregate in terms of the ownership and operator. He
stated it would be easier for him to parse through with the
declines and increases if he could see the field, land
(i.e., state, federal, Native land). He explained that it
would help him get a bigger picture of the overall revenue
pertaining to production.
Co-Chair Josephson asked the department to route the
information through his office.
Representative Johnson asked if the policy of the
department was to encourage as much development as possible
at all times.
Mr. Crowther answered that it was DNR's policy and
statutory obligation to ensure there was full development
occurring on all legacy and new fields. He relayed that the
presentation would cover some of the new activities
occurring. He referenced the decline shown for legacy
fields on slide 8 and explained that in many cases the
fields had been operating for decades and there was
significant investment going on. There were also many new,
exciting projects taking place on the North Slope that the
department thought would bring increased production in the
future for new fields or reinvigorated activity in existing
fields. He noted there had been a couple of significant
transactions on the North Slope changing operatorship and
ownership of legacy fields. He highlighted there had been
new pad development on the Milne Point field that resulted
in an impressive production turnaround, rivaling production
levels from the field 20 years back. The turnaround started
about 10 years back when Hilcorp became the operator and
had started work on a new pad and work on recovery
methodologies. He pointed out that Nikaitchuq and Oooguruk
had previously been operated by ENI, but the assets had
been sold to Hilcorp. In light of the geologic
similarities, DNR believed some of the applications that
occurred on the Milne Point field could occur for the
Nikaitchuq and Oooguruk fields in the future.
1:59:41 PM
Representative Galvin asked when Prudhoe Bay would reach a
typical hyperbolic curve and would level off instead of
seeing the decrease.
Mr. Crowther deferred to a colleague with past private
sector expertise managing the field.
DEREK NOTTINGHAM, DIRECTOR, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, replied that DNR believed
the Prudhoe Bay field was already in a hyperbolic decline.
He explained that a 3 to 4 percent decline per year was an
expected base level decline. He elaborated that 10,000
barrels per year was close to that amount, with some
additional production losses due to a longer turnaround
time. He relayed that there was significant capital
investment and drilling that went into maintaining the 3 to
4 percent decline. He detailed Hilcorp and its partners
were active in the field with well work, drilling, and
facility projects.
2:02:02 PM
Mr. Peltier continued to review slide 8. He pointed to a
website link at the bottom of the slide and explained that
the Division of Oil and Gas worked with the Alaska Oil and
Gas Conservation Commission (AOGCC) the past year to
publish its oil production data in a chart form at the
field, pad, and well level. He turned to slide 9 titled
"Status Update: Milne Point Unit." The slide showed daily
production rates at Milne Point beginning when BP took
operatorship in early 1995 through the last month of
November 2024. The left side of the chart showed the
average daily oil production rate per month and the right
side of the chart showed the water daily production rates.
He focused on the oil production which ranged from zero to
60,000 barrels per day on the chart. He detailed that when
BP was the operator it achieved a maximum rate of just
under 59,000 barrels per day in 1998. The field had
declined to just under 19,000 barrels per day in November
2014. Hilcorp assumed operatorship of the field in November
2014 and had started a drilling program, developed two new
pads, and implemented some enhanced oil recovery projects.
As a result, the average daily production in November 2024
was 47,465 barrels per day. The production was the highest
it had ever been under Hilcorp operatorship and DNR had
high confidence the field would continue to see production
growth and exceed 50,000 barrels of oil per day due to all
of the effort.
Mr. Crowther noted it was extremely unusual to see the
shape like the one shown on slide 9 for the production life
history for fields.
Co-Chair Josephson thought that would be true and remarked
that it was good to see.
Mr. Peltier referenced the two new Milne Point pads he had
mentioned on slide 9. He detailed that one of the most
recent pads discussed on the North Slope was called Raven
Pad (R-Pad) and had been on the department's key future
project list the previous year. The pad had been developed
a full fiscal year faster than DNR had expected. Slide 10
showed a status update of six key future projects on the
North Slope. The projects were listed in chronological
order based on when the department expected them to come
online. The KRU Nuna-Torok project was a new pad within the
Kuparuk River Unit (KRU), the Mustang Unit was a new single
pad development to the west of KPU, and the Colville River
Unit (CRU) Minke project size was to be determined.
Additionally, the slide showed the large North Slope
projects including Pikka Phase 1, Pikka Phase 2 (new unit
and processing facilities), and Willow.
Mr. Peltier provided a status update of each of the six
fields listed on slide 10. He began with KRU Nuna-Torok and
relayed that in 2024 funding had been approved for the
project and it had been under construction with anticipated
first oil in 2025. He reported that production began in
December 2024 under the operator ConocoPhillips. The
department had an internal expectation for a peak rate of
around 20,000 barrels per day for the project. He moved to
the Mustang Unit and relayed that Finnex had taken over
operatorship from the Alaska Industrial Development and
Export Authority (AIDEA) in October 2023. Since that time,
Finnex had worked hard to expand the pad, conduct pipeline
tie-in activities, and other restart activities, in
addition to drilling two development wells in 2024.
Production had started on the work in the past month and
the department expected peak production of about 4,000
barrels per day.
2:07:20 PM
Representative Bynum referenced slide 9 showing an abnormal
curve where production had declined, the operator had
changed, and production had increased. He asked if there
was specific information available on the result of the
increased production. If so, he wondered if a policy would
be put forward to ensure the mistakes resulting in reduced
production would not be made in the future.
Mr. Peltier replied that Hilcorp had chosen to invest
substantial time drilling new wells at Milne Point, while
the previous operator BP did not drill as many wells.
Additionally, the well architecture had changed. He
detailed that Hilcorp had elected to drill simpler wells
that were easier to manage compared to what BP had been
drilling in the past. He believed the shift [indicated on
slide 9] was the result of the continued change of new
drilling. He added that the Schrader Bluff reservoir was
leading the change. He elaborated that the large production
wedge shown for BP in the past was from the Kuparuk River
formation, which had declined and continued to decline.
There was Schrader Bluff drilling at that time as well;
however, BP was challenged with the cost of doing the work.
When Hilcorp implemented its drilling, it was mostly
focused on the Schrader Bluff resources; there was a large
volume of resource potential in the Schrader Bluff that was
untapped when Hilcorp took over operatorship.
Representative Hannan looked at the Mustang project on
slide 10. She asked how long AIDEA had been the unit
operator prior to Finnex taking over and whether there were
any other units AIDEA was operating.
Mr. Peltier would follow up on the question.
Mr. Crowther would confirm the period of operatorship. He
relayed that AIDEA acquired the assets as a result of a
series of complex financial and bankruptcy transactions. He
did not believe AIDEA had a primary intent to retain and
develop the field. He elaborated that AIDEA had worked to
bring in partners and transfer the field to an operating
company, which it had successfully done. Subsequently, the
company had succeeded in bringing the field back into
active production.
2:10:22 PM
Representative Hannan asked if the Mustang field sat idle
with AIDEA for multiple years or a period of months. She
knew there were some legal issues that led to the result.
She asked if there were any other units where AIDEA was the
operator even if the field was not currently operating.
Mr. Crowther replied that the department would follow up
with the information. He stated that AIDEA was not
presently the operator of any other North Slope units.
2:11:23 PM
Mr. Peltier resumed his explanation of the fields on slide
10 beginning with the CRU Minke field. He noted that the
project had not been included in the department's key
future projects list the previous year. He explained that
in the past year ConocoPhillips drilled an exploration well
CD5-32X. Based on the results of the exploration well,
Conoco planned a producer-injector well-pair to be drilled
in the current winter. He noted that future production
would depend on the performance of the producer-injector
pair.
Mr. Peltier addressed large projects being installed on the
North Slope. Pikka phase 1 had been under construction the
previous year when DNR presented to the committee, and it
was still under construction. First oil was initially
expected in Q1 of 2026 and it was now expected in Q2 of
2026. He added that Santos had indicated in its investor
presentation it was targeting trying to get the field
online in December of 2025. The peak rate for the project
was 80,000 barrels per day. Pikka phase 2 was expected to
follow phase 1. The department expected the project to move
to the FEED [Front End Engineering and Design] stage in
2025 with a final investment decision (FID) in 2027. There
was potential for an additional 80,000 of production
capacity from phase 2. The department was looking forward
to seeing Pikka phase 1 come online in the next 12 to 18
months.
2:13:13 PM
Mr. Peltier addressed the ConocoPhillips Willow project at
the bottom of slide 10. He relayed that a Bureau of Land
Management (BLM) record of decision on the supplemental
environmental impact statement (SEIS) was issued in 2023,
which enabled construction to begin in April of 2023.
Conoco announced FID in December of 2023. He detailed that
first oil was expected in 2029 and the peak production rate
was expected to be 180,000 barrels per day.
Co-Chair Josephson looked at the chart on slide 4 and
thought it appeared the department was being hopeful that
the Pikka project would produce the full 160,000 barrels.
He asked if his understanding was correct.
Mr. Peltier replied that he would address the question on a
slide later in the presentation.
Mr. Crowther highlighted that the legislature passed a
unanimous resolution in support of the Willow project,
which had positive results for the project. He thanked the
legislature for the resolution. He remarked that the
projects were getting closer to startup and the volume of
new production was unseen in modern Alaska. He stated the
projects reflected a turnaround and growth that rivaled the
startup of the Kuparuk River field. He added that the
argument could be made that it rivaled Prudhoe Bay in terms
of new activity and volume of production. From the
department's perspective, it was a major change in the
paradigm on the North Slope. He stated it was very
exciting.
2:15:44 PM
Mr. Peltier turned to slide 11 titled "FY2024 Summary: Cook
Inlet." He pointed to a chart on the top right of the slide
showing Cook Inlet daily production. He relayed that Cook
Inlet had been in production for over seven decades. The
field had a large production number in the past; however,
there had been seven decades of decline. The chart showed a
daily production range of zero to 20,000 barrels [from FY
17 to FY 24]. The chart reflected a production peak of just
over 15,000 barrels of oil per day in FY 18, declining to
around 8,500 barrels per day in FY 24. There was a
production decrease of 450 barrels per day (5 percent)
between FY 23 and FY 24. He highlighted that the oil from
Cook Inlet was critical to the supply of instate
refineries; the oil was used to create aviation fuels for
use in the Southcentral Railbelt region.
Mr. Peltier addressed a chart on the lower right of slide
11 reflecting production decline by field. He relayed that
Beaver Creek, Granite Point, Hansen, McArthur River, and
Swanson River units were all experiencing natural decline.
The fields were all mature and the operator was doing as
much as possible to produce as much oil as possible, but
there had been no real drilling for oil in the Cook Inlet
for some time. The Redoubt Shoal had natural decline;
however, rate-adding well work had restored some oil
production and cut into the natural decline. The Kenai Loop
and Middle Ground Shoal fields were effectively offline.
They were reflected on the chart because they were existing
units, but both were producing at a zero rate. He noted
that Swanson River was experiencing natural decline.
Trading Bay and West McArthur River fields were producing
more oil in FY 24 than the prior year because well work
offset the fields' natural decline.
2:18:17 PM
Representative Galvin recognized slide 11 pertained to Cook
Inlet oil forecasting. She asked if the gas production
rates for the fields were similar.
Mr. Peltier answered that it depended on the field. He
explained that some fields had natural gas reinjection. He
elaborated that those fields produced a fair amount of gas,
but it was put back into the field to augment oil
production. He relayed that natural gas should be declining
with the oil production rate if managed pressure was being
used. He noted that the oil fields did produce natural gas
used in the Southcentral Railbelt; however, they were not
as key as the gas producing fields.
2:19:50 PM
Representative Hannan asked about a scenario where oil was
reinjected in the Kenai Loop or Middle Ground fields that
were effectively no longer producing oil. She asked if the
gas was still there and could be extracted.
Mr. Nottingham responded that if gas was injected into a
field for enhanced oil recovery some of the gas came back
out of the ground with the oil as the oil was matured. Some
of the gas would get trapped in the pore space, but a lot
of the gas did get produced along with the oil. He relayed
that if it was economical, there where techniques that
operators could use to recover the remaining gas.
2:21:23 PM
Co-Chair Schrage asked why the presentation did not include
a list of key projects for Cook Inlet. He asked if there
were not the volume of projects and activity in Cook Inlet
compared to the North Slope.
Mr. Peltier answered that there was one key project for
Cook Inlet. He added that the Cosmopolitan project was
included on a later slide.
Co-Chair Josephson referenced the use of gas for
reinjection and enhanced oil recovery on the Cook Inlet. He
asked if it would be more meaningful for home heating fuel
because the amount of oil production was de minimis
relative to the North Slope. He noted that rather than
burning the gas, it was being used for enhanced oil
recoveries.
Mr. Crowther replied that the oil produced in Cook Inlet
was entirely consumed by instate refiners, which led to
instate fuel and commodities there were some exports of
heavy and residual ends of the crude for things like
gasoline, aviation fuel, asphalt used in Southcentral. He
explained that the tradeoff would result in a fuel supply
problem of another kind. He noted there was already a fuel
supply problem in Cook Inlet as production declined. He
stated that the oil itself was very important. He relayed
that as operators came to DNR with development plans for
different projects, the department looked at what the
projects targeted and how the priority fit with other
things in the operator's portfolio. He noted that oil
continued to be important because of the need for fuel
supply and the operators' ability to make their own
development decisions. He added that the Cosmopolitan
project was a potential oil project. The department had
much more information about potential gas production from
existing fields and potential new resources that could be
presented to the committee at another time. He stated it
was related to some of the same dynamics impacting oil
production, but there were some unique factors DNR was
looking closely at.
Mr. Nottingham added there were no ongoing gas injection
projects for oil in the Cook Inlet. He believed the last
one may have been at Swanson River and the gas injection
for enhanced recovery was shut in several years back. He
would follow up with detail.
2:24:43 PM
Mr. Peltier transitioned to how DNR created the production
forecast. He relayed that there had been no change in
methodology in the past three years with the exception of
fixing the calculation error. He moved to slide 13 titled
"DNR Forecast Process: Projects/Pools Included in
Forecast." He explained that the department's production
forecast started with a decline curve analysis for all
existing production for all producing pools across the
North Slope and Cook Inlet. The forecast currently included
40 pools across the North Slope and Cook Inlet, which had
to be online and producing by June 30, 2024 or earlier to
be included in the decline curve analysis portion of the
forecast. Additionally, DNR worked with the Department of
Revenue (DOR) to have confidential in-person and in-writing
interviews with all of the operators. The operators
provided the departments with a fair amount of information
it could use to help gage the uncertainty on current
production and future projects.
Mr. Peltier relayed that at the end of the discussions with
operators the past fall, there were 16 large projects that
DNR considered to be under development or evaluation to
further include in its portfolio of large projects. He
reminded the committee that the information was
confidential; therefore, DNR could not talk about specific
projects other than to communicate that 15 were located on
the North Slope and one was located in the Cook Inlet. He
clarified that the production forecasting only included
oil.
2:27:07 PM
Mr. Peltier addressed slide 14 titled "Categories of
Production: Ongoing/Current vs Future Production." He noted
that the department broke production up in a number of
ways. He explained that existing fields were referred to as
current production (CP). He clarified that the category
pertained to ongoing production from existing fields with
the expectation that the fields had to be online before
June 30, 2024. He noted that the Nuna-Torok project from
the Kuparuk River Unit and the Mustang project were
included in the presentation as future projects because
they were not online on June 30, 2024. He reviewed features
and considerations pertaining to current production
including well and facility uptime, operator spending to
maintain base production, and major changes to reservoir
management.
Mr. Peltier continued to review slide 14. He relayed that
DNR had made a slight change to its definition for projects
under development. He explained that under development (UD)
pertained to investment and infield drilling on existing
fields. He highlighted that DNR was leaving all of the
large projects in the under evaluation (UE) category for a
risking perspective. He detailed that DNR never changed how
it risked the 16 large projects; therefore, it decided it
should not be changing UD or UE until they came online. He
noted that the categories had never been treated
differently. He relayed that UD and UE projects required
new investment to come online. He elaborated that there was
always uncertainty in future well performance and project
scope. Historical well performance data was used to gage
the uncertainty of the performance of new wells drilled in
existing fields; however, there was a lot more uncertainty
for new projects in terms of scope and timing. He explained
that economic and commercial risk associated with
variations in oil prices could impact when a project came
online. He noted that DNR did not include the risk
components for infield drilling projects.
2:30:03 PM
Mr. Peltier turned to a map showing the North Slope on
slide 15 related to major projects under evaluation
considered in the fall 2024 forecast. He reviewed the
general characteristics of major UE projects:
• Projects that were not online by end of FY2024 (data
cut-off date of 6/2024)
• Higher risk factors than currently producing fields
• Known discoveries with identifiable operators
• Require major investments
Mr. Peltier pointed to a map on slide 15 showing North
Slope major projects. The Willow development was located in
the west on federal property. The Colville River Unit
Narwhal CD8 and Minke projects were located on a mix of
state, federal, and private lands. Various Santos projects
were located a bit farther east and included Horseshoe
Stirrup, Pikka Unit Development, Pikka Phase 2, Pikka Phase
3, and Quokka/Mitquq. Next was the Mustang unit. Farther to
the southeast were the Theta West, Talitha, and Alkaid
projects operated by Pantheon Great Bear. He noted that
publicly the company called the Alkaid and Talitha fields
Ahpun and Kodiak. He noted that DNR had left the names as
Alkaid and Talitha to reflect the current unit names. He
relayed that it may change in the future and DNR would
change accordingly. Farther to the east was the Point
Thomson unit operated by Jade Energy, which included an
expansion project to increase production rate and the
Sourdough project, an unrelated oil prospect located in the
southern part of the Point Thomson unit.
Co-Chair Josephson asked if Point Thomson was still owned
by Exxon.
Mr. Peltier answered that the ownership was a combination
of Exxon and Hilcorp. He noted there were some other owners
as well. He relayed that Exxon was the majority owner and
Hilcorp was the operator.
Mr. Peltier reviewed the Fall 2024 North Slope annualized
forecast on slide 17. The chart showed the fiscal year
annual average daily oil production rate from 2025 through
2034 ranging from zero to 1 million barrels. The data came
from the DOR Revenue Sources Book. The department expected
average daily statewide production to be about 474,000
barrels of oil in 2025, with the North Slope accounting for
466,000 barrels per day. The range of uncertainty was
roughly 5 percent, ranging from 424,000 barrels of oil per
day to 510,000 barrels per day. The department expected
production to increase in the long-term as production
projects came online. He noted that the production forecast
was built on assumptions from the operators. He stated that
business plans could change; therefore, the slide showed a
static snapshot in time from the fall of 2024. The
department provided an updated forecast twice a year in the
spring and fall. He highlighted that the data on the slide
included information up to November [2024] and did not
reflect any changes since that time.
2:34:57 PM
Mr. Peltier asked to be reminded of Co-Chair Josephson's
earlier question pertaining to Willow.
Co-Chair Josephson looked at slides 10 and 17 and observed
that DNR appeared to be hopeful that Pikka phase 2 would
occur even though FEED had not yet been completed.
Mr. Peltier replied that part of DNR's process involved
bringing in 24 experts on various aspects for oil field
development to get a sense of their thoughts on the risks
of each of the projects and to learn whether they believe
the projects would happen and what year they would come
online. He relayed that Pikka phase 2 had been part of the
department's project portfolio for years. He stated that
with the continued development of Pikka phase 1, the
confidence that Pikka phase 2 would come online had
increased, but DNR did not consider it to be a foregone
conclusion. The chance of its occurrence had increased from
the previous year, but it was not guaranteed. He noted that
the production bump indicated on the chart in the 2030
timeframe was more of a direct effect of Willow production.
Co-Chair Josephson recognized Representative Elexie Moore
in the audience.
Representative Bynum asked if the information from
operators took into consideration the improvement in
technology resulting in better production from fields in
the future. Alternatively, he wondered if it was based on
operating plans in place at the time of development.
Mr. Peltier answered it was a combination of both. He
stated that sometimes there was talk about brand new
technologies. He liked to use the wait and see approach at
times. He referenced Milne Point as an example and
explained that using existing technology in a new way had
been extremely beneficial. He relayed that DNR took it into
account.
2:37:40 PM
Co-Chair Schrage observed that a final investment decision
for Pikka phase 2 was expected around 2027. He asked when
the project was expected to meet peak production.
Mr. Peltier answered that first oil was expected about
three to four years after FID. He added there was a range
of uncertainty around the timeline.
Mr. Peltier advanced to slide 18 titled "FY2025 as
Forecasted by DNR in Fall 2024: Monthly Forecast with Daily
Actuals." He shared that it had been seven weeks since the
department published its fall 2024 forecast. A chart on the
slide showed oil production rate on the left and cumulative
oil production on the right. The forecasting monthly data
for FY 25 shown in blue reflected the department's
forecast. He noted that the data on the slide was not
something DOR published, DNR published it specifically for
the presentation. The chart showed the Alaska North Slope
(ANS) daily production for FY 25. He pointed to the
cumulative forecast over time (the orange segment of the
line reflected actuals and the dotted portion reflected the
forecast) and relayed that prior to submitting the
presentation, DNR had data through January 15, 2025. He
remarked that DNR's forecast and actuals were right on. He
noted that seasonal turnaround time came into the forecast
around the end of August/early September, but by the time
they averaged out, DNR had about matched actuals, which was
a good start for the forecast cycle.
2:39:47 PM
Mr. Peltier turned to slide 19 titled "Fall 2024: AK
Statewide Annualized Forecast (Expected Case with
Production Categories)." The slide showed changes from the
spring 2024 forecast to the fall 2024 forecast. The chart
on the left showed annual average daily oil production
ranging from zero to 700,000 barrels per day. The blue
wedge showed current production and the orange reflected
the next 12 months of expected infield drilling on the
North Slope. He explained that due to the definition
change, all future projects and future infield drilling
from years two through ten were included in the gray wedge.
He highlighted that the current forecast was slightly less
than the forecast for the previous year; it took into
account how fields had performed over the past year, minor
modifications had been made, and it was a slightly smaller
forecast for FY 25. He noted that DNR anticipated that
factoring in projects such as Willow and Pikka phase 2
would exceed the forecast from 2024 in the next seven to
ten-year timeframe.
Co-Chair Josephson looked at the last bullet point on slide
19 and remarked that the Pikka and Willow projects were in
between under development and under evaluation. He asked if
it was appropriate to say the two projects were under
evaluation.
Mr. Peltier answered that Pikka and Willow would remain in
the under evaluation category until they began producing.
He elaborated that the tools used to calculate the risk of
projects coming forward would not change by simply moving
the projects to the under development category.
2:42:22 PM
Mr. Crowther remarked that the department was struggling a
bit to clearly present such a significant new greenfield
project because there had been significant new pads or well
programs within existing units, but there had not been a
50,000 to 100,000 barrel new greenfield project go into the
currently producing wedge for some time. He stated it was a
good problem to have in terms of how to communicate it.
Mr. Peltier highlighted the chart on the right side of
slide 19. The chart showed production bumps expected from
future projects that would come online within the next
three years. Additionally, the chart reflected another
tranche that would come online in years six through ten.
Overlaid with that was the spring 2024 forecast. He pointed
out the difference indicating the increased confidence
pertaining to projects in the outyears.
Representative Galvin observed that as the forecasts got
closer the level of certainty increased. She wondered if
forecasts made ten years ago projecting the present day
production would have relied on the majority of production
coming from projects under evaluation at the time.
Mr. Crowther responded that there had always been under
evaluation projects. He elaborated that ten years ago, the
under evaluation contribution was highly speculative and
much smaller and there was a forecast that trended into a
production level of 300,000 [barrels] or less. He stated
that very fortunately current production was approximately
460,000 to 470,000, dramatically beating the forecast from
ten years ago. He explained it was due to numerous factors
including infield work, small projects, and rate
maintenance. They were moving to a scenario where there
were large "mega projects" in the Alaska sense, potentially
coming online and changing DNR's ten-year trajectory. From
his perspective, it was a two-point win for the state and
the people of Alaska because they were dramatically beating
the forecast from ten years ago and the forecast for ten
years in the future was potentially better than the
present.
2:46:00 PM
Representative Galvin stated her understanding that DNR did
not believe the ten-year production projections would be as
far under as the projections ten years ago.
Mr. Crowther answered that there was a tranche of things
contributing to the positive forecast and outlook. He
detailed that the continued investment in legacy fields had
maintained in many cases rather than seeing a dramatic
decline (where instead of a 3 to 4 percent decline there
was an 8 to 12 percent decline, which was cumulatively
dramatic over a 10-year period). Additionally, the under
evaluation projects that were in construction and nearing
startup were viewed as a major new tranche. He stated that
exploration was a very exciting component. He explained
that it was speculative and not confirmed, but the
exploration activity was occurring in a variety of areas.
He stated it led him to have confidence that the 16
projects in the UE wedge may or may not proceed and may
contribute significantly ten years out. He expounded that
there were units with committed exploration programs and
current drilling. He explained that if one or more of the
programs turned into potential discoveries, it would
increase the UE category. It was very encouraging to see
that in every category and range of measurement, there were
things that could be added.
Representative Tomaszewski remarked that there was a 180
from the previous federal administration to the new Trump
administration with a number of executive orders targeting
Alaska and its industry. He asked if there were steps the
state should take to capitalize on the new administration
and how it would push for oil and gas production from
Alaska.
2:49:02 PM
Mr. Crowther responded that the potential for expanded
activity and exploration, which went to future activity
that may lead to discoveries and projects. He highlighted
exciting areas beginning with the coastal plain 1002 area.
He relayed that the department could present in more detail
the history and specific changes DNR was seeing with the
new [federal] administration. He explained it was an area
where if seismic data could be gathered and exploration
activity that could occur, it could be a major contribution
in the longer term to the state and national production.
The same dynamic was playing out in the NPRA to the west.
The Willow project in the area was a huge new discovery
that had moved into construction. There was significant
reason to believe there were geologic prospects that the
new federal administration was committed to supporting in
its executive order. He noted that the governor was focused
on working with the Trump administration to have
coordination and move forward in the opportunities. He
relayed that the department was prepared to jump on the
opportunities.
Co-Chair Josephson recalled the discussion on Willow that
had been agreed on in the legislature. He remembered
looking at the previous Trump administration plan for the
NPRA and its predecessor Obama plan. He remarked that even
though there was a four-year term, the work did not happen
overnight. He asked for verification that the only
development thus far was in the far northeast corner of the
NPRA.
Mr. Crowther responded that the Greater Mooses Tooth Unit
and the Bears Tooth Unit or Willow project that were both
under production or active development and were located in
the northeast corner [of the NPRA].
Co-Chair Josephson remarked on what he viewed as a seesaw
back and forth between administrations on whether there
should be a two-thirds versus one-third or three-quarters
versus one-quarter available acreage for potential
development. He stated there was certainly hope for more
and an argument that it was needed. He asked for
verification that "these things take time."
Mr. Crowther agreed. He stated that when there was the
federal policy layer it included time, potential
litigation, and dispute over how to effectuate a
development imperative articulated by the new
administration. The department anticipated needing time and
substantial work to allow exploration and potential
additional leasing to occur. The department was very
engaged in participating and supporting that and the
governor had directed DNR to work expeditiously with the
new administration.
2:52:12 PM
Representative Stapp asked if there were any updates on a
situation involving Kuparuk [River Unit], a road, Santos,
and ConocoPhillips. He asked if the situation had been
figured out or if it was still a mess.
Mr. Crowther answered that DNR issued a permit to provide
for access and there was a legal challenge. There was a
superior court decision directing the permit to be vacated,
but the state had appealed the ruling to the state supreme
court. The appeal was proceeding, and the state was
evaluating with the parties how to move forward with the
litigation. The department maintained it was critical for
operators to work together to ensure the state's interests
were not impacted. Fortunately, the construction activities
had proceeded and there had not been disputes in real time.
The Pikka project had been able to proceed timely and the
situation had remained a legal, commercial, and corporate
dispute. The issue remained active for the state as the
department analyzed how to protect the state's interest in
the development and opportunities in the future such as
leasing of state or federal lands located on the other side
of existing road networks. There was more work to be done.
2:54:10 PM
Representative Johnson asked for verification that the
situation was not slowing down the Pikka development.
Mr. Crowther replied that he could not speak for the
operators or companies, but DNR had not yet seen a delay,
which was important. He remarked that the past construction
season had been very busy and there had been cooperation in
field activity operations for the development to proceed.
If the department saw something that was slowing it down,
it would be an immediate concern for the state and it would
do everything it could to prevent it from happening.
Representative Hannan believed the court ruling directing
the state to vacate the permit was in December. She asked
when the supreme court would decide whether to take the
case.
Mr. Crowther answered that the different administrative
stages had stretched on for several years. The superior
court final decision took place several months back and the
state promptly filed an appeal with the supreme court. The
appeal was proceeding and had not yet been briefed to the
supreme court. The state sought an emergency stay, which
the supreme court did not grant; however, it noted in its
order that the state had leave to seek a stay again if
there was any indication of actual challenges to the access
on the ground. The litigation would proceed with briefing,
subject to continued work to resolve the issue between the
companies themselves and also with the litigation with the
state.
Co-Chair Josephson asked if the trial judge was judge
[Andrew] Guidi.
Mr. Crowther replied that judge Guidi was the superior
court judge.
Co-Chair Josephson offered to provide a copy of the court
document to committee members. He discussed the schedule
for the following day. He noted that the oil price and
production were somewhat down from where the state hoped to
be, meaning there would be some patching to do in the
budget.
ADJOURNMENT
2:58:04 PM
The meeting was adjourned at 2:58 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2025 01 22 HFIN DNR Fall 2024 Production Forecast Presentation.pdf |
HFIN 1/22/2025 1:30:00 PM |
HB 53 |