Legislature(2025 - 2026)ADAMS 519
01/21/2026 01:30 PM House FINANCE
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| Audio | Topic |
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| Start | |
| Presentation: Production Forecast by the Department of Natural Resources | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
HOUSE FINANCE COMMITTEE
January 21, 2026
1:32 p.m.
1:32:21 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 Elexie Moore
Representative Will Stapp
Representative Frank Tomaszewski
MEMBERS ABSENT
Representative Nellie Unangiq Jimmie
ALSO PRESENT
Derek Nottingham, Director, Division of Oil and Gas,
Department of Natural Resources; Travis Peltier, Petroleum
Reservoir Engineer, Division of Oil and Gas; Representative
Jubilee Underwood.
SUMMARY
PRESENTATION: PRODUCTION FORECAST BY THE DEPARTMENT OF
NATURAL RESOURCES
1:32:50 PM
Co-Chair Josephson reviewed the meeting agenda.
^PRESENTATION: PRODUCTION FORECAST BY THE DEPARTMENT OF
NATURAL RESOURCES
1:34:36 PM
DEREK NOTTINGHAM, DIRECTOR, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, noted that Acting
Commissioner John Crowther could not attend the meeting due
to a prior commitment. He stated that he wanted to begin by
providing a high-level overview of the production forecast
before turning to his colleague to discuss the details. He
stated that 2026 was a significant year because new
production was expected to come online from the Pikka
project.
Mr. Nottingham stated that substantial progress had
occurred over the previous year on the Pikka project,
including construction activity, facility installation, and
the drilling of multiple wells. He characterized the
progress as significant. He added that notable progress had
occurred on the Willow project and other major North Slope
developments. The forecast also included information on
ongoing activity at existing fields, including the Milne
Point Unit (MPU). He stated that the production forecast
reflected several positive developments. Over the next ten
years, production was projected to increase from current
levels to more than 600,000 barrels per day by the end of
the forecast period.
1:36:40 PM
TRAVIS PELTIER, PETROLEUM RESERVOIR ENGINEER, DIVISION OF
OIL AND GAS, shared that he was a petroleum reservoir
engineer for the Division of Oil and Gas (DOG) within the
Department of Natural Resources (DNR). He graduated from
the University of Alaska Fairbanks (UAF) in 2006 with a
Master of Science degree in Mechanical Engineering. He
spent the previous 19 years working in Alaska's oil
industry, primarily on the North Slope, as a petroleum
engineer with BP. During his 14 years with the company, he
worked across all BP-operated fields, ranging from the
Kuparuk River Unit (KRU) to the Point Thomson Unit (PTU).
He joined DNR in 2021 and was asked to lead development of
the state's oil production forecast in 2022. He continued
to lead the effort and the team responsible for producing
the forecast on a biannual basis.
Mr. Peltier introduced the PowerPoint presentation, "Fall
2025 Oil Production Forecast" dated January 21, 2026 (copy
on file) and relayed that the presentation focused on
Alaska's oil production forecast for the upcoming decade.
He explained that DNR had conducted the analysis since
2016. He stated that the goal of the presentation was to
share production forecast results for FY 25 as well as the
ten-year forecast, including an overview of the methodology
and background used to generate the forecast.
Co-Chair Josephson recognized Representative Jubilee
Underwood in the audience.
Mr. Peltier continued to slide 2 which included a list of
acronyms for reference. He stated that the acronym "BOPD"
referred to barrels of oil per day and appeared frequently
throughout the presentation. He stated that additional
acronyms used on individual slides were listed at the
bottom of those slides for reference. He continued to slide
3 and outlined the structure of the presentation. He would
first review a preview of the forecast, followed by a
review of FY 25 production. The presentation would then
cover DNR's fall 2025 production forecasting approach and
the methodology used to generate the ten-year forecast.
Mr. Peltier advanced to slide 4 which included a chart that
displayed the fall 2025 North Slope annualized production
forecast. He explained that the left axis reflected fiscal
year annualized average daily oil production. For FY 26,
the internal forecast was approximately 460,000 BOPD. The
vertical axis ranged from zero to 1 million BOPD and each
data point represented a single fiscal year along the
horizontal axis. The chart incorporated information from
the Department of Revenue's (DOR) Revenue Sources Book,
including low, official, and high forecasts. He stated that
the chart also overlaid operator forecasts for currently
producing fields, which were provided confidentially and
were aggregated for use in the production forecast. He
noted that the operator forecasts were represented by a
dashed line. He relayed that there were differences between
DNR's forecast and the operator forecast. For FY 26, the
operator forecast was higher, but it decreased beginning in
FY 27. He emphasized that operator forecasts reflected only
currently producing fields and did not include future
developments such as the Pikka project, which was included
in the department's forecast.
1:40:50 PM
Mr. Peltier continued to slide 6 and explained that the
next portion of the presentation reviewed actual field
production rather than forecast data. He stated that FY 25
production was reviewed to assess forecast accuracy. He
relayed that DNR aimed for forecast uncertainty within plus
or minus five percent for the upcoming fiscal year. For FY
25, actual production exceeded the prior year's forecast by
0.3 percent. He drew attention to the chart displayed on
the right side of the slide. He stated that the vertical
axis ranged from zero to 600,000 BOPD. The high-end DNR
forecast for FY 25 was approximately 510,000 BOPD and the
low end of the forecast range was 424,000 BOPD. He
clarified that the mean forecast presented to the committee
the prior year was slightly above 466,000 BOPD, while
actual production concluded at just under 468,000 BOPD. He
noted that the result fell within the targeted plus or
minus 5 percent range.
Representative Hannan observed that the DNR forecast
appeared accurate, but operator projections were more
optimistic. She asked whether DNR conducted follow-up
inquiries to determine where the anticipated 20,000 BOPD
estimate had not materialized, or whether the discrepancy
resulted from aggregated data across multiple operators
rather than a specific development that failed to occur.
Mr. Peltier responded that DNR reviewed the data internally
at the field level but did not request explanations from
individual operators regarding overperformance or
underperformance relative to their forecasts. He explained
that operator projections were used solely as a comparator
and were not relied upon in developing the DNR forecast. He
explained that the operator forecast shown on the far right
of the chart reflected a combined total of just under
487,000 BOPD for FY 25.
Mr. Peltier continued reviewing slide 6 and described
several factors that were considered when shaping the
annual forecast. He explained that DNR often received
similar feedback from various operators working on the
North Slope and in Cook Inlet. He relayed that feedback
often highlighted continued industry interest in the
Brookian topset prospects on both state and federal land.
He noted that exploration results were recently released
from the Sockeye 2A well during the prior winter season and
demonstrated continued interest.
Mr. Peltier added that exploration activity on federal
leases had increased under the current federal
administration, with four wells proposed for exploration in
the National Petroleum Reserve-Alaska (NPR-A) during the
current year. He also noted that moderate oil prices and
capital discipline across the industry continued to present
challenges for development decisions. Additionally,
inflation, elevated interest rates, and insurance-related
challenges affected North Slope exploration costs and
operations.
1:44:57 PM
Representative Galvin asked for clarification regarding
inflation impacts. She noted that inflation had declined
over the previous year and had decreased from 5 percent in
January of 2025 to 3.7 percent in December of 2025. She
asked whether operators had identified an ideal interest
rate and she expressed uncertainty as to why inflation
continued to pose a significant challenge.
Mr. Peltier responded that oil field inflation differed
from consumer price index (CPI) inflation. He explained
that cost increases specific to oil field operations often
exceeded CPI trends. For example, between 2010 and 2014,
CPI increased by approximately 2 percent annually while oil
field inflation rose closer to 10 percent. He explained
that sustained cost escalation of that magnitude
constrained development activity. He noted that oil field
inflation continued to outpace CPI.
Representative Galvin asked if oil field inflation included
labor, subcontracting, and related operational costs.
Mr. Peltier responded in the affirmative.
Representative Stapp asked about the third and fourth
bullet points on slide 6 concerning oil prices and capital
discipline. He observed that the industry had made
significant capital investments in both existing
infrastructure and exploration wells during the current and
prior year and noted that the investment occurred despite
inflationary pressures and declining prices. He asked how
Alaska compared to other areas of the country. He remarked
that Alaska continued to attract interest in high-risk
plays, including Sockeye 2A, and appeared to remain a
competitive investment environment.
Mr. Peltier responded that he could not provide a direct
comparison of inflationary pressures between Alaska and the
rest of the country. Based on qualitative observations,
operating costs in Alaska were generally significantly
higher than in other areas of the country. He noted that
wells drilled in other states could cost several million
dollars, while comparable wells in Alaska were often more
expensive.
Representative Stapp asked what actions the legislature
could take that would most negatively affect continued
capital investment.
Mr. Nottingham responded that he could not identify a
specific legislative action that would be the worst course.
He emphasized that maintaining a competitive business
environment for Alaska, regardless of price conditions,
remained critical. The oil and gas industry was highly
competitive and companies had multiple alternatives for
capital deployment. He encouraged the legislature to
consider policies that preserved Alaska's competitive
advantages.
Co-Chair Josephson asked for clarification on the location
of Sockeye 2A. He understood that the Brookian topset was
west of Point Thomson. He asked if the Canning River was
also west of Point Thomson. He had visited Point Thomson
and he understood there were some disputed lands in the
area. He asked whether the prospective location was within
contested or uncontested areas.
Mr. Peltier responded that the Canning River was located
east of Point Thomson. He explained that the disputed
boundary involved the border between state lands and NPR-A.
He confirmed that the Sockeye 2A prospect was located west
of Point Thomson and was not near the disputed lands
associated with the river.
1:50:19 PM
Representative Galvin clarified that her earlier comments
referred to interest rates rather than inflation. She noted
that interest rates had declined and asked why operators
continued to identify high interest rates as a challenge.
She asked whether an ideal interest rate existed.
Mr. Peltier responded that the concern related primarily to
private financing rates rather than federal benchmark
rates. While Federal Reserve rates were publicly available,
private sector borrowing for development projects typically
carried significantly higher interest rates. He stated that
he did not have access to specific figures and noted that
such information was often confidential. He offered to
follow up if additional information could be obtained.
Representative Galvin asked for confirmation that Mr.
Peltier was referring to private lending rates above
federal benchmarks.
Mr. Peltier responded in the affirmative.
Representative Galvin noted the answer was sufficient and
she did not need a follow up.
Mr. Peltier continued to slide 7 and explained that the
chart displayed information similar to the prior slide. He
relayed that DNR had introduced the chart format during the
previous year. He noted that the chart presented a 12-month
forecast broken out by month. The left-hand axis reflected
oil production rates in BOPD, ranging from 0 to 600,000. He
stated that the orange curve with high-frequency
fluctuations represented daily production rates. The purple
line and the blue forecast line represented the monthly
forecast compared against the average of daily run-ticket
volumes. He explained that DNR generated monthly internal
forecasts and used the chart to compare those forecasts
against aggregated daily production.
Mr. Peltier explained that the right-hand axis reflected
cumulative production measured in millions of stock tank
barrels, ranging from 0 to 300 million barrels. He
described the straight orange line and the dashed blue line
as cumulative actual production and cumulative forecast
production, respectively. The total forecast for 2025 was
approximately 170 million barrels and actual production
finished slightly above the forecasted level. He emphasized
that the variance was minor and that the chart was intended
to show how daily production translated into monthly and
cumulative results. He added that an 18-month view would be
presented later to illustrate the anticipated impact of the
Pikka development scheduled to come online later in the
year.
1:54:00 PM
Representative Hannan understood that the chart began at
zero simply because it marked the first day of the fiscal
year. She asked if the most relevant information was the
cumulative total on the far right side of the chart.
Mr. Peltier responded that Representative Hannan's
interpretation was correct. He explained that the
cumulative forecast line was difficult to see because it
was largely overlaid by the actual cumulative line. He
noted that any meaningful forecasting error would appear as
a visible gap between the two cumulative lines. He
explained that if production underperformed in a given
month, a divergence would emerge over time. He pointed to
May 2025 and June 2025 as the point where daily actual
production slightly exceeded the forecast, resulting in
cumulative actual production marginally surpassing the
forecast. He emphasized that the difference was small.
Representative Hannan noted that on the prior slide, Mr.
Peltier had indicated that actual production exceeded the
forecast by 0.3 percent. She asked whether the cumulative
forecast remained within the acceptable margin, which she
understood to be within plus or minus 5 percent.
Mr. Peltier responded that the cumulative forecast remained
within the plus or minus 5 percent range that DNR targeted
on an annual basis.
Mr. Peltier advanced to slide 8. He explained that the
slide continued the review of actual field performance for
FY 25 and did not present new forecast information. He
reminded members that legacy North Slope fields, including
the Prudhoe Bay Unit (PBU) and KRU, were mature fields that
typically experienced year-over-year production declines
despite ongoing reinvestment by operators. Contrary to
typical expectations, total North Slope production
increased in FY 25 compared to FY 24. He reported that
basin-wide production rose by approximately 7,000 BOPD. He
characterized the increase as a positive outcome and
attributed it to sustained investment and reinvestment in
legacy fields.
Mr. Peltier directed attention to the charts on the right
side of the slide. He explained that the top chart showed
fiscal year annual average daily oil production for the
entire North Slope from FY 19 through FY 25. He noted that
production averaged approximately 495,000 BOPD in FY 19,
experienced fluctuations during FY 20 and FY 21 related to
the COVID-19 pandemic, and then generally declined through
FY 25, where average production was approximately 468,000
BOPD. The bottom chart showed the change in production
between FY 24 and FY 25, broken out by field. He noted that
the bullet points on the left corresponded to the chart.
Mr. Peltier relayed that there were production declines at
the Colville River Unit (CRU), the Greater Moose's Tooth
Unit (GMTU), and PBU. He explained that the declines
primarily reflected natural reservoir decline, partially
offset by development drilling. There were also declines at
the Endicott Unit and the North Star Unit (NSU) and no
development drilling or new wells occurred during the
fiscal year. He explained that the resulting volume losses
reflected natural reservoir decline. He relayed that PBU
produced more than 200,000 BOPD and a decline rate of less
than 2 percent for a field of its size was notable. He
emphasized that PBU formed the backbone of throughput into
the Trans-Alaska Pipeline System (TAPS) and he credited the
operator with effectively mitigating reservoir decline.
Co-Chair Josephson remarked that he was struck by the
performance of KRU and asked whether it was fair to
characterize it as performing strongly despite its status
as a legacy field.
Mr. Peltier responded that KRU production increased in FY
25. He explained that the operator, ConocoPhillips,
demonstrated strong base performance and undertook
significant new drilling. Recent projects such as the
Coyote Project had come online successfully and contributed
to increased production. He also noted that there were
positive results from viscous oil drilling in the Schrader
Bluff reservoir, which further supported KRU production. He
added that the Badami Unit also experienced an increase in
production. He reported that the new well B-133A came
online and had produced more oil than the remainder of the
field combined.
Mr. Peltier stated that MPU continued to show sustained
production increases driven by its ongoing infill drilling
program. He reported that production at MPU increased by
more than 4,000 BOPD in FY 25. He indicated that additional
discussion of MPU activities would be provided on a later
slide. He added that the Nikaitchuq, Oooguruk, and PTU also
recorded production increases during FY 25. The increase at
PTU largely reflected recovery from a pipeline shutdown
during the prior fiscal year, when a freeze during a
production upset halted operations for several months. He
noted that production resumed during the summer of FY 24,
resulting in higher production levels during FY 25.
Mr. Peltier reported that the Southern Miluveach Unit (SMU)
appeared on the chart for the first time. He relayed that
production volumes were modest due to the timing of initial
production, but early results had been positive. He
indicated that additional information on the field would be
available in future forecasts.
2:01:36 PM
Co-Chair Josephson asked whether production from PTU
consisted of gas and condensate.
Mr. Peltier responded in the affirmative and explained that
condensate volumes were reported as oil production and
expressed in BOPD. He clarified that condensate was sold
under a separate quality bank with its own quality meter.
He explained that although PTU condensate carried a
distinct grade, it was included under oil production totals
for reporting purposes.
Representative Hannan asked whether the apparent increase
in PTU production reflected a restoration following the
aforementioned shutdown of another pipeline. She asked how
current production compared to levels the year prior to the
pipeline incident.
Mr. Peltier responded that detailed field-level production
charts were publicly available and allowed users to review
production data by well across North Slope fields. The last
bullet point on slide 8 was a link to the field charts. He
explained that PTU production had declined from FY 23 to FY
24 due to well performance issues in addition to the
shutdown. He noted that the field had only one producing
well and that the well experienced a loss in productivity.
He explained that while production increased in FY 25, it
had not yet returned to prior levels. He stated that the
current operator was conducting ongoing remediation efforts
to restore production and refill the facility.
Mr. Peltier continued to slide 9, which detailed the
history and performance of MPU under both the prior
operator, BP, and the current operator, Hilcorp. He
explained that the chart displayed oil plus natural gas
liquids on the left axis and water production on the right
axis. He noted that oil production was expressed in
thousands of BOPD and that water production ranged up to
200,000 barrels of water per day (BWPD). The chart
reflected calendar-year monthly data from 1995 through
November of 2025. He stated that under BP's operatorship,
MPU functioned primarily as a "Kuparuk light" oil field and
reached peak production in July of 1998 at just under
59,000 BOPD. He explained that production declined over
time and reached approximately 18,779 BOPD day in November
of 2014, when BP sold the asset to Hilcorp.
Mr. Peltier explained that Hilcorp assumed operatorship in
November of 2014 and initially focused on stabilizing
production. He explained that the operator later invested
in SBU and implemented new drilling and polymer flooding,
which resulted in year-over-year increases in production.
He reported that the most recent monthly production level
shown on the chart was 50,906 BOPD.
2:06:24 PM
Mr. Nottingham remarked that he had nearly 30 years of
industry experience and it was rare to see a revitalization
of a mature oil field that nearly duplicated its prior peak
production. He explained that while some mature fields
experienced later revitalization phases, production rarely
returned to previous peak levels. The most notable aspect
of the MPU revitalization was that production increasingly
came from the Schrader Bluff reservoir, which produced more
viscous and heavier oil than the Kuparuk reservoir. He
explained that the original facilities were not designed to
handle the heavier oil and the operator had successfully
adjusted drilling practices and modified facilities to
accommodate the oil.
Co-Chair Josephson remarked that Hilcorp was known as an
operator that excelled at redeveloping mature fields.
Mr. Peltier advanced to slide 10, which provided a status
update on five North Slope projects. He explained that
Pikka Phase 1, Pikka Phase 2, and Willow were new projects
associated with new fields. He relayed that CRU CD8 project
and Project Taiga under PBU were new pads within existing
fields. He explained that new fields carried greater risk
and cost than new pads in existing fields. During the prior
year, the Pikka Phase 1 operator, Santos, conducted
construction and drilling activities and anticipated first
oil in the second quarter of 2026. As of 2026, the project
was more than 95 percent complete and commissioning
activities were underway. He reported that first oil was
anticipated by the end of the first quarter of 2026. He
added that peak production was estimated at 80,000 BOPD and
that production would ramp over time.
Co-Chair Josephson asked whether there were plans for
expansion into adjoining fields.
Mr. Peltier responded in the affirmative and explained that
the expansion was classified as Pikka Phase 2. During the
prior year, Pikka Phase 2 was in the conceptual engineering
and cost estimation stage, with publicly stated plans to
advance to front-end engineering design in 2025 and a final
investment decision in 2027. As of January of 2026, Santos
prioritized completion of Pikka Phase 1 before proceeding
with Phase 2. He explained that Phase 2 included a new pad
and additional production capacity and was expected to add
approximately 80,000 BOPD. He explained that combined peak
production from Pikka Phase 1 and Phase 2 was estimated at
160,000 BOPD.
2:10:34 PM
Representative Hannan asked whether Santos had sold or
transferred ownership of the project.
Mr. Peltier responded that Santos acquired Oil Search, both
of which were Australian companies. He explained that Oil
Search Alaska (OSA) remained the Alaska subsidiary and held
a 51 percent ownership interest in Pikka Phase 1 and Phase
2. He explained that Repsol held the remaining 49 percent
interest. The current ownership structure was a 5149 split
between Santos and Repsol.
Co-Chair Josephson understood that the other name for Pikka
Phase 1 was Horseshoe. He asked what the names for the
other phases were.
Mr. Peltier responded that Horseshoe and Qilak were
distinctly different projects from Pikka. He emphasized
that those projects were wholly separate units on the North
Slope and were not part of the Pikka development.
Co-Chair Josephson asked whether the projects were also
separate from Pikka Phase 2.
Mr. Peltier responded in the affirmative.
Mr. Peltier continued on slide 10 to discuss the Willow
project, which was a ConocoPhillips development. He
explained that first oil remained on track for 2029 and
that the project was now more than 50 percent complete. The
Willow Central Facility was currently under construction in
Texas and was planned for transit to the North Slope in
2027. The Willow project was expected to reach a peak
production rate of 180,000 BOPD. He relayed that the
project was primarily located on federal land, unlike Pikka
Phase 1 and Pikka Phase 2, which involved a mix of state
and Alaska Native lands.
Mr. Peltier continued on the slide to discuss projects
involving new pads within existing fields. He relayed that
ConocoPhillips began permitting the CRU CD8 project in
early 2025. He explained that the United States Army Corps
of Engineers (USACE) served as the lead agency and that a
notice of intent was issued on September 9, 2025.
Engagement with stakeholders was ongoing and a draft
environmental impact statement comment period was underway
and scheduled to continue through the fall of 2026. He
explained that a record of decision was anticipated in
early 2027 and first oil was expected in 2030. He stated
that no public production estimate had been released yet,
therefore DNR was therefore sharing its internal mid-case
estimate of approximately 20,000 BOPD.
2:14:37 PM
Representative Tomaszewski asked whether the production
estimates for the projects discussed, including 80,000,
160,000, and 180,000 BOPD, explained the high North Slope
forecast shown on slide 4, which approached approximately
975,000 BOPD. He asked if there were any factors that could
derail the projects and if the high forecast was likely to
be realized.
Mr. Peltier responded that the official forecast relied on
mid-case assumptions rather than the high or low scenarios.
He explained that the official forecast summed to just
under 700,000 BOPD and was a more representative estimate.
He relayed that DNR assumed approximately plus or minus 5
percent uncertainty in the first year of the forecast and
that uncertainty increased in later years. He explained
that some projects might not come online as anticipated,
which was reflected in the low-case forecast, while
stronger-than-expected performance was reflected in the
high-case forecast. Both scenarios were intended to show
the range of potential outcomes.
Representative Stapp remarked that the chart reflected
approximately 400,000 BOPD of additional production. He
asked when the department had last been able to present
projects of such a scale to the legislature. He noted that
several other projects, including Sockeye 2A, were not
shown on the slide and asked how the high level of new
production compared to the state's historical experience.
Mr. Nottingham responded that he had been in his role for
four years and that the department had often discussed the
projects. He explained that the projects had progressed
through multiple stages and faced numerous challenges, but
what distinguished the current year was that construction
activity was underway, facilities were being installed, and
significant capital was being spent. He explained that
Pikka had reached a point where production would soon come
online and that Willow was well into development. He
explained that the projects had moved beyond the conceptual
stage and were now becoming reality.
Representative Stapp expressed that he viewed the situation
as a historic moment in the state's recent history. He
noted that Alaska had long discussed declining production.
He was 38 years old and for the first time in his life, the
state would experience a substantial increase in oil
production. He thought that the increase reflected years of
difficulty, significant capital investment by industry, and
extended timelines. He noted that prior tax structure
discussions had anticipated production growth and the
results were materializing. He asked how the department
determined which projects were included on the slide and
which were excluded.
Mr. Peltier responded that the slide focused on large
projects that were either nearing production or were
materially significant to the long-term production
forecast. He explained that a later map would display all
projects included in the North Slope production forecast,
as well as one Cook Inlet project included in the aggregate
forecast. The department reviewed its projects annually. He
explained that inclusion of a project depended on whether a
development plan existed, whether a known resource had been
identified, and whether the operator intended to develop
the project within the next 10 years. Any projects that no
longer met the criteria were removed from the list, citing
the Liberty project as an example. He explained that
Liberty was no longer included because it was not expected
to come online within the 10-year forecast window.
2:21:29 PM
Representative Stapp remarked that he was glad Liberty was
mentioned. He was interested in projects like Liberty and
asked how often companies invested significant capital in
Alaska projects that ultimately did not succeed, resulting
in financial losses for the operator.
Mr. Peltier responded that outcomes varied significantly
across projects. He explained that PBU had exceeded
expectations as it was initially projected to produce
approximately 9.6 billion barrels of oil and had since
produced billions of barrels beyond the estimate. Other
projects did not meet expectations, such as Badami. He
explained that the peak production rate for Badami was
projected to be approximately 35,000 BOPD, but actual
production never reached that level. He explained that peak
daily production occurred early in the field's life and
remained well below projections, with monthly average
production significantly lower and long-term production
declining to approximately 1,000 BOPD until the recent
drilling of the B133A well. Overall, the Badami project had
not met its original expectations.
Co-Chair Josephson commented that Shell's efforts in the
Beaufort Sea were "notorious." He understood that there
were efforts to develop Smith Bay as well.
Mr. Nottingham responded that Shell's efforts to explore
the Beaufort Sea were extremely expensive and difficult to
execute. The efforts ultimately resulted in significant
costs and were abandoned. He explained that Alaska
contained substantial resource potential but also presented
extreme logistical challenges, particularly in remote
locations where specialized equipment was required and
operational conditions had to align precisely for
exploration and development to succeed. Additionally,
resources were identified in Smith Bay, but the location
was remote, situated on state land in state waters, and
access required transit through NPRA. He relayed that
federal access constraints created challenges for
exploration, even on state lands, and that Alaska's
development history reflected ongoing logistical and
regulatory complexities.
2:25:21 PM
Representative Moore asked for an update on Pikka road
access. She understood that there were jurisdictional
challenges related to federal lands, state lands, and NPRA
and there were additional challenges related to accessing
the road in the winter.
Mr. Nottingham responded that the Pikka road access issues
had largely been resolved. He explained that ConocoPhillips
and Santos had entered into a mutually agreed-upon use
agreement. He noted that prior legal action had occurred
and that a ruling had been issued in superior court. While
the state pursued further legal review, the companies
resolved the matter through a commercial agreement. As a
result, the supreme court determined the issue to be moot
and vacated the superior court ruling. He suggested that he
could ask the Department of Law (DOL) to follow up with
more details.
Representative Moore asked for confirmation that road
access issues would not prevent Pikka from coming online.
Mr. Nottingham confirmed that there were no anticipated
delays for Pikka related to road access.
Mr. Peltier introduced the last project on slide 10, which
was a brand-new project in PDU that had not been included
in the project list presented the prior year. He stated
that Hilcorp was proposing to move forward with two new
pads referred to collectively as Project Taiga. He reported
that first oil from the first pad was expected in 2028, and
first oil from the second pad was anticipated between 2028
and 2030, depending on the final investment decision. He
noted that the peak production rate for both pads could
reach as high as 40,000 BOPD.
2:28:28 PM
Mr. Peltier moved to slide 11 and provided highlights for
the Cook Inlet Basin and compared FY 24 and FY 25. He
reported that production in the basin declined
approximately 8 percent, reflecting the region's status as
the most mature basin among Alaska's oil assets. He noted
that many fields had been producing for over seven decades.
He emphasized that the Cook Inlet supply remained critical
for in-state refineries.
Mr. Peltier explained that most fields in the Cook Inlet
were not experiencing significant new well drilling, which
contributed to the production decline. He noted that well
work performed by Hilcorp could sometimes offset natural
decline. For example, maintenance and well work at the
Redoubt Shoal Field resulted in a net positive production
change for the year. He clarified that all other fields
were still experiencing net declines despite operator
efforts to manage the assets.
Representative Bynum asked whether the anticipated focus on
gas production in the region might shift toward oil
production if a gas line were developed.
Mr. Peltier responded that he could not provide a
definitive answer. He stated that his assumption was that
operators would aim to maximize the value of their existing
fields regardless of the presence of a natural gas
pipeline.
Mr. Peltier advanced to slide 12 to discuss the production
forecasting methodology. He noted that there had been no
changes in methods used since the DNR's fall 2022 and
spring 2023 forecasts.
2:31:43 PM
Representative Galvin commented that she had a question
related to forecasts but not directly to the material on
the slides. She referenced a prior audit regarding whether
oil companies had made the appropriate write-offs and
whether the state was receiving the appropriate amount due.
She had heard from various sources that the amount being
negotiated had changed significantly, from hundreds of
millions to nearly zero, and asked for clarification on the
current status.
Mr. Nottingham responded that he could not speak to the
issue and apologized for not being able to provide an
update.
Mr. Peltier proceeded to slide 13 and detailed the
production forecasting methodology. He explained that the
bulk of the production forecast was developed using decline
curve analysis for all producing pools on the North Slope
and the Cook Inlet. Each individual pool on the North Slope
was treated separately, while the Cook Inlet pools were
aggregated as a single unit, reflected in the DOR's Revenue
Sources book. He reported that as of June 30, 2025, there
were approximately 41 producing pools on the North Slope
and additional pools in the Cook Inlet. The department also
conducted interviews, both in person and in writing, with
operators in both regions and reviewed internal plans of
development.
Mr. Peltier continued that based on the assessments, 13
projects were identified as worthy of consideration under
the "under development" and "under evaluation" categories.
The projects relied on confidential operator information
and were not typically reported individually unless the
information was already public. He explained that
production from these projects was risked and adjusted for
scope, probability of occurrence, and anticipated start
date. He relayed that 12 of the projects were located on
the North Slope and one was in the Cook Inlet. He would
provide a map on a later slide.
Mr. Peltier advanced to slide 14 and explained that the
production forecast was broken out into various categories
of ongoing and future production. The current production
(CP) category referred to existing fields, which included
the 41 North Slope pools discussed previously. He noted
that forecasts took into account well and facility uptime,
operator spending to maintain base production, and changes
in reservoir management. The under development (UD)
category included production that required new investment,
such as drilling new wells or installing new production
facilities. He explained that the contribution of new wells
carried uncertainty, particularly in legacy fields. The
scope was also included in the evaluation such as the
number of new wells and facility capacity.
Mr. Peltier added that the under evaluation (UE) category
accounted for timing risks associated with new projects. He
indicated that for projects nearing completion, such as
Pikka Phase 1, timing uncertainty had decreased, while for
other projects like Willow and Pikka Phase 2, timing
uncertainty remained. He clarified that commercial risks
were incorporated into all forecasts, such as oil price
fluctuations and breakeven costs.
2:36:51 PM
Representative Bynum remarked that legislators received
many inquiries regarding global volatility in oil markets.
He noted that volatility in the northern hemisphere
directly affected oil prices. He asked whether any global
climate conditions could impact Alaska production to the
point that production would be curtailed.
Mr. Peltier asked for clarification on what Representative
Bynum meant by climate conditions.
Representative Bynum responded that he was referring to
volatility in global oil markets, including developments in
Venezuela and the Middle East. He wanted to know whether
such conditions could directly impact oil production in
Alaska.
Mr. Peltier responded that he did not anticipate legacy
field production in Alaska being affected in the near term
by changes in Venezuelan or Middle Eastern supply,
including potential redirection of oil to refineries in the
contiguous U.S. He noted that from 2014 to 2016, Middle
Eastern producers increased output, oil prices declined
significantly, and future projects were deferred. He
explained that such conditions affected future production
but not near-term legacy production. In April of 2020
during the COVID-19 pandemic, oil prices fell sharply, but
Alaska's legacy fields continued producing. He offered
reassurance that while oil prices could fluctuate
significantly, production generally continued, as operators
typically maximized volume except in extreme pricing
conditions.
Co-Chair Schrage asked whether capital requirements for
investments in other markets, including Venezuela, could
affect development in Alaska and the state's ability to
bring projected production online.
Mr. Peltier responded that the question was one the
department regularly raised with operators during
confidential discussions. He relayed that he could not
identify any current impacts. He explained that maintaining
Alaska's competitiveness remained important given its large
resource base. He had no information to share regarding
whether capital was being diverted from Alaska projects to
other states or overseas markets.
Co-Chair Schrage understood that it was conceivable that
capital needs elsewhere could impact Alaska, even if not
reflected in the forecast. He asked how much exposure
existed and whether companies included in the forecast were
also considering investments in Venezuela. He noted that
there were reports that Hilcorp might be pursuing
investment in Venezuela and asked if other companies were
also interested in investment.
2:41:06 PM
Mr. Peltier responded that he did not have a specific
number. He noted that he had seen the news indicating that
several companies with operations in Alaska were
represented at a recent White House meeting. He stated that
one company expressed hesitation regarding Venezuela, while
others were more optimistic. He could not speak to whether
companies were already diverting capital and noted that
such considerations were outside the scope of the
department's forecast.
Representative Stapp asked about the implications of
potential capital related to Venezuela. He asked whether
increasing taxes on companies while potentially moving
capital elsewhere would guarantee that capital left Alaska
projects.
Mr. Peltier responded that it was an interesting question,
but he did not have an answer.
Representative Stapp commented that if the concern was
competition from projects in other regions, it would seem
counterproductive to make doing business in Alaska more
expensive.
Mr. Peltier advanced to slide 15, showing the major
projects under evaluation that were considered for the fall
2025 North Slope forecast. He stated that the projects were
not online as of June of 2025 and therefore remained
classified as projects. Although Pikka was planned to come
online, it was still considered a project because it was
not yet producing. He stated that the projects carried
higher risk than currently producing fields but were known
discoveries with identifiable operators that required major
investment.
Mr. Peltier highlighted that the slide included a map of
North Slope projects in development. He identified the
Willow development located on federal land. He stated that
the Horseshoe project was located south of Willow and
consisted of a mix of state and federal acreage. The CRU
CD8 project was located in the southern area of the CRU. He
identified the Pikka unit east of CD8 and stated that Pikka
Phase 2 and Phase 3 were aligned along a north south trend
within nonproducing state leases. He highlighted that the
Quokka Unit's Mitquq well was east of Pikka. He stated that
KRU did not include any major projects under development
for the forecast and the existing projects had moved into
currently producing pools. He identified the Pantheon Great
Bear projects south of Prudhoe Bay, including Theta West,
Talitha, and Alkaid. He stated that no major projects east
of Prudhoe Bay were included in the forecast.
2:45:00 PM
Mr. Peltier moved to slide 17 which included an annualized
forecast chart for the North Slope. He noted that he would
focus on the summary points due to time constraints. He
stated that the DNR forecast for FY 26 showed an annualized
statewide production average of 464,500 BOPD, with North
Slope production at 457,000 BOPD. He stated that the low
case was 418,400 BOPD and the high case was 495,300 BOPD.
The operator forecast for FY 26 was 476,000 BOPD. He
explained that the operator long term forecast did not
include new fields and therefore diverged from DNR's
forecast later in the projection period. He stated that the
operator forecast remained within the low and high case
range. The differences between the low case, official case,
and high case resulted from uncertainty analysis related to
project timing, project success, and production rates. He
relayed that uncertainty increased over time and that the
forecast assumed operator plans remained static. He noted
that an updated forecast on how the assumptions had changed
was expected to be released in mid-March of 2026.
Representative Tomaszewski asked about the production
increases shown on the slide. He noted that the increase
between 2026 and 2027 appeared to reflect Pikka Phase 1
coming online in March, with an estimated year-end rate of
approximately 80,000 BOPD. He observed that the increase
between 2029 and 2031 appeared to correspond to Willow,
with increases of roughly 160,000 to 180,000 BOPD. The
increase between 2031 and 2035 of approximately 100,000
BOPD appeared to reflect Pikka Phase 2. He asked whether
there was an estimate for Pikka Phase 3 production.
Mr. Peltier responded that Pikka Phase 3 was not viewed as
having an additional production capacity at the facility.
Instead, it was considered a new pad that would come online
as production from Pikka Phases 1 and 2 declined over time.
He explained that Phase 3 was intended to fill the
available capacity created by that decline by adding new
wells, thereby maintaining the overall peak production rate
of the Pikka facility rather than increasing it.
Mr. Peltier continued on slide 18. He explained that DNR
decided to present an 18-month forecast rather than a 12-
month forecast to better address questions regarding the
timing and ramp-up of Pikka production. He noted that the
chart included actual production data through January 14,
2026, allowing a comparison between actuals and the
forecast, which was finalized in late November. He stated
that North Slope production was running slightly higher
than the forecast but remained generally on trend, with no
significant divergence. He added that the cumulative
production line also showed close alignment between
forecasted and actual cumulative volumes over the 18-month
period.
Mr. Peltier explained that Pikka Phase 1 was expected to
come online toward the end of the first quarter of 2026,
but it was not anticipated to immediately reach a
production rate of 80,000 BOPD. He stated that the forecast
reflected a modest increase beginning in April of 2026,
followed by a decline through the summer months. He
explained that the seasonal pattern reflected constraints
in legacy North Slope fields, which produced significant
volumes of gas and experienced reduced oil production
during warmer months. Additionally, there were planned
summer maintenance and turnaround activities that typically
occurred in June, July, and August. The forecast showed a
larger production increase in August of 2026, reflecting
both the continued ramp-up of Pikka Phase 1 and the
completion of summer turnaround activities across the North
Slope. He added that production was then projected to
increase further as colder winter conditions return.
2:50:31 PM
Mr. Peltier advanced to slide 19 and explained that the
charts presented Alaska statewide annualized average daily
oil production by production category. He stated that both
charts used the same scale, from zero to 700,000 BOPD, to
illustrate the relative contributions of existing
production, new projects, and new drilling. He noted that
the chart on the left included an overlay of the spring
2025 forecast to show how projections had changed.
Mr. Peltier explained that the forecasts showed a high
degree of stability overall. He observed that while the
spring 2025 forecast was slightly higher, the current
forecast reflected a modest reduction compared to prior
projections. He emphasized that production from existing
fields continued to decline over time and that a
significant portion of new production from projects offset
the declines rather than representing net growth. The
orange curve represented new drilling, which reflected the
next 12 months of drilling in existing fields. He noted
that although it was the smallest component, it
demonstrated a material impact on the production forecast
and showed the continued value of the drilling moving
forward. He explained that the remaining drilling was
represented in gray and covered months 13 through 120 of
the forecast.
Mr. Peltier directed attention to the chart on the right
which overlaid future projects against one another. He
indicated that the spring forecast and the current forecast
showed slight differences. He had not corrected the spring
forecast to reflect the Torok projects or the
ConocoPhillips projects that were being executed at the
time, as he wanted to leave them visible to illustrate the
relative contribution of projects such as Pikka coming
online in the near term. He indicated that Pikka was
expected to be a significant project with substantial near-
term impact.
Mr. Peltier noted that there was a gap that developed in
the 2028, 2029, and 2030 time frame. He explained that the
gap resulted from uncertainty surrounding certain projects
previously discussed, including Pikka Phase 2. He noted
that the timing of the projects was uncertain relative to
expectations from the prior year, which contributed to
differences between last year's expectations and the
current forecast.
Representative Bynum asked whether the projections
reflected only currently known information. He asked if
potential changes in the federal administration, the
opening of the NPRA, challenges to Willow, and changes to
pad development were considered. He also asked whether such
factors might be incorporated at a later time.
Mr. Peltier responded that the question was one the
department debated internally. He explained that the
forecast did not take into account any actions by a new
federal administration with respect to Willow. He noted
that while new exploration activity in the Willow and GMTU
area had been publicly reported, the exploration wells had
not resulted in the discovery of oil. He explained that
because of uncertainty, no barrels associated with that
exploration activity were included in the production
forecast, despite interest in how the activity might
ultimately affect future production.
Mr. Peltier advanced to slide 20 and relayed that the
production forecast relied on the best available
information from DNR and DOR. He stated that the forecast
was intended to be as accurate as possible in both the near
future and long term. He explained that the forecast
represented a static view of production and that as
business plans changed, underlying assumptions could become
outdated and were updated when possible. He noted that
DNR's outlook for fall of 2025 showed mean annual
production beginning at approximately 465,000 BOPD and
increasing to 685,000 BOPD by the end of the outlook
period. He moved to slide 21 and thanked the committee for
its time.
Co-Chair Josephson thanked the presenters. He remarked that
the forecast included positive information, particularly
for future legislatures.
Co-Chair Josephson reviewed the agenda for the following
day's meeting.
ADJOURNMENT
2:56:07 PM
The meeting was adjourned at 2:56 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 1.21.26 HFIN DNR Fall 2025 Production Forecast Presentation.pdf |
HFIN 1/21/2026 1:30:00 PM |