Legislature(2023 - 2024)SENATE FINANCE 532
01/18/2023 09:00 AM Senate FINANCE
Note: the audio ![]()
and video ![]()
recordings are distinct records and are obtained from different sources. As such there may be key differences between the two. The audio recordings are captured by our records offices as the official record of the meeting and will have more accurate timestamps. Use the icons to switch between them.
| Audio | Topic |
|---|---|
| Start | |
| Production Forecast – Department of Natural Resources | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
SENATE FINANCE COMMITTEE
January 18, 2023
9:00 a.m.
9:00:24 AM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 9:00 a.m.
MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Donny Olson, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Click Bishop
Senator Jesse Kiehl
Senator Kelly Merrick
Senator David Wilson
MEMBERS ABSENT
None
ALSO PRESENT
John Boyle, Commissioner Designee, Department of Natural
Resources; Travis Peltier, Petroleum Engineer, Division of
Oil and Gas, Department of Natural Resources; Derek
Nottingham, Director, Division of Oil and Gas, Department
of Natural Resources.
SUMMARY
PRODUCTION FORECAST DEPARTMENT OF NATURAL RESOURCES
Co-Chair Stedman introduced the committee members and
discussed roles. He commented on the level of experience of
the members. He discussed committee process and informed
that the committee would consider overviews for the next
several days to set the stage for upcoming meetings as the
committee worked through the revenue and expenditures of
the state.
Co-Chair Stedman introduced Senate Finance Committee staff.
He explained that staff would sit behind the members.
9:03:34 AM
Co-Chair Stedman introduced his staff, including Mr. Pete
Ecklund, the operating budget coordinator. Mr. Ecklund
would also lead the weekly operating budget staff meetings.
He introduced additional staff. He commented on the
experience of the staff.
Senator Hoffman introduced his staff.
Senator Olson introduced his staff.
Co-Chair Bishop introduced his staff.
9:07:00 AM
Senator Wilson introduced his staff.
Senator Merrick introduced her staff.
Senator Kiehl introduced his staff.
Co-Chair Stedman introduced the committee staff and staff
from the Legislative Information Office.
9:09:26 AM
Co-Chair Stedman discussed committee process, schedules,
and decorum. He conveyed that there might be morning and
afternoon meetings on occasion. He emphasized the
importance of a good and fair exchange of information and
commented on the magnitude of information received by the
members. He asserted that all members would have equal time
to express concerns and ask questions. He discussed
presenters providing information to the committee when
questions were not answered during meetings.
Co-Chair Stedman continued that the co-chairs would prefer
no eating in the room. He discussed the use of technology.
He emphasized treating presenters with respect. He
discussed protocol for presenters and the general public.
He noted that further information on decorum would be sent
to members. He expressed the desire to run timely meetings.
^PRODUCTION FORECAST DEPARTMENT OF NATURAL RESOURCES
9:13:51 AM
Co-Chair Stedman relayed that the committee would consider
a production forecast from the Department of Natural
Resources (DNR). He noted that the commissioner-designee
would introduce himself and his staff. He noted that the
standard presentation process was to take questions after
each slide. He asked the presenter to offer information on
his background.
9:15:20 AM
JOHN BOYLE, COMMISSIONER DESIGNEE, DEPARTMENT OF NATURAL
RESOURCES, discussed his background. He had worked as a
clerk for a number of judges in Fairbanks and had worked
with the North Slope Borough as an assistant attorney and
as chief advisor to the mayor as well as director of the
boroughs government affairs department. He had gained
insight into the oil industry while working in the North
Slope Region. He had worked for three years as the Director
of Government Affairs at BP Alaska. He had most recently
worked with a new entrant to the state. The experience had
provided information about the challenges of bringing an
oilfield into development.
Commissioner Boyle commented that his work experience had
shaped his perspective on resources. He used the metaphor
of a firehose to describe his learning curve at DNR. He
commented on the quality of professionals working at DNR.
He explained that the staff took pride in compiling the
information in the report in an effort to assist the
legislature to better understand the outlook for the coming
years in order to make budgeting decisions for the state.
9:19:19 AM
Commissioner Boyle wanted to offer highlights of the
presentation. He commented that generally production on the
North Slope was stable. He considered deeper legacy fields
that were near to 50 years old and required more energy to
keep a steady production level. He thought the legacy field
progress was a commentary on the major accomplishment of
producers. He noted that DNR had forecast a steady trend of
production that increased towards new development. He
thought the legislators should have confidence that the
state had a resource base that looked to be steady and
would bridge into the future when there could be
opportunity to monetize other state resources.
Commissioner Boyle introduced his team and discussed their
experience in the field of oil and gas.
9:22:26 AM
TRAVIS PELTIER, PETROLEUM ENGINEER, DIVISION OF OIL AND
GAS, DEPARTMENT OF NATURAL RESOURCES, discussed a
presentation entitled "FALL 2022 PRODUCTION FORECAST(copy
on file). He commented that the department had been
performing the production forecast analysis since 2016. The
goal of the presentation was to share the oil production
results of FY 22 and share the oil forecast for the
following ten years. The discussion would include
information on methodology and background, as well as how
the forecast was generated.
Mr. Peltier discussed his background. He had graduated with
a mechanical engineering degree from the University of
Alaska Fairbanks (UAF) in 2006. He had worked with BP
Alaska, working predominantly in Prudhoe Bay. He had spent
time away from the industry and in 2021 he obtained a
position with the Division of Oil and Gas at DNR. He was
recently given the opportunity to lead the production
forecast. He had spent the majority of his life in the
state.
Mr. Peltier looked at slide 2, "AGENDA":
• Introduction
• Background:
• FY 2022 in Review
• DNR Production Forecasting Approach
• Fall 2022 Forecast Results
• Summary
9:25:06 AM
Mr. Peltier showed slide 3, "FY 2022 IN REVIEW." He
commented that the following three slides would focus on
the North Slope and Cook Inlet.
Mr. Peltier referenced slide 4, "FY 2022 SUMMARY: NORTH
SLOPE":
Highlights (FY 2022 vs FY 2021)
•All production areas are generally expected to see a
year-on-year decline
•Compared to FY 2021, in FY 2022 North Slope
production decreased by ~2% (~9,570 bopd)
•Decreases
•Alpine: Natural decline from flush production
after extended shut-ins from 2020. Limited
development drilling in FY 2022
•Kuparuk and Kuparuk Satellites: Natural decline
due to cessation of NGL imports and associated
EOR, as the OPL was converted to fuel gas in
early FY 2022
•Offshore: Natural reservoir decline
•Increases
•NPRA: GMT2 pad brought online, performing well
•PBU Satellites: 10% production growth due to
consistent drilling efforts
•Point Thomson: 8% growth from improved facility
reliability
Mr. Peltier wanted to highlight how FY 22 compared to FY
21. He noted that the information was based on data and
involved no forecasting. He noted that instead of showing
fields separately, DNR wanted to address production areas
to be consistent with the Department of Revenue (DOR).
Additionally, the numbers were consistent with the numbers
in the Revenue Sources Book (RSB).
Co-Chair Stedman cautioned against using acronyms.
Mr. Peltier explained that the RSB was the official
forecast for revenue and oil production. He continued to
address slide 4. He reported that DNR expected to see a
year-on-year decline across all production areas. He
expounded that oil fields naturally declined over time. He
shared that North Slope production in FY 22 decreased by
approximately 2 percent or approximately 9,570 barrels per
day from FY 21. He reminded that the forecast followed the
fiscal year rather than the calendar year.
Mr. Peltier pointed to the top chart on slide 4 showing
North Slope daily production. The Y axis showed the fiscal
year annual average daily oil production in barrels of oil
per day and the X axis showed the fiscal year from FY 16
through FY 22. He relayed the peak oil production rate in
FY 17 was just over 526,000 barrels of oil per day and had
declined until about FY 20, which was expected with natural
decline. He added that FY 20 was the start of the COVID-19
pandemic and several oil fields had been shut-in for
economic reasons resulting in an artificially high decline.
The issue resolved in FY 21 when oil prices rebounded after
COVID era lows. The normal decline rate resumed in FY 22.
He reported that FY 22 gross North Slope production
averaged about 476,490 barrels of oil per day.
9:28:42 AM
Mr. Peltier addressed individual production area changes
from FY 21 to FY 22 in the lower chart on slide 4. The
chart began at a zero line. He cited flat production for
Prudhoe Bay and satellites to increasing production, which
had to do with operators continued development of the
Prudhoe Bay field. He reminded that in 2019, BP Alaska had
decided to sell the asset to Hilcorp, which was the
predominant operator in the fields. There was continued
drilling in places such as Milne Point, which was by
definition part of the Prudhoe Bay Unit (PDU) satellites
for the RSB. He noted that GPMA had normal reservoir
decline year over year and was also a satellite for Prudhoe
Bay.
Mr. Peltier highlighted a decrease in Kuparuk and Kuparuk
satellites of around 10,000 barrels per day from FY 21 to
FY 22. He elaborated there was natural decline due to the
cessation of natural gas liquid (NGL) imports, which were
used for enhanced oil recovery (EOR) within the Kuparuk
reservoir unit. The NGL imports and EOR had ceased because
of the need to convert the Oliktok pipeline (running from
PDU to the Kuparuk River Unit) to fuel gas in order to
maintain the base production from the Kuparuk River Unit.
The next production area was Endicott, which showed a small
decline attributed to natural reservoir decline.
Mr. Peltier addressed the Alpine area, which included the
Colville River area, and noted the area was closed during
the pandemic era and brought back online during FY 21.
There was a relatively large production increase after the
short period, followed by a reservoir decline in FY 22.
There was limited drilling for FY 22 compared to previous
years, which led to a relatively large production decline
out of the Alpine area. He mentioned there were a number of
offshore fields, and there was nothing of note to point
out. He mentioned there were increases in the Natural
Petroleum Reserve-Alaska (NPRA), which included the Greater
Mooses Tooth Unit. He recalled there was a project the
previous year to bring a new pad online (GMT2) at the unit.
The unit was doing well and was one of the predominant
reasons for the production increase in the NPRA area.
Mr. Peltier addressed the Point Thomson unit shown on the
graph on slide 4. He highlighted that the unit was
predominantly driven by its initial production system that
started in April of 2016, and was a new facility to the
slope. There had been many production issues for the
initial years of operation. He informed that ExxonMobil was
the operator two years previously and had resolved many of
the issues to increase production before Hilcorp took over
and had continued the positive trend. He cited a total
North Slope decrease of about 9,570 barrels.
9:33:17 AM
Co-Chair Stedman recalled that several years previously the
production facilities were all running at the maximum
handling gas or water and thought Alpine had been the only
field with extra capacity. He asked for the status of the
facilities and the handling of gas and water. He asked for
Mr. Peltier to address the topic and location of the
facilities.
Mr. Peltier asked if Co-Chair Stedman was curious about
Alpine specifically or about all facilities on the North
Slope.
Co-Chair Stedman stated that he was asking a broad general
question, and offered that Mr. Peltier get back to the
committee with the information. He noted that a facility
could only process so much water or gas, which limited the
amount of production that was possible. He queried about
the background of the issue and the current status.
Mr. Peltier affirmed that Co-Chair Stedman was correct and
offered to send the more detailed information at a later
time. He explained that in Prudhoe Bay, the majority of the
time the aging assets would be limited by water-handling
capacity. He discussed the process of separating the gas
and water from oil that came out of the ground in order to
get saleable oil. He qualified that in many facilities,
there was a water handling limitation or a gas handling
limitation, which would limit through-put. He noted that
Point Thomson was a good example that the ability to
produce additional condensate came with the gas limit.
Prudhoe Bay had various facilities, some of which were
water-limited, some of which were gas-limited, and some
were both.
9:35:33 AM
Co-Chair Stedman acknowledged the limiting factors. He
suggested that DNR's presentation could try and address
processing facilities and potential increases.
Co-Chair Kiehl asked for more detail on the chart on the
bottom right of slide 4. He thought the narration matched
the color of the bars, but he wanted more detail on the
increase or decrease in production shown.
Mr. Peltier noted that the increases were shown in blue and
reviewed the relative increases and decreases shown on the
chart.
Co-Chair Stedman thought the negative amount was the
difference between FY 21 and FY 22 shown on the chart
above.
Senator Olson asked about GMT2, which was thought to
produce about 7,000 barrels per day. He asked if production
was on track.
Mr. Peltier reminded that the data was cut off from June
30, 2022. He affirmed that GMT2 was performing to
expectations.
Senator Olson asked about the expectation for the coming
years and if the production would increase or decrease.
Mr. Peltier relayed that there was very little production
history for the GMT2, so the department used the previous
years data of consistently forecast production. He
explained that the next ten years of the forecast would be
consistent with previous years.
9:38:40 AM
Mr. Peltier turned to slide 5, "FY 2022 AS FORECASTED BY
DNR IN FALL 2021: HOW DID WE DO?":
•Actual FY 2022 production came in within DNR's
forecasted range
•DNR mean forecast was ~2% higher than actual FY 2022
production
•Factors to watch for that are currently shaping the
forecast horizon
•Strong ESG influences continue to challenge
capital allocation decisions in the Arctic,
especially for early-stage oil projects under
development/evaluation
•Industry interest continues in Nanushuk leases
and projects on State and Federal lands
Mr. Peltier referenced the bar graph on slide. He explained
that the striped, blue bars showed the high and low
forecast from the RSB. He commented that the range from the
previous year was about 524,000 barrels per day on the high
to just under 450,000 barrels per day on the low. The
official forecast for the previous year was just under
487,000 barrels of oil per day, but actual production came
in at 476,490 barrels of oil per day. He noted that the
department also received confidential information from
operators that was aggregated. For the previous year,
operators forecast that the Alaska North Slope (ANS) oil
made just under 500,000 barrels per day.
Co-Chair Bishop asked for the department to provide more
information defining the acronyms on the slide, such as
Environmental Social Governance (ESG).
9:41:36 AM
Mr. Peltier considered slide 6, "FY 2022 SUMMARY: COOK
INLET
Highlights (FY 2022 vs FY 2021)
•All fields are generally expected to see a year-on-
year decline
•Compared to FY 2021, in FY 2022 Cook Inlet production
decreased by ~11% (~1200 bopd)
il from the Cook Inlet basin critical to the supply
of in-state refineries
•Decreases
•Middle Ground Shoal: Field taken offline due to
fuel gas pipeline leak discovered in April 2021.
Production is currently suspended.
•Increases
•Beaver Creek increase due to rate-adding well
work.
•Redoubt Shoal and West McArthur River fields
brought back online in September and October 2021
respectively after being offline since May 2020.
Mr. Peltier addressed the top bar graph on the slide, which
showed a decline in production after the highest oil
production year for Cook Inlet in FY 16. The most recent
production level in FY 22 was 9,400 barrels per day. He
summarized that the majority of the fields in Cook Inlet
saw natural declines, there were large decreases and large
increases listed on the slide. He discussed the production
decrease in Middle Ground Shoal and relayed that the field
was taken offline due to a fuel gas pipeline leak
discovered in 2021. He pointed out an increase in Beaver
Creek due to well-work.
Co-Chair Stedman asked Mr. Peltier to touch on gas in Cook
Inlet, and assumed the charts showed only oil.
Mr. Peltier affirmed that the charts only showed oil
production.
Co-Chair Stedman suggested that the department start
considering a presentation about the Cook Inlet gas field.
He informed that the committee would be having forthcoming
discussions around energy and reminded that gas was a big
source of energy for heating. He suggested including the
history and trajectory of gas production.
9:45:12 AM
DEREK NOTTINGHAM, DIRECTOR, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, shared that DNR Division
of Oil and Gas had recently completed a production forecast
for the Cook Inlet gas, and would share it with the
committee.
Co-Chair Stedman relayed that he would work with the chairs
from the House and Senate Resources Committee on how to
handle the information.
9:45:50 AM
Mr. Peltier displayed slide 7, "STATUS UPDATE OF KEY FUTURE
PROJECTS: NORTH SLOPE," which showed a table of projects.
The slide addressed some of the groundwork for future
production on the North Slope. He noted that there were 17
projects, while the table highlighted 5 projects. He
thought the committee had most likely heard about the Pikka
and Willow projects in the news, which were new fields
brough online on the North Slope. The other three projects
constituted either new pads or pad expansions within
existing units on the North Slope.
Mr. Peltier reminded of discussion the previous year
regarding the Pikka project, and whether it would get
approved for final investment decision (FID). The project
FID came through in August 2022, and project first oil was
anticipated in 2026. He cited a peak design capacity rate
of 80,000 barrels per day, which had been publicly shared
by operators.
Co-Chair Stedman asked for a reminder as to who owned the
subsurface rights of the different projects, which should
have a significant impact on revenue. He noted that all oil
production increases helped with the throughput of the
Trans-Alaska Pipeline System (TAPS) as well as with an
impact on the treasury.
Mr. Peltier relayed that the Pikka project was on state
land and listed other projects on state land. The Willow
project was on federal land.
Co-Chair Stedman asked Mr. Peltier to briefly touch on why
there were tax differences between the projects.
Mr. Peltier deferred the question to Mr. Nottingham.
Co-Chair Stedman mentioned severance tax and royalties. He
commented that the state received royalties on federal land
but there was no state tax per se.
Mr. Nottingham relayed that on state land, the state
royalty ranged between 12.5 percent to 16.67 percent. The
percentage was applied to the overall value or volume of
the barrels produced off the land and would be revenue into
the state from royalties. He explained that the royalty on
federal land went to the federal government, with a portion
going to local communities.
Co-Chair Stedman relayed that the committee would revisit
the topic with more detail at a later time when the
committee considered the revenue forecast. He made the
point that all barrels of oil were not equal in terms of
paying the states bills.
Senator Olson thought Mr. Nottingham was trying to say that
the impact aid that came to some communities on the North
Slope was the way that the state benefitted from the
federal royalties it did not receive.
Mr. Nottingham agreed with Co-Chair Olson's assessment.
Co-Chair Stedman reiterated that there would be more detail
on the subject when the committee considered the revenue
forecast.
9:50:24 AM
Mr. Peltier addressed the Willow project listed on the
table on slide 7. He recalled that the project was remanded
by the Alaska District Court with a record of decision, and
at the time construction was expected to start in 2023 with
first oil in 2025 or 2026. In the year since, the Bureau of
Land Management (BLM) was awaiting a record of decision on
the supplemental environmental impact statement (EIS) that
was released in July 2022. ConocoPhilips, the operator of
the Willow project, could not make its FID prior to the
record of decision being made. The first oil was expected
to be six years after FID if the project was approved and
moved forward. The publicly stated estimates from the
supplemental EIS indicated 180,000 barrels per day at peak
two years after first oil.
Mr. Peltier addressed the CRU Narwhal CD8 project listed on
slide 7. He noted that there was discussion the previous
year about a Narwhal project. He cited that there were
project uncertainties. He noted that the vision for the
project was quite large. He discussed the most recent plan
of development submitted by ConocoPhilips, with production
possibly commencing as early as 2028. Production was
dependent upon alignment with stakeholders, permitting,
internal studies, and ultimate project approval. He cited
that the department estimated that about 3,200 barrels per
day could come from the project, which was on state lands.
Mr. Peltier spoke to the MPU Raven Pad project. He relayed
that Hilcorp had formally applied for approval to construct
a new drilling construction pad in November 2022. The pad
would be very analogous to a recently developed pad called
Moose Pad from 2018. The department estimated roughly
10,000 barrels per day on state land could come from the
project. He discussed the KRU Nuna-Tork project, which was
operated by ConocoPhilips. The most recent plan indicated a
plan to drill additional injector and producer wells to
apprise of future developments. The project had much
uncertainty but could turn out to be a large producer for
the North Slope on state lands.
Senator Kiehl commented that the state had often looked at
peak production design for a potential field, while peak
production did not last particularly long. He asked how to
look at the numbers when considering the longer-term
production of the wells in relation to the peak production
numbers.
Mr. Peltier commented that the numbers shown were peak
rates and used the Willow project as an example. He
explained that one would see a peak rate shared in a
supplemental EIS document two years after first oil
production then declining. He noted that most of the fields
on the North Slope were supported with water flooding or
other enhanced oil recovery activities. He mentioned
cumulative volume. He suggested taking the peak number, and
then computing a decline rate of 10 percent to 15 percent,
knowing that operators would be working to minimize the
decline.
9:56:08 AM
Mr. Peltier highlighted slide 8, "DNR FALL 2022 PRODUCTION
FORECASTING APPROACH
Recap: Minor changes in methodology from last year's
forecast. Changes are:
1) To more explicitly capture drilling activity into
Under Development and Under Evaluation, and
2) To have DOR and DNR forecasts be the same in the
first 5 months of the forecast period due to treatment
of actual production. [Fall 2022 Forecast]
Mr. Peltier relayed that the presentation would transition
to the production forecasting approach. He reminded that
DNR had been performing the analysis since 2016 and tried
to be as consistent as possible. He remarked on recent
improvements, including project definition. He explained
that the currently producing category had no future
drilling included. He noted that the definitions for the
production categories were listed in the RSB and were now
more accurate.
Co-Chair Stedman asked Mr. Peltier to remind the committee
about how the department received information from
producers in the fields dealing with expectations in the
future on a calendar basis. He thought producers reported
to the department twice a year. He thought there was a lot
of communication between the two groups.
Mr. Peltier noted that the next slide would address Co-
Chair Stedman's question.
Mr. Peltier advanced to slide 9, "DNR FORECAST PROCESS:
PROJECTS/POOLS INCLUDED IN FORECAST
•DOG performed ground-up Decline Curve forecasts for
all producing pools (Public)
•Forecast of Current Production uses AOGCC
publicly available data
•~37 pools (ANS and CI), producing as of
6/30/2022
•DOG engaged with operators through DOR-arranged in-
person and written interviews
•17 projects under development/under evaluation were
considered/researched/reviewed (Confidential)
•Forecast for these projects use confidential
information from operators
•Future production from these projects were
adjusted and risked for scope of contribution,
chance of occurrence and start date
•Minor modifications in forecast approach between Fall
2021 and Fall 2022 forecasts
1. To more explicitly capture drilling activity
into Under Development and Under Evaluation, and
2. To have DOR and DNR forecasts be the same in
the first 5 months of the forecast period due to
treatment of actual production
Mr. Peltier explained that the slide was meant to discuss
the projects and the Division of Oil and Gas and DORs
engagement with operators. He addressed Co-Chair Stedmans
question and relayed that the department had conversations
with operators throughout the year. Within the fall
production forecast timeframe there were many in-depth
conversations with operators that were confidential and
helped build the forecasts. The meetings were both in
person and via written responses. There was an update in
the spring wherein the department would meet with operators
and ask for updates to prior inflation that could be
material to forecasting efforts. He mentioned plans of
development, which had an aspect of confidentiality, and
were submitted every one to two years.
10:01:20 AM
Mr. Peltier addressed slide 10, "CATEGORIES OF PRODUCTION:
ONGOING/CURRENT VS FUTURE PRODUCTION
Ongoing/Current production
•Current Production (CP)
•Features and considerations:
•Well and facility uptime
•Operator spending to maintain base
production
•Reservoir management
Future production
•Projects Under Development (UD) and Under Evaluation
(UE):
•Rate contribution:
•Uncertainty in future well performance
•Uncertainty in project scope
•Project occurrence and timing:
•Uncertainty in timing (incl. outright
project cancellation/deferral)
•Commerciality risk (economic, regulatory
etc)
Mr. Peltier discussed the production categories. He
referenced 17 major projects and discussed infill drilling.
Within existing units, there was continued drilling
activity (with additional capital expenditures and
investment) where new wells were put into existing fields.
The contributions from the new wells came under under
development and under evaluation categories, which were
within the next 12 months and 12 months to the 120th month
respectively. He commented on the uncertainty of future
well performance and project scope, which were factored
into high and low parts of the forecast.
Mr. Peltier mentioned Pikka and Willow, which were not
currently producing and did not have infill opportunities.
He discussed project startup and timing, and noted that
there was additional risking included in production
profiles regarding when the projects would start up. He
mentioned commerciality risk, as the economic hurdles that
might need to be overcome for a project to progress.
Senator Hoffman referenced Mr. Peltier's comments about an
upcoming slide addressing capital expenditures. He asked if
Mr. Peltier would also address increases or decrease of
capital expenditures in the past, and projections for the
future. He thought the information was a single indicator
as to what policymakers would look for in projections
regarding future development on the North Slope.
Mr. Peltier relayed that DNR would not be sharing any
capital expenditure information in the slide, but would be
sharing information on expected production from future
capital investment.
Senator Hoffman requested that Mr. Peltier provide his
office with capital expenditure information, which had been
a major discussion for the previous decade. He thought the
information was critical to what the public policy makers
could expect on what was happening on the North Slope.
Co-Chair Stedman asked for Mr. Peltier to send the data to
the co-chair's offices to distribute and asked for him to
include delineation of deductible and non-deductible
expenses. He asked for any information about future
predictions of capital expenditures.
10:06:22 AM
Mr. Peltier advanced to slide 11, "MAJOR PROJECTS
[UNDEREVALUATION/DEVELOPMENT] CONSIDERED IN FALL 2022
FORECAST
Generalized characteristics
• Projects that were not online as at end ofFY2022
(data cut-off date of 6/2022)
• Higher risk factors than currently producing fields
• Known discoveries with identifiable operators
• Require major investments
North Slope Major Projects List (West to East)
• Smith Bay
• Willow
• Umiat
• CRU Narwhal CD8
• Horseshoe Stirrup
• Pikka Unit
• Quokka/Mitquq
• Mustang
• Nuna-Torok
• Ugnu
• MPU Raven Pad
• Theta West
• Talitha
• Alkaid
• Liberty Unit
• PTU Expansion
• Sourdough Project
Mr. Peltier commented that the risk associated with the
projects listed was higher than the currently producing
fields, such as Prudhoe Bay. The fields listed were all
known discoveries with identifiable operators, which all
required major investments over the following ten years. He
reviewed projects from west to east on the map on slide 11.
He began with the Smith Bay development shown in top left
corner of the map. He pointed to the Willow and Umiat
projects and noted a red square on the map indicated the
developments were located on federal lands. The CRU Narwhal
CD8 project was to the east of the Willow development. He
listed the remaining projects and their locations on the
map including Pikka, Quokka/Mitquq, Mustang, Nuna-Torok,
Ugnu (located across PDU, KRU, and MPU), MPU Raven Pad,
Theta West, Talitha, Alkaid, Liberty, PTU expansion, and
Sourdough project.
Senator Olson considered the Smith Bay project and asked if
Mr. Peltier had an update on the development.
Mr. Peltier thought much of the information could be
confidential and offered to get back to the committee with
what information could and could not be shared.
Mr. Nottingham generally stated that the operator was
actively looking at options to explore and delineate the
reservoir further.
Co-Chair Stedman asked the department to get back to the
committee with the information that was accessible. He
suggested that the committee could discuss the matter with
the operator, who may be inclined to provide further
information.
10:10:22 AM
Co-Chair Bishop asked if the information was only embargoed
for 10 years.
Mr. Nottingham offered to get back to the committee with
the answer to Senator Bishop's question.
Senator Kiehl referenced higher risk projects mentioned by
Mr. Peltier. He asked how the risks were put in the
forecast. He looked at projects that were far from
infrastructure and mentioned the Liberty project, which was
supposed to be coming soon twenty years previously.
Mr. Peltier agreed that all the projects listed had
uncertainty or risk. There were a few of major components
to the risk, including the chance of the project coming
online, the start date of the project, and whether it would
achieve the expected return rate. He explained that
multiple people with information on various aspects of the
projects would collaborate to discuss the pieces of
uncertainty related to projects. He compared the Liberty
and Raven projects and the types of risk considered. He
emphasized the importance of aggregating risk information
for all the projects. The same process was used to evaluate
all the projects before aggregating the results.
Senator Kiehl did not have a sense of exactly what the
process was.
Mr. Peltier noted that the group that aggregated the
information included engineers, geo-scientists, permitting
individuals, and commercial analysist. The process was
democratic and included about 24 individuals.
10:13:59 AM
Mr. Peltier showed slide 12, "FALL 2022 PRODUCTION FORECAST
RESULTS
Mr. Peltier discussed slide 13, "FALL 2022: NORTH SLOPE
ANNUALIZED FORECAST
• Short Term:
o DNR forecasts FY2023 annualized average daily
statewide production at 501 MBOPD, and North
Slope production at 492 MBOPD, with a range of
448 MBOPD and 535 MBOPD
• Long term:
o Long term forecast reliability is gauged by
general ballpark comparison between DNR and
operators' aggregate forecasts. Operators' long-
term outlook falls within DNR's long term
forecast range
o Specific differences are expected and do
highlight DNR's ground-up uncertainty analysis on
all included projects
• Outlook on production assumes that operators' plans
and other project drivers stay unchanged
Mr. Peltier addressed the chart on slide 13, which showed
the fall 2022 North Slope Forecast, with an axis with
fiscal year annual average daily oil production. There were
four components including the high forecast case, low
forecast case, and the two middle cases. The official
forecast case from the RSB and summation of the
confidential operator forecast showed the aggregated
picture for the following ten years. He noted that the
total official forecast included future projects, which did
not include the information from operators. For FY 23, the
DNR forecast showed an annualized average of daily
production of 501,000 barrels of oil per day, which was
492,000 barrels from the North Slope per day. He discussed
low-end and high-end numbers.
Mr. Peltier explained that MBOPD signified thousands of
barrels per day, while MM signified millions.
Co-Chair Stedman reminded that one decade previously there
had been oil forecast predictions that showed a parabolic
curve with a flat tail that would go on for several
decades. He thought the forecast had assumed that the
industry in the state would work to extend the life of
fields rather than let the natural decay happen. The
forecast from a decade previously had been very near to
what happened in reality. He commented that it would be
nice to get Willow and a few other larger projects moving
forward.
Mr. Peltier addressed the last bullet on slide 13
pertaining to the production forecast. He noted that there
were certain assumptions that had to be made in order to
make the production forecast be valid, although the
assumptions could change. He expanded that the process
started with data ending from June 30, 2022. He mentioned
the spring forecast update that would include any observed
changes. He noted that the forecasts did assume that
operators plans and other drivers remained unchanged
during the forecast period.
10:19:24 AM
Mr. Peltier reviewed slide 14, ALASKA STATEWIDE OIL
PRODUCTION FORECAST FALL 2022 EXPECTED CASE and
CATEGORIES OF PRODUCTION," which showed two charts. He
highlighted that the chart on the left of the slide showed
the fiscal year average daily oil production ranging from
zero to 700,000 barrels of oil per day. The blue showed
current producing fields declining over time, the orange
showed future development drilling within producing fields,
and the gray section reflected a combination of in-field
drilling and the 17 major projects under exploration
(growing over time through FY 32).
Mr. Peltier addressed the right-hand chart on slide 14,
which reflected projects under exploration only. He cited
production growth ramping up until the late 2020s, and
then another small peak at the end of the forecast period
in 2032. The trajectory had to do with how DNR did its
uncertainty analysis on future projects. He discussed the
risking process and how the forecast handled increases over
time.
Co-Chair Stedman commented on changing federal
administrations and asked how risking analysis was dealt
with when going from one administration to the next. He
commented that the previous administration had been helpful
to the state by moving the resource extraction industry
forward versus what appeared to be a less-than-
enthusiastic current administration.
Mr. Peltier relayed that the matter was addressed in to two
components of risking. He mentioned the two major
components of uncertainty for projects including the chance
of occurrence and the project start date. He mentioned the
Willow project. He noted that the production profiles were
spread out over time based on what the group decided.
Co-Chair Stedman thought the risking was balanced out each
year with consideration of current conditions.
Mr. Peltier answered affirmatively.
10:23:54 AM
Mr. Peltier referenced slide 15, "FALL 2022 PRODUCTION
FORECAST - SUMMARY
• DNR Forecast continues to use the best information
available to DNR/DOR, to generate production outlook
for oil fields within the state, with a focus on
generating accurate near-term, and realistic long-
term, forecasts.
• Fall 2022 Forecast is a static view on production;
DNR's outlook is updated annually (Fall and Spring)
to incorporate latest operator plans and the State's
official updated price outlook.
• DNR's Fall 2022 outlook shows mean annual production
of approximately 500 MBOPD across much of the
outlook period, based on the current snap-shot of
operators' plans.
• Production from projects under evaluation reflects
uncertainty in operators' plans towards return to
pre-pandemic activity levels, specific project
uncertainties, as well as project scope and timing
risks.
Mr. Peltier thanked the committee. He commented on the
effort expended to put together each year. He thanked the
forecasting team and those available online for questions.
Co-Chair Stedman thanked Mr. Peltier and the support staff
and acknowledged the preparation necessary for the
presentation. He discussed the upcoming schedule. He
commented that the price of oil was much more sensitive to
the states revenue than the production variable. He
commented that the following week would include
presentations on the budget.
ADJOURNMENT
10:27:13 AM
The meeting was adjourned at 10:27 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2023 01 18 SFIN DNR Fall 2022 Production Forecast Presentation v3.1.pdf |
SFIN 1/18/2023 9:00:00 AM |