Legislature(2023 - 2024)ADAMS 519
01/23/2023 01:30 PM House FINANCE
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| 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
HOUSE FINANCE COMMITTEE
January 23, 2023
1:32 p.m.
1:32:25 PM
CALL TO ORDER
Co-Chair Johnson called the House Finance Committee meeting
to order at 1:32 p.m.
MEMBERS PRESENT
Representative Bryce Edgmon, Co-Chair
Representative Neal Foster, Co-Chair
Representative DeLena Johnson, Co-Chair
Representative Julie Coulombe
Representative Mike Cronk
Representative Alyse Galvin
Representative Sara Hannan
Representative Andy Josephson
Representative Dan Ortiz
Representative Will Stapp
Representative Frank Tomaszewski
MEMBERS ABSENT
None
ALSO PRESENT
Helen Phillips, Staff, House Finance Committee, Legislative
Finance Division; John Boyle, Commissioner Designee,
Department of Natural Resources; Travis Peltier, Petroleum
Engineer, Division of Oil and Gas, Department of Natural
Resources; Representative Craig Johnson; Representative Tom
McKay.
SUMMARY
PRODUCTION FORECAST: DEPARTMENT OF NATURAL RESOURCES
1:33:37 PM
Co-Chair Foster introduced himself and relayed he would be
in charge of legislation for the committee.
Co-Chair Edgmon introduced himself and welcomed returning
and new finance members. He would be in charge of the
capital budget.
1:34:55 PM
Co-Chair Johnson introduced herself and expected to get
more information about operating budget subcommittees in
the near future. She discussed meeting protocol.
HELEN PHILLIPS, STAFF, HOUSE FINANCE COMMITTEE, LEGISLATIVE
FINANCE DIVISION, introduced herself and staff. She
welcomed the committee.
1:36:51 PM
Co-Chair Johnson reviewed the meeting agenda.
^PRODUCTION FORECAST: DEPARTMENT OF NATURAL RESOURCES
1:37:15 PM
JOHN BOYLE, COMMISSIONER DESIGNEE, DEPARTMENT OF NATURAL
RESOURCES, provided opening remarks. He discussed that the
Department of Natural Resources (DNR) produced the
production forecast in an effort to assist the legislature
better understand the outlook for the coming years in order
to make budgeting decisions for the state. He believed the
particular presentation should be cause for optimism. The
department was forecasting fairly flat production for the
next five years with a gradual increase as projects came
online. He stated the forecast was a bit of a departure
from previous years as many people had become accustomed to
seeing steady decline from Alaska's oil fields.
Commissioner Boyle explained that the current legacy field
operators were putting in the time and investment in order
to keep production relatively stable. He stated it was a
significant accomplishment to keep aging fields at steady
production when each additional molecule produced required
additional energy. The legacy backbones comprising North
Slope production (Prudhoe Bay, Kuparuk, Alpine) enabled DNR
to forecast the steady trend of continuing production.
Additionally, there was reason for optimism related to new
projects such as Pikka and Willow. He elaborated that the
type of project had the potential to significantly increase
state production. He explained that the department's
forecasting methodologies showed a relatively smooth
production gradient rather than a stairstep approach.
Commissioner Boyle highlighted the forecast for steady
production with legacy fields and new production coming
online. He stated new production was underpinned by the
Nanushuk formation. He elaborated that the discovery and
delineation of the particular geologic formation
highlighted Alaska as an exciting place for companies to
invest. He reported there was much reason to believe there
would be ongoing activity on the North Slope. He thought
there was much reason for optimism surrounding the
production front and the price of oil remained to be seen.
There was reason to continue to be mindful of the need for
continued good policies as the resources were managed, but
he believed the state would continue to see strong
investment and activity in the coming years.
1:42:07 PM
TRAVIS PELTIER, PETROLEUM ENGINEER, DIVISION OF OIL AND
GAS, DEPARTMENT OF NATURAL RESOURCES, provided information
about his educational and work background. He introduced a
PowerPoint presentation titled "Fall 2022 Production
Forecast," dated January 23, 2023 (copy on file). The
presentation focused on the forecast for the next decade.
He relayed that DNR had been performing the analysis since
2016. He noted the presentation would include methodology
and background on how the forecast was generated.
1:43:49 PM
Mr. Peltier covered the agenda for the presentation on
slide 2. The presentation would look at the FY 22 year in
review and the DNR production forecasting approach. He
would discuss the fall 2022 forecast results and a summary.
He noted each slide included a list of acronyms.
Mr. Peltier moved to slide 4 and discussed the FY 22
summary for the North Slope. The slide referred to
production areas, which was different than past years. He
explained that DNR and the Department of Revenue (DOR) were
striving for consistent terminology. He noted the DOR
Revenue Sources Book used the term production areas. 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.
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.
Mr. Peltier addressed production changes from FY 21 to FY
22 in the lower chart on slide 4. The blue color denoted a
production increase, and the orange denoted a decrease. The
chart began at a zero line. He highlighted Prudhoe Bay as
an example and stated there was a slight production
increase to 787 barrels of oil per day. The Prudhoe Bay
Unit (PDU) satellites produced 6,120 barrels per day, but
in total the top of the blue line was around 6,800 barrels
per day. He explained that the chart flowed with the most
recent cumulative sum of change.
1:49:24 PM
Mr. Peltier continued to review slide 4. He began with
Prudhoe Bay on the left of the lower chart. The forecast
showed a year-on-year production increase for PDU and PDU
satellites from FY 21 to FY 22. He noted that DOR included
the Milne Point Unit was included in PDU satellites;
therefore, a large percentage of the Milne Point
development was reflected in the PDU increase. He
highlighted there had been a change in operator from BP in
2020 to Hilcorp. He explained that investment from the new
operator in the PDU and PDU satellites led to the
production increase. He relayed that GPMA field operated by
Hilcorp within PDU showed a decrease reflecting natural
reservoir decline. He 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.
Mr. Peltier briefly noted that the decline in the Endicott
field was natural. The Alpine field saw a decline of just
under 11,000 barrels of oil per day reflecting natural
decline after returning to flush production from an
extended shut-in. He expounded that in 2021 and 2022 there
had been limited development drilling compared to
historical norms.
1:52:34 PM
Mr. Peltier continued to discuss slide 4. He stated the
next decease was in the Offshore areas at approximately
2,400 barrels per day due to natural reservoir decline.
There had been a large production increase for the Natural
Petroleum Reserve-Alaska (NPRA).
Representative Ortiz referred to the term development
drilling and its impact on overall production. He asked for
an explanation.
Mr. Peltier explained the term development drilling with an
example. He detailed that existing oil fields such as
Prudhoe Bay continued to invest capital to drill in-fill or
in-field wells.
Representative Ortiz surmised it was a way to keep
production levels up by doing more drilling in an already
established area.
Mr. Peltier agreed.
Co-Chair Foster asked for an explanation of the phrase
"flush production after extended shut-ins" pertaining to
the Alpine field.
Mr. Peltier replied that reservoirs on the North Slope
recharged a little around the wellbore. He elaborated there
was pressure decline around producing wells, which healed
or recharged during a shut-in period. Flush production
reflected a high production rate as the pressure transient
progressed through the reservoir before returning to a
steady flow rate.
Representative Hannan asked for the full name of the GPMA
field.
1:54:43 PM
Mr. Peltier responded that GPMA stood for Greater Point
McIntyre Area.
Representative Hannan asked where the GPMA field was
located.
Mr. Peltier answered that the GPMA field was directly north
of PDU and southeast of the North Star Unit.
Representative Hannan asked if the GPMA field was located
entirely on state lands.
Mr. Peltier believed the field was all on state land. He
noted it was not on federal land, but he did not know about
Native land holdings.
Mr. Peltier continued to address slide 4. He explained that
ConocoPhillips had brought the new pad GMT2 online in 2022
in the NPRA area. The new pad had only been online for a
number of months but had been meeting expectations and
resulting in a production increase of just over 7,000
barrels of oil per day. The last field on the chart was the
Point Thomson Unit, which had been developed by ExxonMobil
and come online in 2016. He stated it was a technically
challenged reservoir and had facility up time issues for a
number of years. Hilcorp was the current operator and had
continued the trend. The chart showed a total Alaska North
Slope change of about 9,570 barrels of oil per day.
1:57:16 PM
Mr. Peltier turned to slide 5 titled "FY 2022 As Forecasted
by DNR in Fall 2021: How did We Do?" He relayed that
production had come in within DNR's forecasted rates in FY
21. He expounded that the DNR mean forecast was about 2
percent higher than the actual FY 22 production. The goal
was to hit the mean forecast; however, it was very
challenging to do so. He explained that DNR provided a high
and low forecast and an official forecast that fell within
the range. He pointed to the chart on the right of the
slide showing the FY 22 North Slope forecast. The y-axis
showed the FY annual average daily oil production ranging
from zero to 600,000 barrels. The first bar reflected the
DOR Revenue Sources Book forecast for a high of 524,170
barrels and the fourth bar showed DOR's low forecast of
just under 450,000 barrels per day. The second bar showed
DNR's official forecast for FY 22 of 486,730 barrels per
day. The actual FY 22 production was 476,490 barrels of oil
per day. The actuals came within DNR's range of
expectation. The department also asked operators for their
own individual forecasts, which were confidential
individually, but could be provided in an amalgamated form.
Representative Galvin asked if the operator forecasts
included projects on the horizon (e.g., Willow).
Mr. Peltier answered that the future projects were not
included in the number.
2:00:31 PM
Representative Stapp asked about the purpose of including
the high projection range.
Mr. Peltier answered that production forecasting was
difficult. He explained that the high and low forecast put
out a range showing what DNR believed would happen in the
next 12 months. The high and low range provided median
barriers that production would stay within. He stated that
the operators provided a forecast to deliver to their
business. He referenced a quote: "A P50 forecast is a
forecast they hit 90 percent of the time." He stated it was
very hard to do.
2:02:24 PM
Representative Hannan asked if it was normal for the
operator forecasts to be slightly more optimistic than the
DNR forecast.
Mr. Peltier responded that he would have to look at the
historical information to answer the question.
Representative Hannan replied that she did not need the
department to take the time to compile the information.
Mr. Peltier replied that when he had worked in private
industry, the operators did not look at the state's
production forecast for the PDU satellites; however, the
midstream asset did look at production throughput of the
Trans-Alaska Pipeline System (TAPS), which had been
important for market consistency engineers.
2:05:02 PM
Mr. Peltier continued to address slide 5. He discussed
factors to watch for that currently shaped the forecast
horizon. He stated that environmental social governance
(ESG) influences continued to challenge capital allocation
decisions in the Arctic, especially for early-stage oil
projects under development and evaluation. He relayed the
department often heard it was hard to get money for
projects on the North Slope. On the other hand, DNR also
heard about continued interest in the Nanushuk development.
He elaborated that leases on state and federal land
continued to draw interest due to their high resource
potential.
Representative Josephson stated he had heard corporate
interests using the term ESG favorably more and more. He
asked if the industry (e.g., ExxonMobil) was
allowing/welcoming the influence of ESG and thereby
inviting the problem.
Commissioner Designee Boyle replied that ESG could mean
different things to different people in different contexts.
He relayed there were still a number of lending
institutions domestically and internationally that had
generalized blanket policies they couched as part of their
ESG principles that prohibit investing in new hydrocarbon
development in areas such as Alaska. He elaborated that
companies needing to look for outside sources of financing
in order to develop a project were running into the
roadblocks. He stated that a number of oil companies in
Alaska including ExxonMobil, Santos, and ConocoPhillips had
set targets to become net zero. The department was not
seeing policies from the industry side as a factor playing
into a lack of investment in Alaska. He noted there were
some global companies that had announced a reticence to
further Arctic investment. Generally, the point on slide 5
pertained to lending institutions that has a blanket
prohibition on Arctic investment and how it influenced the
availability of capital.
Representative Josephson recalled a recent Alaska Oil and
Gas Association (AOGA) meeting where most everyone was
using ESG. He considered perhaps they had been using it in
a different way or the term was being borrowed.
2:09:44 PM
Co-Chair Johnson recognized Representative Craig Johnson in
the room.
Mr. Peltier turned to slide 6 showing an FY 22 summary for
Cook Inlet. He noted the slide reflected oil production
only and did not include gas. He stated that due to natural
reservoir decline, the department typically expected to see
all fields decline year-on-year. He reported that Cook
Inlet production increased by about 11 percent or 1,200
barrels per day from FY 21 to FY 22. He relayed that oil
from the Cook Inlet basin was critical for instate
refineries. He looked at the Cook Inlet daily oil
production in a chart on the upper right side of the slide.
The y-axis showed the fiscal year annual average daily oil
production with a range from zero to 20,000 barrels per
day. The high point on the chart was in 2016 at 16,585
barrels per day. The chart showed production mostly
declining over time with a bump in 2017. He highlighted a
reduction from 10,600 barrels per day in FY 21 to about
9,400 barrels of oil per day in FY 22. He noted there were
many oil producing fields in the Cook Inlet area; however,
the forecast showed the Cook Inlet basin lumped into a
single oil production basin.
Mr. Peltier reviewed the chart on the bottom of slide 6
showing average yearly production changes across Cook Inlet
assets. The majority of the fields in Cook Inlet saw
natural reservoir decline from FY 21 to FY 22. He pointed
to a decrease of about 930 barrels of oil per day in the
Middle Ground Shoal field was a result of the field being
taken offline in April 2021 due to a fuel gas pipeline
leak. He stated that production from the specific field was
currently suspended. He reviewed the three increases
beginning with the Beaver Creek Unit, which increased by
490 barrels per day from FY 21 to FY 22 due to successful
rate adding well work. Additionally, the Redoubt Shoal and
West McArthur River fields had been brought back online in
September and October 2021 respectively after being offline
since May 2020 due to COVID-19 pandemic reasons.
2:13:50 PM
Representative Hannan referenced the Middle Ground Shoal
field that Mr. Peltier had referred to as offline. She
asked for the difference in the terms offline and shut in.
Mr. Peltier answered that shut in meant the field was
turned off; the field was still capable of producing oil,
but it was not being operated due to a leak in the fuel gas
pipeline. He explained that if the integrity issue was
resolved, the field could be brought back online.
Representative Hannan asked if the terms had been used
interchangeably in the current context.
Mr. Peltier answered affirmatively.
Co-Chair Johnson acknowledged Representative Tom McKay in
the room.
2:15:24 PM
Mr. Peltier turned to slide 7 and discussed a status update
of five key future projects on the North Slope. He
highlighted Pikka and Willow as new fields scheduled to
come online during the next ten years, while the Colville
River Unit (CRU) Narwhal CD8, Milne Point Unit (MPU) Raven
Pad, and the Kuparuk River Unit (KRU) Nuna-Torok were new
pads within existing fields. He elaborated that CD8 and the
Raven Pad would be brand new, while Nuna-Torok would be a
pad expansion. He relayed that each of the projects
represented a large capital investment for operators.
Mr. Peltier provided an update on the Pikka project. He
detailed that when the project had been discussed with the
legislature the previous year, it had been in the front end
engineering and design (FEED) stage. He elaborated that the
start of production and phase 1 was expected to be online
in 2025, the phase 2 final investment decision (FID) had
been expected shortly thereafter. He explained there had
been a Santos and Oil Search merger completed as well. He
relayed that the project had been granted FID for phase 1
in August 2022 and first oil was expected in 2026 from
Santos. The peak design rate for phase 1 of the project was
80,000 barrels per day per public information released by
Santos.
Mr. Peltier reviewed the Willow project on slide 7. He
detailed the project had been remanded from the Alaska
District Court in 2022 to target a new Bureau of Land
Management (BLM) decision. He explained that construction
had been anticipated to start in the first quarter of 2023
with first oil in 2025 or 2026. Currently the project was
awaiting a BLM record of decision (ROD) on its supplemental
environmental impact statement (EIS), which was released in
July of 2022. ConocoPhillips was the operator and it could
not make the FID until the ROD was released. If approved,
first oil was expected six years after FID. The peak rate,
as published in the supplemental EIS, was 180,000 barrels
of oil per day.
2:18:20 PM
Representative Ortiz asked for a high level overview of
factors that went into companies' FID decisions.
Commissioner Designee Boyle replied that companies looked
at a number of factors including the level of confidence a
geologist and reservoir engineers had that the underlying
resource would produce at anticipated rates. Second, there
were commercial and financial considerations such as the
cost of supply and transportation, the expected rate of
return, severance tax, royalties, and any pending policy
issues that could lend to increased risk. Generally, many
companies had global portfolios or a multitude of assets
spread across a region.
Commissioner Designee Boyle explained that when a board of
directors was making a final investment decision, an Alaska
project may have to compete with a project in Papua New
Guinea, Surinam, Texas, or elsewhere. He elaborated that
boards had to look at all of the potential projects and
determine which could move quicker, be successful, and
offer a competitive rate of return. He furthered that once
a company had received approval for FID, it indicated the
company had successfully made the case to its board and
shareholders that the project would add value to the
company.
2:21:49 PM
Mr. Peltier continued with slide 7 and discussed the CRU
Narwhal CD8 project. He relayed that DNR had given a
presentation to the legislature that the project had first
oil in December of 2021. He explained that typically, the
department would categorize such a project as currently
producing; however, the CD8 project was a large capital
investment. He expounded that DNR opted to categorize CD8
as an uncertain project, while moving some of what was
historically Narwhal into the currently producing category.
According to the ConocoPhillips plan of development, CD8
could commence as early as 2028, pending stakeholder
alignment, permitting, and internal studies and alignment.
The DNR peak estimate was around 32,000 barrels of oil per
day.
Mr. Peltier discussed the MPU Raven Pad on slide 7. He
explained that in 2022, the plan of development discussed
future drilling opportunities in undeveloped acreage in the
northwest of the unit. Hilcorp had formally applied for
approval to construct a new drilling and production pad,
also known as R Pad, on ADL 025509 within MPU. He detailed
it was analogous to the previously developed Moose Pad or M
Pad within MPU. The estimated peak rate for the pad was
around 10,000 barrels of oil per day.
Mr. Peltier reviewed the KRU Nuna-Torok development on
slide 7. The 2021 plan of development was for two appraisal
wells and additional seismic data processing. In 2022, the
plan of development included rotary drilling in the third
quarter of 2022 with an additional injector/producer pair
for additional Torok reservoir appraisal to inform future
development. Assuming ConocoPhillips moved forward with the
pad, DNR projected a peak rate of 25,000 barrels of oil per
day.
2:25:04 PM
Representative Josephson asked for verification there
should not be an assumption the Willow project would be
generating 700,000 barrels per day in 2029.
Mr. Peltier agreed. He added there was a lot of uncertainty
about when the projects would come online and the
production they would generate. He would expound on the
answer over the next several slides.
Mr. Peltier turned to slide 8 and discussed the DNR fall
2022 production forecasting approach. The department worked
to be consistent with its forecasting and worked to make
improvements to provide a better forecast. He reviewed a
couple of minor changes in methodology from the prior
year's forecast. First, in past years under the current
production category, DNR had included capital and
development drilling, which reflected a future expense
baked into current production. He clarified that current
production should only be what was in place at the end of
the last fiscal year; therefore, all future capital spend
for future drilling was captured in the under development
or under evaluation categories. He elaborated that the DOR
Revenue Sources Book defined the three categories;
therefore, DNR changed its methodology to be more in line
with DOR's definition. Second, previously there had been a
slight variation in the first few months of the forecast
period between the DNR and DOR forecasts. He explained that
the updated forecasting approach included aligning the two
forecasts to show the same numbers.
2:28:23 PM
Mr. Peltier turned to slide 9 and reviewed the projects and
pools included in the DNR forecast. The Resource Evaluation
Section within the Division of Oil and Gas looked at all of
the pools on the North Slope and Cook Inlet and generated a
decline curve analysis for all producing pools. The
information was generated from public data from the Alaska
Oil and Gas Conservation Commission (AOGCC). He noted that
pools had to be in production by June 30, 2022 to be part
of the category. The division also engaged with operators
through DOR in in-person and written interviews to gain
information about current fields and future projects. He
detailed that 17 projects under development/under
evaluation were included in the current production
forecast. He relayed that projects used confidential
information from the operators; therefore, the information
was presented as a single aggregated number. The projects
were adjusted for scope of contribution, chance of
occurrence, and start date.
2:30:32 PM
Mr. Peltier discussed categories of production on slide 10
including ongoing/current production and future production.
He began with ongoing/current production, which encompassed
production up to June 30, 2022. The category included the
Prudhoe Bay Unit, PBU satellites, Kuparuk River Unit, and
Alpine Units and evaluated well and facility uptime within
the units to provide an appropriate decline curve analysis.
The department talked with operators to ensure they were
maintaining their base production by appropriately spending
and investing in their fields. Additionally, the department
looked at reservoir management practices and evaluated
whether there were any changes that would impact trends in
the future.
Mr. Peltier discussed future production on the bottom
portion of slide 10. He noted that future production was
much more uncertain [than ongoing/current production]. He
added that many of the currently producing fields had been
operating for around 50 years. He stated that Prudhoe Bay
had started in 1977; therefore, five decades of production
history provided a lot of credence on how to decline the
field. Many of the projects under evaluation/under
development were brand new fields in reservoirs with short
production histories on the North Slope. The department
considered rate contribution including uncertainty in
future well performance and in project scope. He noted the
range could be quite large resulting in a large uncertainty
band. Project occurrence and timing was also important.
Mr. Peltier discussed that some future projects were
cancelled over time. He highlighted the Nikaitchuq North
offshore development as an example and explained the
project had never occurred and the leases had been
relinquished; therefore, the project was not included in
the fall 2022 production forecast. Additionally, DNR
evaluated commercial risk based off of expected future
prices of oil.
2:33:38 PM
Mr. Peltier moved to a map on slide 11 showing major
projects under evaluation/development considered in the
fall 2022 forecast. He reviewed general characteristics of
the projects. First, the projects were not online at the
end of the data cutoff period of June 30, 2022. Second, the
projects had higher risk factors than currently producing
fields. Third, the projects were known discoveries with
identifiable operators, and fourth, the projects required
major investments. 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.
Co-Chair Johnson asked if the Ugnu formation was drilled at
a different depth.
Mr. Peltier answered that the Ugnu formation was shallower
than most of the producing fields; the depth was just below
the permafrost and above the Schrader Bluff Formation.
Co-Chair Johnson observed that the Smith Bay development
was located off the coast of NPRA. She asked for
verification the location was a state lease.
Mr. Peltier confirmed Smith Bay was a state lease.
2:37:04 PM
Mr. Peltier continued to review the list of major North
Slope projects on slide 11 including MPU Raven Pad, Theta
West, Talitha, Alkaid, Liberty, Point Thomson Unit (PTU)
expansion, and Sourdough project.
Mr. Peltier turned to slide 13 and discussed the fall 2022
North Slope annualized forecast. The y-axis of the chart
showed the fiscal year annual average daily oil production
barrels per day with a range of zero to 1 million barrels.
The chart included the DOR Revenue Sources Book high
forecast reflected as a blue line and its low forecast
reflected in gray. The DOR official forecast was shown in
dark blue along the middle of the chart. The summation of
the operator forecasts was included as a dotted line. He
added that operator forecasts only included currently
producing fields; however, the DOR official forecast
included future projects.
Representative Galvin looked at the highs and lows on slide
13 and observed the extremes were much broader than on a
prior slide. She asked for detail.
Mr. Peltier answered that the high and low cases diverged
through time based on uncertainty of how projects would
play out in the future. He explained that over time some of
the projects expected to come online added a potentially
higher rate than the forecast. He elaborated that as
projects continued to be added, the forecast continued to
diverge on the high side, whereas the low end reflected a
scenario where projects did not come online.
Representative Galvin remarked that results for FY 22
generated in the fall of 2021 showed a very small
difference between the high and low scenarios compared to
the chart on slide 13. She asked if it was not out of the
ordinary based on Mr. Peltier's previous response.
2:41:28 PM
Mr. Peltier answered that the uncertainty was hard to
gauge. He explained that every year the uncertainty band
continued to increase through time. He elaborated that in
the next five months, plus or minus 5 percent may be
something reasonable to expect and beyond that time period
the range may be plus or minus 10 percent. He clarified
that the contribution from future uncertain projects was
the reason the band increased.
Representative Galvin saw there was a difference of about
plus or minus 75,000 barrels in the near-term and a
difference that was closer to 200,000 barrels per day in
the future. She believed Mr. Peltier was explaining the
difference was within the norm. She thought it was a much
greater range.
Mr. Peltier answered that the uncertainty band was the
nature of the way the analysis was done year-on-year. He
explained that when looking at the forecast from the
previous year the same was true.
Representative Josephson referenced the Smith Bay project
shown on the map on slide 11. He recalled there had been
constant discussion with the legislature between 2013 and
2015 about the field's potential including meetings with
the oil company Caelus. He referenced the industry's desire
at the time for continuing cash credits that had been
suspended by the state in the middle of the past decade. He
clarified he was not saying Smith Bay would not happen, but
he observed that the excitement about the field had gone
away. He asked how to know when a project would come to
fruition. He asked if it was FID and the lack of
litigation.
2:44:21 PM
Mr. Peltier responded that when the department looked at
all 17 projects individually, every project had uncertainty
around start date and chance of occurrence. He explained
there was a group of 24 people in the room who all got one
vote. He detailed that projects like Smith Bay may be
considered higher risk by some people than something like a
pad expansion off an existing field. He used Smith Bay
compared to the MPU Raven Pad as an example. The department
had a higher risk associated with possibility the Smith Bay
project would come online. The department did not want its
forecast to pick on any one project; therefore, it relied
on the broad perspective of the group to determine how to
aggregate Smith Bay's production forecast. In comparison,
the group within the department would likely consider the
Raven Pad project as lower risk because it was an existing
pad within an existing field with no subsurface risk.
Mr. Peltier clarified the department did not want to pick
winners and losers in the forecast; it worked to aggregate
the projects using the same method. He explained that the
department added all of the project risk components using a
Monte Carlo analysis. He stated that while some of the
group may think Smith Bay had a high chance of coming
online and others may think it had a low chance of coming
online; the department used all of the results to aggregate
a forecast.
2:46:52 PM
Representative Josephson stated he was not spending a
significant amount of time thinking about Smith Bay, but he
recalled the incredible amount of excitement about the
field in the past. He had not heard anything about the
project in recent years and it made him watchful and a
little skeptical sometimes.
Representative Stapp looked at the fall 2022 North Slope
annualized forecast on slide 13. He stated his
understanding that Willow was awaiting the record of
decision by the BLM, FID would come next, and first oil
would be projected six years from the FID. He calculated
oil could be expected as early as 2029; however, he did not
see any associated projected increase in the official
forecast. He asked how to reconcile the two things.
Mr. Peltier answered that he would more fully address the
question on a subsequent slide. He explained the forecast
accounted for the various uncertainties including start
date, amount of production, and FID approval and spread out
the potential production increase over time. He clarified
the forecast would not show a dramatic increase in the
production rate; the increase would be reflected as a
gradual wedge over time. He noted the phenomenon was
illustrated on slide 14.
2:49:33 PM
Representative Ortiz looked at the variance between the
high and low projections. He thought it was understandable
the variance increased over time. He asked if forecasts
included variables like changes in technology and potential
successes in alterative energy that may make oil less
advantageous.
Mr. Peltier replied that the department's forecast did not
include the impact of substantial changes to future oil
demands. The department included technology changes
operators were already using, but it did not include
changes in technology that may come in the future.
Mr. Peltier provided a recap of the difference between the
DOR and DNR forecasts. He explained that the DNR official
forecast included future projects. The operator forecast
came from currently producing operators and excluded future
projects. He clarified that the Willow and Pikka projects
were not included in the operator forecast, which was one
of the reasons the official forecast and operator forecast
began to diverge in FY 27 [slide 13]. He highlighted that
in the short-term (FY 23), the DNR forecast for the average
daily statewide production was just over 500,000 barrels of
oil per day. He clarified that the acronym MBOPD stood for
thousand barrels of oil per day, whereas MMBOPD stood for
million barrels of oil per day. The DNR forecast included
FY 23 production at 492,000 with a range of 448,000 and
535,000 barrels per day. In the long-term, the department
anticipated the 500,000 barrels per day to continue for the
next five or so years.
Mr. Peltier explained the forecast had to include many
assumptions that operators would continue to inject and
manage reservoirs as they had in the past. He elaborated
that the forecast was updated when operators changed their
activity set or business information. He noted the process
occurred in the fall and spring.
2:54:06 PM
Mr. Peltier advanced to slide 14 showing the fall 2022
expected case and categories of production. 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 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). The
chart on the right of the slide reflected projects under
exploration only. He pointed out that in-field development
drilling and project aggregation were major contributors to
the oil production forecast over the next ten years.
Mr. Peltier turned to slide 15 and discussed the 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 snapshot 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.
2:57:25 PM
Mr. Peltier thanked the committee for inviting the
department to present the production forecast team. He
listed members of the production forecast team within the
department.
Co-Chair Foster pointed to slide 5 showing the FY 22
forecast. He looked at the difference between the forecast
of 486,730 and the actual of 476,490, which was a
difference of about 10,000 barrels per day. He looked at
slide 13 showing the DNR forecast for FY 23 North Slope
production at 492,000 barrels per day. He observed the
forecast for FY 23 was up from the actual FY 22 production
by about 15,500 barrels per day. He asked if his statements
were accurate.
Mr. Peltier responded affirmatively. He confirmed the
numbers listed by Co-Chair Foster were accurate and there
was an increase projected in the coming year.
Co-Chair Johnson thanked the presenters. She informed
committee members they would receive emails about
subcommittee assignments. She reviewed the agenda for the
following meeting on Wednesday. She introduced her
operating budget staff Remond Henderson.
ADJOURNMENT
3:00:46 PM
The meeting was adjourned at 3:00 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2023 01 23 HFIN DNR Fall 2022 Production Forecast Presentation.pdf |
HFIN 1/23/2023 1:30:00 PM |
DNR - HFIN |