Legislature(2023 - 2024)ADAMS 519
01/17/2024 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| 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
HOUSE FINANCE COMMITTEE
January 17, 2024
1:35 p.m.
1:35:25 PM
CALL TO ORDER
Co-Chair Johnson called the House Finance Committee meeting
to order at 1:35 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
John Boyle, Commissioner, Department of Natural Resources;
Travis Peltier, Petroleum Reservoir Engineer, Division of
Oil and Gas, Department of Natural Resources; Derek
Nottingham, Director, Division of Oil and Gas, Department
of Natural Resources; John Crowther, Deputy Commissioner,
Department of Natural Resources.
SUMMARY
PRESENTATION: PRODUCTION FORECAST BY THE DEPARTMENT OF
NATURAL RESOURCES
1:36:20 PM
AT EASE
1:36:36 PM
RECONVENED
Co-Chair Johnson welcomed committee members and staff. She
discussed meeting protocol and decorum and introduced House
Finance Committee staff. She thanked various members of the
Legislative Finance Division staff and her staff.
^PRESENTATION: PRODUCTION FORECAST BY THE DEPARTMENT OF
NATURAL RESOURCES
1:40:07 PM
JOHN BOYLE, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES,
introduced himself and staff. The Department of Natural
Resources (DNR) would present its fall 2023 oil production
forecast. He relayed that DNR undertook the exercise
semiannually to help inform decision makers on what the oil
and gas production landscape looked like across the state.
The department welcomed feedback on the ways it could
improve the presentation of its data in a useful way. He
shared that Alaska was on an exciting oil and gas
production trajectory. The state was currently realizing a
"major boom" in investment at the beginning of a new
chapter on the North Slope.
Commissioner Boyle stated that for decades the major
producers had controlled the fate of the North Slope. He
explained that it was the beginning of a new era with new
operators and explorers opening up new prospective areas on
the North Slope. He detailed that different companies with
different investment profiles that may prioritize investing
in Alaska differently than other companies were infusing a
new energy on the North Slope. He remarked that the state
was starting to see a healthy mix of competition and
investment dollars that would be a great benefit to the
state in the long run. The situation was being driven by
multiple projects and commitments and had been years in the
making. He believed credit was due to the legislature for
enabling an investment climate that bred confidence.
Commissioner Boyle pointed out that oil and gas
developments did not happen overnight. He stated that
companies could not merely acquire a lease and start
producing oil six to twelve months later as they could in
Texas and North Dakota. He clarified that the timeline for
new oil and gas developments in Alaska was 10 to 12 years.
The projects took substantial time and effort; the time led
to uncertainty and increased cost for companies. He noted
that permitting and regulatory framework could be
challenging, particularly if there was a federal nexus to
the permitting. He stated it took a number of factors
working together to create an environment incentivizing
companies to invest. He reported that based on what DNR was
seeing on the North Slope, it appeared that Alaska had its
policy right. The state was seeing investment and activity
and it would begin recognizing the fruits of the policy in
the next several years in the form of increased production.
1:45:01 PM
Commissioner Boyle continued to provide opening remarks.
The department projected that North Slope oil production
would exceed 630,000 barrels per day by 2033. He argued
that the estimate was relatively conservative. The number
reflected DNR's confidence in seeing new projects,
particularly Willow and Pikka, which had both received
their final investment decisions (FID) and were in various
stages of construction and development. He noted that
current [North Slope] production was approximately 480,000
barrels per day. He expressed optimism about the projection
for 630,000 barrels per day in the future.
Commissioner Boyle relayed that a large part of the state's
oil production continued to come from legacy fields. While
production decline was natural in legacy fields, the state
continued to see operators make investments and infill work
to stem and/or reverse the decline. He remarked that it was
critical because the legacy fields maintained the
[production] backbone and provided the opportunity to
bridge new projects coming online, which would begin
accounting for a larger component of Trans-Alaska Pipeline
System (TAPS) throughput. He highlighted that data in the
presentation showed that by 2033 legacy production from
fields in Prudhoe Bay, Kuparuk, and the Colville River Unit
(CRU) would represent the minority of the oil in TAPS,
while new projects including Pikka, Willow, and expansions
such as Quokka and Horseshoe would comprise the lion's
share of production.
Commissioner Boyle highlighted there were promising
opportunities on the exploratory work [the producer] Great
Bear Pantheon was doing on its Talitha and Alkaid units
along the Dalton Highway. Additionally, [the company]
Apache had partnered with Armstrong and had announced plans
to drill three exploratory wells in the current winter
located on the eastern North Slope to continue the Brookian
play. The department was excited to see the results of the
exploration, which could result in significant production
in the future. He characterized the current production
environment as a health ecosystem where companies were
investing and targeting a multitude of different geologic
formations.
1:48:55 PM
Commissioner Boyle stated that with some of the growth came
some growing pains. He explained that workforce service
capacity and infrastructure needed to support the new
development was being stretched. There was close to $18
billion coming into the state between Santos,
ConocoPhillips, and other North Slope operators. He
believed they were good challenges in some ways, but the
state was keeping an eye on the situation. Despite all of
the good things, the department was monitoring some
potential challenges. He elaborated that the state was
seeing movement out of the federal government, particularly
with a proposed Natural Petroleum Reserve-Alaska (NPRA)
rule making, which could have a significant impact on the
efficacy of future permitting or development efforts in the
NPRA.
Commissioner Boyle relayed that the state was seeing
continued challenges with some operators in terms of the
financial environment for oil and gas. He stated that the
strong drive towards some of the environmental and social
governance (ESG) principles seen in a number of financial
institutions pre-pandemic had waned. He believed there was
a greater realization in the investment community that the
energy transition was taking a significant amount of time
and that transitions had to be just and ensure people had
access to reliable and affordable energy sources. He
explained that while there continued to be some headwinds
when it came to investment in the Arctic and Alaska, there
were indications of some willingness to engage. The state
would continue to engage in the effort to tell the story of
how development was done in Alaska. He expounded that no
one valued having clean air and water and a pristine tundra
more than the residents of the area.
Commissioner Boyle summarized that the department's
forecast was very optimistic. He stated that DNR had worked
to provide robust data in the presentation as the committee
thought through long-term planning for the state. He
welcomed questions and input.
1:52:22 PM
TRAVIS PELTIER, PETROLEUM RESERVOIR ENGINEER, DIVISION OF
OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES, provided
information on his educational and professional background.
He provided a PowerPoint presentation titled "Fall 2023 Oil
Production Forecast: House Finance Committee," dated
January 17, 2024. He relayed that DNR had been performing
the 10-year oil production forecast since 2016. He planned
to share the oil production forecast result for FY 23 and
the forecast for the next 10 years. The presentation also
included information on how the forecast was generated. He
noted the presentation appendix included a list of acronyms
used in the presentation.
1:55:16 PM
Representative Hannan asked when the department's forecast
data translated to the Department of Revenue (DOR). She
asked if DOR used DNR's number as provided or reanalyzed
it. She also wondered whether DOR participated in the
forecast development.
Mr. Peltier answered that DOR did not change the
[production] forecast number provided by DNR; however, he
could not speak to how DOR parsed it out amongst the
various state and federal leases. The forecast provided by
DNR was the forecast used by DOR.
1:56:14 PM
Mr. Peltier turned to a chart titled "Fall 2023: North
Slope Annualized Forecast" on slide 3. The y-axis of the
chart reflected the fiscal year annual average daily oil
production and barrels of oil per day (BOPD) showing a
range from zero to 1 million BOPD. The x-axis showed fiscal
years from 2024 through 2033. He noted that the forecast on
the slide was reflected in the DOR Revenue Sources Book
(RSB) released in the fall of 2023; the data was included
in various parts of chapter 6 of the RSB. The dark blue
line on the chart reflected the official DNR forecast,
which reflected the P50 value including existing fields and
future production from future projects such as Pikka and
Willow. He noted the forecast included risk and had been
described by Commissioner Boyle as conservative. He stated
that creating and meeting a single forecast every year was
difficult; therefore, DNR generated a high and low
production forecast as well. He highlighted that in FY 24
the range was about plus or minus 5 percent. He noted that
because uncertainty grew over time, the number was closer
to plus or minus 50 percent by FY 33.
Mr. Peltier continued to explain the chart on slide 3. The
department had conducted in-person and written interviews
with operators of existing fields to learn what they
believed their assets on the North Slope and Cook Inlet
would produce. The department summarized the information
from operators and included it in the forecast [as shown by
the black dotted line]. He pointed out that in FY 24 DNR
and the operator expectations were very similar. He
clarified that the operator data only reflected existing
fields and did not include fields in development (e.g.,
Willow and Pikka), which accounted for the divergence
between the operator and official forecast lines around FY
27.
Representative Stapp observed that operators seemed to
anticipate production exceeding 500,000 barrels per day in
FY 25 and FY 26. He did not believe oil production had
exceeded 500,000 barrels per day in almost a decade. He
asked for an explanation.
Mr. Peltier answered that he could not explain how the
operators came up with their forecast.
Representative Stapp hoped the operators were right for the
next two years and that DNR was right for the following
years.
2:00:34 PM
Mr. Peltier moved to slide 5 titled "FY2023 as Forecasted
by DNR in Fall 2022: How did we do?" He looked at the chart
on the right side of the slide showing the FY 23 North
Slope forecast. The chart reflected the annual average
daily oil production per day ranging from zero to 600,000
barrels of oil per day. He relayed that chapter 6 of the
DOR RSB included a high and low forecast. He pointed to the
dark blue bar reflecting DNR's official forecast and noted
that DNR considered the forecast to be a success as long as
it fell within the range between the high and low
scenarios. Actual production in FY 23 was 479,380 barrels
per day, which was about 3 percent lower than DNR's
official forecast at 491,700 barrels per day. The FY 23
operator forecast was 482,461 barrels per day, which was
closer to the actual production, but still within DNR's
forecast range.
Representative Ortiz asked what factors caused the actual
FY 23 production to be a bit less than DNR's official
forecast rather than a bit more.
Mr. Peltier responded there were three major things the
department observed in FY 23. He elaborated that declines
had resulted from challenges associated with the Badami
Unit's primary well and Point Thomson's single producing
well. The other two things had to do with existing or
"infill" drilling. He explained that DNR forecasted the
number of wells about right, but the expectation for the
wells had not been met. Additionally, a new development in
the NPRA had a significant production gap in the past year.
He noted that the GMT Unit was highlighted on slide 6. He
explained that DNR had forecasted a number based off of
little data; the department had received more data the past
year, but unfortunately the development did not meet its
expectations.
Representative Ortiz assumed there were other areas that
likely exceeded DNR's forecast expectations.
Mr. Peltier agreed.
2:04:42 PM
Mr. Peltier addressed factors currently shaping the
forecast horizon on slide 5. He relayed that industry
interest was expanding in Brookian age plays across the
Nanushuk and North Slope. He detailed that Armstrong was
partnering with Apache on a three-well exploration program
on the eastern North Slope on state lands. He highlighted
continued development on the Willow and Pikka projects on
federal and state lands respectively. The projects were all
located in Brookian age formations. He relayed that Great
Bear Pantheon projects Talitha and Alkaid were also
Brookian age plays that were of high interest to industry.
The department continued to see challenges associated with
ESG influences, which continued to challenge capital
allocation decisions in Alaska. He noted that companies and
investors were adapting and trying to figure out how to get
investment in Alaska. He added there had been some federal
regulatory changes and leasing restrictions that had
presented challenges, which was one of the reasons a couple
of projects had been removed from DNR's list. He would
address the issue on a later slide.
Representative Hannan asked for a definition of Brookian
age plays.
Mr. Peltier responded that the term [Brookian age plays]
had to do with the age of the sands. He detailed that it
was after the age of the dinosaurs and before the current
Holocene epoch. He explained that the rock was relatively
new and not as deep as the Ivishak at Prudhoe Bay or the
Kuparuk sands. He remarked that it was similar to Schrader
Bluff sands. He noted the Brookian age plays were located
below the permafrost but were not as old as the areas the
traditional oil fields had been deposited.
2:07:43 PM
Mr. Peltier turned to slide 6 titled "FY2023 Summary: North
Slope." He provided highlights comparing FY 22 and FY 23.
He reported that DNR expected fields to naturally decline.
He detailed that Prudhoe Bay and the Kuparuk River Unit
(KRU) fields were some of the largest in North America and
had been online for decades. He pointed to a chart on the
top right of the slide showing North Slope daily production
from FY 17 to FY 23. The chart showed a decline from
526,389 barrels of oil per day in FY 17 to 479,380 in FY
23; however, operators continued to invest capital to
maintain the fields. He highlighted there had been a
production increase in FY 23 compared to FY 22. In total,
the North Slope produced about 2,890 barrels per day in FY
23 compared to FY 22.
Mr. Peltier addressed a waterfall chart on the lower left
of slide 6 reflecting production changes across North Slope
fields from FY 22 to FY 23. He explained that the chart
began at zero with a waterfall from left to right,
reflecting a cumulative difference that built on one or the
other. He noted that the fields [shown on the x-axis] were
organized alphabetically and he had input decreases first
followed by the increases. He pointed to Prudhoe Bay that
ended at about 2,890 barrels of oil per day, which was the
nature of how the waterfall chart worked. He reviewed the
chart beginning with the Badami well, which had seen a
decrease in FY 23 from FY 22 because its best producing
well had been offline for a substantial part of the fiscal
year. He noted the well had come back online in May 2023
and was still operating. There had been natural decline in
the Colville River and Kuparuk River Units, which was
offset by development drilling. He reported that drilling
had been returning to the North Slope after the COVID-19
pandemic when there had been a drilling shutdown. He added
that decline was being mitigated with continued investment.
There was natural reservoir decline with the Endicott and
Northstar fields. The Point Thomson field experienced
decline because its single production well was suffering
technical challenges continuing into FY 24.
Mr. Peltier addressed the increases in North Slope
production between FY 22 and FY 23 on slide 6. The Greater
Mooses Tooth Unit (GMT2) had a new pad put in development,
which had resulted in new oil beginning in November 2021.
There was more drilling needed over the years and continued
activity played out in FY 23 resulting in a relatively
large increase due to new resources. Production growth on
the Milne Point, Nikaitchuq and Oooguruk Units pertained to
infill drilling targets and rig workover efforts. Prudhoe
Bay had seen production growth from improved facility
reliability and increased gas throughput in the winter. He
explained that the operator Hilcorp was able to keep the
facilities online and running for a good part of the year,
which led to a year-over-year production increase.
2:12:04 PM
Mr. Peltier turned to slide 7 titled "Status Update of Key
Future Projects: North Slope." He noted that the project
list was not exhaustive and included five projects DNR saw
as material to the North Slope's production future. He
highlighted that Pikka and Willow were large new fields
with combined capital investment exceeding $10 billion.
Additionally, there were new pads under development or pads
under expansion for additional production within existing
fields. He cited examples including Narwhal CD8 in the
Colvill River Unit (CRU), Raven Pad (R Pad) within the
Milne Point Unit (MPU), and the Nuna-Torok Pad within the
Kuparuk River Unit.
Mr. Peltier addressed the current status and expected
production rates of the five projects shown on slide 7. He
would review the status in January 2023, the current status
as of January 2024, and the production rate estimates for
each of the projects. He began with Pikka, which was
operated by Santos and located on state land. In 2023, FID
had been approved for Pikka Phase 1 and first oil was
anticipated in 2026. As of January 2024, project
construction and drilling activities were ongoing and
project first oil was anticipated in the second quarter of
2026. The peak design capacity and rate remained at 80,000
barrels per day.
Mr. Peltier moved to the Willow project on slide 7. Willow
was operated by ConocoPhillips and located on federal
lands. In January 2023, the project had been awaiting a
record of decision (ROD) from the Bureau of Land Management
(BLM) on a supplemental environmental impact statement
(EIS). He relayed that ConocoPhillips had stated that the
FID could not be made prior to the completion of the ROD
and if first oil happened, it would be six years after FID.
He reported that the BLM issued the ROD on the supplemental
EIS in 2023 and ConocoPhillips started construction
activity in April 2023. Throughout the year there had been
some legal uncertainties, which had been largely resolved
by November 2023 and Conoco had announced FID in December
2023. The timeline remained at six years after FID and
first oil was expected in 2029. The peak rate for the
project was expected to be 180,000 barrels per day.
2:15:18 PM
Mr. Peltier discussed the CRU Narwhal CD8 (CD8) project on
slide 7. He relayed that in January 2023, CD8 was expected
to start production in early 2028 pending alignment with
external and internal stakeholders. He noted the date came
rd
out of the 23 plan of development (POD) submitted in 2021.
As of January 2024, CD8 was expected to have its first oil
th
in 2030 according to the 25 CRU POD. The project was still
awaiting stakeholder alignment, permitting, and internal
studies and alignment. The peak estimate for the project
was around 32,000 barrels per day.
Mr. Peltier reviewed the status of the MPU Raven Pad (R
Pad). In January 2023, Hilcorp had recently applied for
approval to construct the R Pad project. Over the past 12
months DNR granted approval for R Pad construction to begin
in February 2023 and construction activities were ongoing.
He reported the pad was expected to be online within the
next two years. The DNR peak production estimate was 10,000
barrels per day. He noted that the operator, Milne Point,
had developed the M Pad or Moose Pad in 2018. He detailed
that the R Pad and M Pad resource base was very similar,
and the production expectations were the same for the two
projects.
Mr. Peltier addressed the KRU Nuna-Torok project located on
state lands (last project on slide 7). In January 2023,
ConocoPhillips had still been doing testing with an
additional injector/producer pair planned. In 2023, the
operator saw enough to approve the funding for a 3T pad
expansion. Production from the project was expected in 2025
and peak production was expected to be 20,000 barrels per
day.
Mr. Peltier summarized slide 7. He explained that the top
two projects [Pikka and Willow] would bring significant
investment to Alaska in the medium and far-term, while the
last two [Raven Pad and Nuna-Torok] would bring significant
oil production benefit in the near-term.
2:18:04 PM
AT EASE
2:18:36 PM
RECONVENED
Representative Stapp remarked that the peak production for
the Willow project was expected to be 180,000 barrels per
day despite the fact that three pads were approved instead
of five. He asked for verification that the number of pads
had not changed the production projections.
Mr. Peltier responded that the supplemental EIS included a
table of production rates. He noted that the absence of the
fourth pad decreased the total volume for the project;
however, the peak rate was estimated to be the same.
Representative Stapp observed that in 2022 the peak rate
for the Nuna-Torok project was projected at 25,000 barrels
per day. He remarked on the reduction to 20,000 barrels per
day. He asked what had caused the change.
Mr. Peltier answered that the Nuna-Torok project included
an expansion on 3T pad. He explained that the Nuna-Torok
formation was also accessible from the 3S pad on the
Kuparuk River Unit. He elaborated that because some of the
rate [of production] was accessible from an existing pad,
DNR had removed a portion from the part of the project
highlighted on slide 7. The change had naturally reduced
the [projected production] rate.
Representative Hannan referenced the Pikka project and the
[anticipation for first oil in the] second quarter of 2026.
She noted a litigation issue related to access for
development. She asked if the first oil anticipation
changed depending on how the litigation played out. She
asked if the information shown on slide 7 accounted for the
possibility of having to build a new road.
Commissioner Boyle answered that the outcome of the
litigation was not a factor in the anticipated first oil
date for Pikka. The project was anticipated to use the
roads it was using currently during the development of the
fields. More impactful for the timing of the development of
the Pikka field was the ability to build out the pipeline
structure within the next two winter seasons. He stated if
there was long tundra travel and winter season in the
current year and if more of the pipeline work was
completed, the start date may move up.
2:22:34 PM
Representative Josephson asked for verification that
because of net operating losses and carried forward lease
expenditures, the Willow and Pikka projects would be a boon
to the state treasury later in the current decade because
the credits would offset revenue the state would otherwise
have.
Commissioner Boyle prefaced his answer by noting that DNR
was not the Department of Revenue. He stated his
understanding that revenues coming to the state from Pikka
occurred nearly immediately because Santos was not a
current operator and was not currently paying production
tax to the state. As soon as Pikka began production there
would be royalty payments accruing to the state treasury.
He relayed that the Willow project was located on federal
land within NPRA and the royalty rates were split with 50
percent accruing to the federal government and the other 50
percent was dedicated to the North Slope Impact Grant Fund
administered by the Department of Commerce, Community and
Economic Development. He explained that the money was
earmarked for the five villages within the NPRA most
impacted by the development. The state did not receive a
direct royalty share. He added that the current
operator/producer ConocoPhillips would have the opportunity
to offset some of its construction costs with its existing
production taxes, which would have an impact on cashflow
timing for the state in the earlier years. He noted that in
later years it would still provide a net overall revenue
benefit to the state.
2:25:40 PM
Representative Galvin asked if the department had heard
from companies on any unique development challenges in the
particular fields that may result in increased development
costs. She highlighted road access and difficult rocks as
examples.
Commissioner Boyle replied that the Pikka and Willow
projects were the first developments of the Nanushuk
formation. He believed the companies had been working to
get as efficient recovery as possible out of the
reservoirs. He noted that he was not a geologist or
petroleum engineer. He stated his understanding as a
layperson that the formation was different from Prudhoe Bay
and Kuparuk and required more enhanced oil recovery
techniques such as gas or water injection to help stimulate
the reservoirs and sweep the rock to get as much oil and
gas molecules as possible. He explained that it added an
element of cost and complexity to understand how the
geologic systems would react to the techniques. He
elaborated that Pikka was advantaged by its location near
existing roads and infrastructure. Willow was well
attenuated from the central facilities, pipelines, and
infrastructure on the North Slope, which resulted in
increased cost and complexity logistically (i.e., the need
to build a pipeline to transport its oil).
Mr. Peltier advanced to slide 8 titled "FY2023 Summary:
Cook Inlet." He relayed that Cook Inlet had been online
since 1958 and due to its age, fields were expected to
broadly decline year-on-year. He pointed to a chart on the
top right of the slide reflecting Cook Inlet daily oil
production. The chart showed fiscal year average daily
production ranging from zero to 20,000 barrels per day for
FY 17 to FY 23. He highlighted the peak rate at 15,653
barrels per day in FY 18, which had declined through FY 23
to 9,033. The decrease from FY 22 to FY 23 was roughly 4
percent or 370 barrels per day. He highlighted that oil
from the Cook Inlet basin was critical to supplying instate
refineries. Fuel generated from instate refineries was used
for various purposes including aviation fuels for the State
of Alaska.
Mr. Peltier reviewed a waterfall chart showing average
yearly production changes (in barrels of oil per day)
across Cook Inlet assets on the lower left of slide 8. He
explained that the chart was alphabetically ordered on
decreases and alphabetically ordered on increases. Overall,
the Cook Inlet basin was experiencing natural decline. He
highlighted Beaver Creek, Granite Point, Hansen, McArthur
River, and Swanson River units were all experiencing
natural decline. He remarked that the year-on-year declines
were expected from a mature basin. He noted that the
Redoubt Shoal unit experienced natural decline, which was
partially offset by some rate adding well work.
Additionally, well work had been done at the West McArthur
River unit, which resulted in an increased rate year-on-
year.
2:30:56 PM
Mr. Peltier turned to slide 10 titled "DNR Forecast
Process: Projects/Pools Included in Forecast." He pointed
out that the previous year DNR had made its capital
drilling program more explicit in its forecasting
methodology approach. He noted there was no changes from
the methodology between the fall 2023 forecast and the
present day.
Co-Chair Johnson remarked that daily production was down
significantly less than she expected. She was trying to
recall DNR's production forecast from the prior year.
Mr. Peltier replied that slide 15 showed the spring 2023
forecast. He asked to address the question at that point in
the presentation.
Mr. Peltier addressed the DNR production forecast process
on slide 10. The process began with the various pools and
projects. He explained that DNR did an annual bottoms-up
decline curve forecast for all producing pools (everything
publicly available in the Alaska Oil and Gas Conservation
Commission (AOGCC) database as of June 30). There were 39
pools in the current forecast across the North Slope and
Cook Inlet. The forecast included one additional pool over
the previous year because ConocoPhillips had a new pool
the Coyote formation in the Kuparuk River Unit - the
previous year that had not been included in the forecast.
He noted that DNR treated the Cook Inlet basin as one pool
in the data it provided DOR. The Division of Oil and Gas
refined the forecast after conducting in-person and in-
writing interviews with operators arranged through DOR.
Operators provided information on development plans over
the next ten years including activity levels and major
projects they intended to invest in.
Mr. Peltier continued to review the forecast process on
slide 10. The information provided by operators enabled the
department to find 15 additional under development/under
evaluation projects to finish building the forecast. The
forecasts used confidential information from operators,
which could not be shared. He explained that major projects
were not necessarily in existing fields with existing pools
and a track record of production history; therefore, it was
necessary to adjust them for scope and chance of occurrence
with a range of start dates. He used Pikka as an example
and explained that DNR used a start date range from 2025 to
2027.
2:34:40 PM
Mr. Peltier turned to slide 11 titled "Categories of
Production: Ongoing/Current vs Future Production." The
first category was current production (CP), which included
ongoing production from existing fields. He detailed that
any wells producing on or before June 30, 2023, were part
of the current production category. The current production
forecast considered expected well and facility uptime.
Additionally, DNR verified that operators would continue to
maintain base production and that reservoir management
practices would be consistent through the forecast period
to avoid major surprises in the current production
forecasts.
Mr. Peltier reviewed the projects under development (UD)
and projects under evaluation (UE) category on the bottom
of slide 11. The category pertained to new production
projects requiring new investment including new wells on
existing fields or new projects. He noted there was always
uncertainty around how future wells would perform and about
how many wells may get drilled (including both infill
drilling and future projects) when looking at a 10-year
timeframe. He explained that anything occurring within the
next 12 months was considered under development and
anything beyond that timeframe was under evaluation. For
example, in January 2026 the Pikka project would move to
the under development category, assuming the field was not
already online and producing. He noted there was
significant timing uncertainty associated with project
timing. He highlighted economic and regulatory risks and
remarked that some projects were canceled or continued to
get deferred; therefore, DNR built in a risk profile for
each individual project. The forecast included the
summation of all projects and how it worked out materially.
2:37:06 PM
Mr. Peltier turned to slide 12 titled "Major Projects Under
Evaluation (UE) Considered in Fall 2023 Forecast." The
slide included a map of the project locations across the
North Slope. He noted the slide included the large projects
incorporated into the fall 2023 forecast. He highlighted
that none of the projects were online by June 30, 2023, and
none were expected to be online until at least 2025. He
added that the projects on the slide had a higher risk
factor than currently producing pools and a higher risk
factor than for infill drilling. Additionally, the projects
were known discoveries with identifiable operators that
required major investments to bring online.
Mr. Peltier highlighted projects on the map moving west to
east. He began with the Willow project operated by
ConocoPhillips and located on federal land. Next was the
Colville River Unit CD8 pad located on state land. Followed
by a number of Santos operated projects targeting the
Nanushuk Brookian age plays including Horseshoe Stirrup,
Pikka, Pikka Phase 2, and Quokka/Mitquq. Adjacent to the
Santos projects was the Mustang project, acquired by Finnex
from Alaska Industrial Development and Export Authority
(AIDEA) in December 2023. Next were the Nuna-Torok and MPU
Raven Pad projects. Just south of Prudhoe Bay was the Theta
West, Talitha, and Alkaid projects operated by Great Bear
Pantheon. Next was the Liberty unit located on federal
coastal land operated by Hilcorp. The two most eastern
projects were the Point Thomson expansion operated by
Hilcorp and the Sourdough project operated by Jade Energy,
both located in the Point Thomson Unit. He noted there were
two projects included on the map the previous year that
were not included on the present slide: Smith Bay and
Umiat. He detailed that Smith Bay would have been far to
the west and north offshore (the leases were highlighted in
blue on the map on slide 12). The project would have
required the developer to go through substantial federal
acreage in some sensitive areas and DNR did not see a
realistic option for getting the project online within a
10-year timeframe. The project continued to be on DNR's
watchlist. Additionally, DNR had removed the Umiat project
(indicated on the map by a green box just off of federal
acreage on the south) from its forecast because it did not
see a realistic way to get the project online within the
next 10 years.
Representative Tomaszewski referenced Pikka Phase 1 that
was projected to generate 80,000 barrels per day. He asked
if Phase 2 was also projected to generate 80,000 barrels
per day. He asked for verification that there were four
phases. He asked about a timeframe on the second phase.
Mr. Peltier responded that he could not recall whether
Pikka Phase 2 was projected to generate 40,000 or 80,000
barrels per day. He confirmed there were a number of
phases. He deferred to a colleague for additional
information.
2:40:54 PM
DEREK NOTTINGHAM, DIRECTOR, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, replied that the
department could follow up with the information. He
believed that the maximum volume from Pikka and its
additional phases was roughly 120,000 barrels per day. The
additional phases would come in and fill the facility
capacity over time.
Representative Tomaszewski asked for verification that Mr.
Nottingham thought the expected production was 120,000
barrels per day.
Mr. Nottingham confirmed he believed the number was around
120,000 barrels per day.
Mr. Peltier turned to slide 14 titled "Fall 2023: North
Slope Annualized Forecast." He highlighted that DNR
forecast FY 24 average annualized daily statewide
production at 478,000 barrels of oil per day. The
production forecast for the North Slope was 470,000 for FY
24. The low range was 422,000 barrels per day and the high
range was 519,000 barrels per day. He explained that DNR's
long-term forecast reliability was gauged by a general
comparison between the DNR and operators' forecasts. He
added that DNR built its forecasts from the bottom up and
did not use the operators' forecasts. He elaborated that
DNR finalized its forecast prior to looking at the
operators' forecast. He remarked it was good to see
relative consistency in FY 24 even with a blind approach on
forecast development.
Mr. Peltier continued to review slide 14. He noted that
DNR's forecast included projects [operators' forecasts did
not], which accounted for the projected growth over time.
The DNR forecast for North Slope production climbed towards
630,000 barrels of oil per day by year 10. He pointed out
that DNR's forecast assumed that operators' plans and other
project drivers remain unchanged. He explained that if
there was a major change in investment on the North Slope
positive or negative it could yield a dramatically
different forecast.
2:43:54 PM
Mr. Peltier turned to slide 15 titled "Fall 2023: AK
Statewide Annualized Forecast (Expected Case with
Production Categories)." The chart on the left showed the
fall 2023 production forecast for all production
categories. The blue portion of the chart reflected
currently producing wells as of June 30, 2023. The orange
portion of the chart reflected the next 12 months of
expected infill drilling and showed the benefit within
existing fields including Prudhoe Bay, KRU, and CRU. He
noted the substantial development within the existing
fields. The grey portion of the slide reflected projects
under evaluation: any capital in the 13+ month timeframe
over the next 10 years.
Mr. Peltier answered an earlier question by Co-Chair
Johnson about the [production] difference in 2024. He
stated that the spring 2023 forecast included 10 years of
data beginning in FY 23 and the chart naturally cut off in
FY 32, which was the reason for the difference. He
elaborated that in FY 24, the difference was about 20,000
barrels of oil per day. He highlighted that one of the big
differences was that last year, the NPRA production area
forecast had a difference of about 15,000 barrels of oil
per day in 2024. He explained that the difference came from
DNR's expectations of how the NPRA would produce versus how
it did produce. He expounded that it was a relatively new
field with new formations being targeted; therefore, DNR
did not necessarily have a good track record on how the
areas would perform. He noted that unfortunately production
had come in significantly below DNR's expectations. He
noted the gap was reflected in the difference between the
prior year's forecast and the forecast for the current
year.
2:46:17 PM
Co-Chair Johnson looked at FY 25 and FY 26 and observed
there continued to be a gap.
Mr. Peltier agreed and explained it was cumulative.
Co-Chair Johnson asked if it was a similar situation.
Mr. Peltier agreed. He elaborated that the production in
question pertained to the NPRA area. He stated that it had
not met expectations for the current year and would not
start meeting expectations in future years.
Co-Chair Johnson remarked that 20,000 barrels per day did
not seem that substantial, but when talking about the
budget, it was substantial over time.
Mr. Peltier pointed out that there was a higher chance of
occurrence for a number of projects. He detailed that there
was more confidence around Willow because legal
uncertainties had been diminished. Additionally, there was
more confidence associated with the Pikka Phase 2 and
Quokka projects operated by Santos. He highlighted that at
the end of the forecast period there was increased
production in total even compared to the spring of 2023.
The last datapoint for the spring 2023 forecast had about
543,000 barrels of oil per day, whereas the current
forecast for the same datapoint was 609,000 (a difference
of about 66,000 barrels per day). He noted that the
forecast built to the 633,000 barrels of oil per day
expectation in FY 33.
Mr. Peltier pointed to the chart on the right of slide 15
showing the importance of the new capital coming into the
state. The chart ranged from zero to 700,000 barrels of oil
per day and showed how material the new production was from
the various 15 projects highlighted on previous slides to
the State of Alaksa and the North Slope.
2:48:36 PM
Mr. Peltier provided a fall 2023 production forecast
summary on slide 16. He relayed that DNR did the best it
could to forecast using the best information available to
DNR and DOR. The department generated the production
outlooks twice a year in the fall and spring and did
its best to get the most up to date information from
operators. The department used the State of Alaska's
official updated price outlook at the time it made the
forecast. The goal was to generate an accurate near-term
and realistic long-term forecast. The department's fall
2023 outlook showed near-term production at around 480,000
to 500,000 barrels of oil per day in the first few years,
increasing towards 630,000 barrels of oil per day towards
the end of the 10-year outlook. He relayed that production
estimates from projects under evaluation accounted for
several technical and commercial factors and project
execution risks to account for uncertainty on individual
project production delivery.
Mr. Peltier relayed that the DNR team worked hard every
year to deliver a robust production forecast. On behalf of
the team, he expressed gratitude for the opportunity to
present the forecast to the committee.
Representative Ortiz asked whether the department had
looked back to 2013 to see what its forecast had been for
2023. He wondered whether the department had been able to
determine whether its forecasting was improving or
remaining static. He asked if there were too many variables
to make a valuable comparison.
2:51:00 PM
Mr. Peltier could not tell the committee about 2013
specifically because his team had taken over the process in
2016. He relayed that the forecast had been within the plus
or minus 5 percent every year since then. He deferred to a
colleague for additional information.
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, replied that in the 2016 timeframe, DNR brought
the function in-house for efficiency to save money and
apply some processes DNR believed to be more conservative
and appropriate. The department would be happy to do a
comparison chart of what the 2013 forecast showed compared
to the present. He thought it was illustrative about some
of the new developments and how they had progressed over
the past 10 years. He added that DNR was trying to learn
from its past efforts and at times mistakes.
Representative Ortiz asked if the production forecast was
conducted by DOR or another party prior to 2016.
Mr. Peltier replied he was under the impression it was a
private contractor.
Co-Chair Johnson thanked the presenters and reviewed the
schedule for the following day.
ADJOURNMENT
2:53:25 PM
The meeting was adjourned at 2:53 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2024 01 17 HFIN DNR Fall 2023 Production Forecast Presentation.pdf |
HFIN 1/17/2024 1:30:00 PM |
DNR Production Forecast |
| 011724 Cook Inlet Oil and Gas Activity Map.pdf |
HFIN 1/17/2024 1:30:00 PM |
|
| 011724 Cook Inlet Working Interest Ownership Map.pdf |
HFIN 1/17/2024 1:30:00 PM |
|
| 011724 North Slope Oil and Gas Activity Map.pdf |
HFIN 1/17/2024 1:30:00 PM |
|
| 011724 North Slope Working Interest Ownership Map.pdf |
HFIN 1/17/2024 1:30:00 PM |