Legislature(2021 - 2022)ADAMS 519
01/19/2022 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Presentation: Department of Natural Resources Production Forecast | |
| Presentation: Fall 2021 Revenue Forecast | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
HOUSE FINANCE COMMITTEE
January 19, 2022
1:32 p.m.
1:32:21 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 1:32 p.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Kelly Merrick, Co-Chair
Representative Dan Ortiz, Vice-Chair
Representative Ben Carpenter
Representative Bryce Edgmon
Representative DeLena Johnson
Representative Andy Josephson
Representative Bart LeBon
Representative Sara Rasmussen (via teleconference)
Representative Steve Thompson
Representative Adam Wool
MEMBERS ABSENT
None
ALSO PRESENT
Maduabuchi Pascal Umekwe, PhD, Commercial Analyst, Division
of Oil and Gas, Department of Natural Resources; John
Crowther, Deputy Commissioner, Department of Natural
Resources; Dan Stickel, Chief Economist, Economic Research
Group, Tax Division, Department of Revenue; Senator Bert
Stedman; Senator Click Bishop; Senator Natasha von Imhof;
Senator Bill Wielechowski; Senator Donny Olson.
PRESENT VIA TELECONFERENCE
Corri Feige, Commissioner, Department of Natural Resources.
Colleen Glover, Director, Tax Division, Department of
Revenue.
SUMMARY
PRESENTATION: DEPARTMENT OF NATURAL RESOURCES PRODUCTION
FORECAST
PRESENTATION: FALL 2021 REVENUE FORECAST
Co-Chair Foster relayed that the committee would be
following COVID-19 mitigation policies in effect. He
reviewed the meeting agenda. He recognized Senate Finance
Committee members including Co-Chair Bert Stedman and Co-
Chair Click Bishop in the room.
SENATOR BERT STEDMAN, offed a gift of appreciation on
behalf of the Senate Finance Committee to the House Finance
Committee for all of its hard work over the past several
years. He held up a symbolic check in the amount of $4.943
billion to the principal of the Permanent Fund on behalf of
future generations of all Alaskans. He held up a second
symbolic check for $4 billion dated July 21, 2021, for
future generations of all Alaskans. He offered one of the
two checks for the House Finance Committee to display. The
other check would be displayed in the Senate Finance
Committee room. He stated the committees had worked
together to save approximately 10 percent of the entire
Permanent Fund for future generations. He stated that in 30
to 40 years the $8.9 billion would grow to "stacks of
billions."
Co-Chair Foster asked for any comments from members.
Representative LeBon stated that any bank would honor the
checks. He asked to accept the $4 billion check.
Co-Chair Foster suggested accepting the $4.9 billion check.
1:37:49 PM
Representative Edgmon thanked the Senate Finance Committee
for its growing commitment to growing the Permanent Fund.
He remarked that Alaska was the only state with an
endowment. He lauded the committee for holding the line in
terms of growing the fund. He appreciated the gesture. He
remarked there was lightheartedness in the gesture, but the
underlying message was serious.
Co-Chair Merrick thanked the Senate Finance Committee and
appreciated working collectively with the committee in the
past couple of years. She believed it was an example that
working collaboratively resulted in achieving great things.
Co-Chair Foster stated he was up for taking either check.
Representative LeBon concurred with Co-Chair Foster's
choice.
Representative Wool thanked Senate Finance for all of its
work. He asked for the larger check.
Co-Chair Foster requested to receive the $4.9 billion
[symbolic] check.
Co-Chair Stedman thanked the committee.
Co-Chair Foster thanked the Senate Finance Committee.
^Presentation: Department of Natural Resources Production
Forecast
1:40:05 PM
CORRI FEIGE, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES
(via teleconference), echoed thanks to both finance
committees for their commitment to growing the Permanent
Fund for future generations of Alaskans. She believed it
was germane the [symbolic] checks were presented on the
frontend of the 2021 production forecast because of the
relationship to royalty revenues directed into the
Permanent Fund. She introduced Department of Natural
Resources (DNR) staff. She provided opening remarks with a
prepared statement:
Looking back, in 2021, the oil sector recovery from
the chaos and extreme price and demand fluctuations
that were so prevalent during 2020 and the peak of the
global pandemic, the International Energy Agency notes
the demand has now been ahead of supply since the
th
third quarter of 2020 through the 4 quarter of 2021.
Year 2022 is looking like we will see higher and more
stable prices enduring.
Members of the committee will probably know that
Alaska North Slope Crude closed just above $89/ barrel
yesterday. 2022 will likely see global rebalancing and
continued strong prices, though that can change very
quickly in this rather uncertain and highly
politically charged global environment. At the most
th
recent meting of the OPEC Plus on January 4, those
member nations announced that they planned to continue
to their restrained monthly increase in supply;
however, some analysts worry that this restrained
approach indicates that the idle capacity in some of
these nations is going to be difficult to return to
production and it is that market dynamic that has
driven prices higher over the last couple of weeks.
Stronger and more stable prices and increasing demand
is good for Alaska's industry. Though when the current
political climate, companies across the petroleum
sector and especially those operating in Alaska, face
significant headwinds, there is pressure on all
companies to exhibit capital discipline and increase
shareholder profits and returns and that combined with
climate activism and energy transition dynamics is
resulting in financial barriers and slower
reinvestment in the sector.
The times are uncertain. Alaska's operators are taking
full advantage of the price rise and near-term
stability to continue to capture more efficiency,
value, and production from the existing assets, and
that is resulting in somewhat flattened decline rates
across many of Alaska's major North Slope fields.
1:44:20 PM
MADUABUCHI PASCAL UMEKWE, PHD, COMMERCIAL ANALYST, DIVISION
OF OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES, provided a
PowerPoint presentation titled "Fall 2021 Production
Forecast," dated January 19, 2022. He addressed elaborated
on comments made by Commissioner Feige. He remarked it had
been an interesting 12 to 24 months with [oil] prices
swinging between below zero and the current numbers. He
intended to discuss the production outlook throughout the
presentation. He noted the work had been conducted within
the Division of Oil and Gas by a team of geologists,
engineers, and commercial analysts, who worked with the
assets on a daily basis. The forecast had been done in
close collaboration with the Department of Revenue (DOR).
The presentation included a review of FY 21, the DNR
production forecasting approach, and the fall 2021 forecast
results.
Mr. Umekwe advanced to the outlook for FY 21 production on
slide 4, which DNR had forecast in fall 2020. He pointed to
a black bar reflecting actual production in a bar chart on
the lower right of the slide. He noted the gray bars in the
extremes [to the far left and far right of the chart]
represented the high and low production ranges generated by
DNR, while the gray bar to the immediate left of the black
bar reflected DNR's expected case. The blue bar reflected
an aggregate look at what different operators thought. He
reported that the actual production came within DNR's
forecasted range and was about 5 percent above the
department's expected case.
Mr. Umekwe touched on factors the department believed would
shape the landscape for existing and upcoming projects.
Factors included energy transition and strong
environmental, social, and governance issues that impact
the way companies looked at capital in the Arctic. He
referenced statements made on the factors in the media and
from Wall Street. He remarked that companies in Alaska were
aware of energy transition and were taking steps to address
their strategy and response. He noted there were multiple
options available to companies and each company approached
the transition in its own way, picking options that matched
their long-term strategy.
Mr. Umekwe stated that COVID-19 had really impacted the
numbers and overall project climate. He remarked that the
impacts beginning in 2020 continued to shape the way
companies interacted and managed fields and redevelopment
efforts.
1:48:46 PM
Mr. Umekwe moved to slide 5 and addressed "FY 2021 Summary:
North Slope." He considered what was expected from oil and
gas fields that were past the point where significant
development was occurring. He pointed to a chart on the
bottom right showing production changes across North Slope
assets and explained that he largely expected assets to
show as red because fields generally declined on a year to
year basis. He added that a green bar indicated that
something was happening with the assets. He remarked it
took a lot to stabilize decline let alone increase
production in a given asset.
Mr. Umekwe continued to address slide 5. The slide showed
that North Slope production from FY 20 to FY 21 increased
by 2 percent. The increase included activities in the
Greater Prudhoe Bay Unit (GPBU) due to well/facility
optimization efforts. He noted that when looking at
historical data, it would be necessary to go back to 2005
to see facilities being run at their current level. He
noted the prior operator set the groundwork for the
optimization efforts and the current operator was moving
their own strategy of cost reduction and looking across the
fields for small opportunities. Additionally, the Milne
Point Unit (MPU) had seen a 20 percent increase in
production due to consistent drilling efforts. He relayed
ExxonMobil's efforts, which had been taken over by Hilcorp,
had resulted in a 40 percent growth in the Point Thomson
Unit (PTU) due to improved facility reliability.
Mr. Umekwe discussed decreases in production on slide 5. He
reported that ConocoPhillips had held production at the
Kuparuk River Unit (KRU) essentially flat at FY 20 levels.
He noted there was a drop of 300 barrels, which was a
phenomenal feat. The Greater Mooses Tooth Unit 1 (GMT1) had
seen a 50 percent production drop due to persisting
reservoir challenges. He highlighted the presentation would
show good news for the asset resulting from the next phase
of development: GMT2. He highlighted that the absence of
drilling at Oooguruk since 2016 had led to declines shown
on the slide. He stated that overall, it was good to see
the growth in the amount that was being seen on the North
Slope. The first effort was to stabilize decline and add to
it.
1:52:47 PM
Co-Chair Foster noted that Representative Rasmussen was
online.
Mr. Umekwe moved to an FY 21 summary on Cook Inlet basin.
He highlighted the importance of the basin that produced
much supply for in-state refineries as well as yielding
revenues from royalty-in-kind sales. He stated that the
basin production had decreased by 22 percent or ~3,000
barrels of oil per day. Some of the decreases for the basin
included the Redoubt Shoal and McArthur River fields that
were taken offline at the height of the pandemic in June
2020 as a result of the pandemic-related oil crash. He
noted the two fields had been brought back online.
1:54:29 PM
Mr. Umekwe turned to slide 7 and showed a snapshot of some
of the North Slope projects that would be impacting the
outlook over the next two fiscal years. He listed the Fiord
nd
West Kuparuk, CD5 2 expansion, and the Narwhal projects.
He stated it was significant activity in the asset as the
operator continued to deepen portfolio projects. He
highlighted the first oil had been produced in the Narwhal
unit in December 2021. The plan was to drill about 12 wells
going forward, which would increase the amount of oil to a
peak of around 32,000 barrels of oil per day. The first oil
for the GMT2 project had been drilled in November 2021. He
detailed that the wells had not all been drilled but there
was consistent work to bring to its estimated level of
production of a peak of around 30,000 barrels per day.
Mr. Umekwe pointed out that production did not reach its
peak right from the beginning. He discussed the Pikka field
and noted a merger between Santos and Oil Search had been
completed and the FID [final investment decision] was
expected for phase 1 of the development. He noted phase 1
was expected to result in ~80,000 barrels per day.
Production was anticipated to increase in 40,0000 barrel
increments. He highlighted the Willow field and noted the
operator was working on issues highlighted in a court
decision. The project was expected to reach the second
record of decision by the end of 2022 with construction to
follow in the beginning of 2023.
1:57:31 PM
Co-Chair Foster noted that Vice-Chair Ortiz had joined the
meeting.
Representative Josephson asked about the Willow field on
the list shown on slide 7. He observed that the slide
appeared hopeful that corrections could be made, and the
project could move forward. He asked for the accuracy of
his statement. He asked if the department followed the
details of the litigation.
Mr. Umekwe answered that much of the information shown on
the slide was the publicly available information.
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, responded that DNR and the Department of Law
(DOL) had been following the litigation and remand from the
court. He detailed that the necessary record of decision
and approval from the Bureau of Land Management (BLM) was
back with BLM at present. He elaborated that DNR was
participating in the group reviewing the identified
deficiencies and corrections and supporting the federal
agency to try to accelerate the review for completion in a
timely way. The schedule shared with DNR would complete the
review in 2022 and would allow construction to proceed in
2023. He noted that the timelines were always aspirational;
however, the Willow timeline was incredibly important to
the state. He explained the department was working very
hard to do everything possible to support the federal
review to keep it on schedule.
Representative Wool asked if they were discussing the
Natural Petroleum Reserve-Alaska (NPRA) fields that were in
question. He looked at the estimate of 130,000 barrels of
oil per day. He asked if the ultimate projection from DNR
would include the 130,000 barrels per day.
Mr. Crowther answered that the Willow field was in the
federal leases within NPRA, while the Pikka project was
located on state leases near the boundary on state lands.
He verified that the numbers in the presentation reflected
the volumes [projected on slide 7] in the outyears.
2:00:11 PM
Representative Edgmon observed on slide 7 that the start of
production in phase 1 of the Pikka project was scheduled
for 2025 and a final investment decision was expected by
2024/2025. He asked if it was consistent with expectations
a year ago and factored in the high profile dispute between
Oil Search and ConocoPhillips in terms of construction
easement permits. He asked if the impediment still existed
and whether it had influenced the timeline for both phases.
Mr. Crowther replied it was DNR's understanding the Pikka
project was split from a single phase with a target of
120,000 barrels into two phases partially due to COVID-19
and a difficult period of low oil prices and tight market.
The first phase had a peak of 80,000 barrels per day that
may receive final investment decision in 2022. There would
be a second phase with a subsequent final investment
decision in the 2024 timeframe that would take total
production to the original target of ~120,000 barrels per
day. He relayed that DNR was very aware of the situation
and was speaking with both parties about how to resolve the
issues and enable development to proceed. He deferred to
Commissioner Feige for additional detail.
Commissioner Feige added that the Kuparuk River Unit needed
to be crossed to access the Pikka field and both
developments were state resources under state leases on
state lands. The state was very engaged in the process. It
was the state's desire to see the two parties come to a
commercial agreement, which would be the fastest path. She
elaborated it had always been the path that operators in
Alaska and other places had been able to travel in sharing
access across state lands. She relayed that the Pikka
development was the first time on the North Slope where the
operator and the owner of the field was not a working
interest owner in one of the other fields operating on the
North Slope. In the past, when third-party operators had
needed access to facilities or needed to cross other
producing fields, the parties had been able to come
together in a commercial arrangement usually because there
was oil processed through a facility or there was sharing
of some other facility. In the Pikka case, Oil Search
needed to construct its own seawater treatment plant to
Oliktok Point, which was the easement dispute referenced by
Representative Edgmon.
Commissioner Feige explained the new seawater treatment
plant was needed because of the chemistry required for
water to optimize oil recovery from Pikka. The chemistry of
the water coming out of the existing seawater treatment
plant owned by ConocoPhillips was not the exact chemistry
needed; therefore, Oil Search opted to construct its own
plant. It was the department's understanding that
ConocoPhillips would need to expand its seawater treatment
plant at Oliktok Point for the Willow project. She
explained it was not an area where the two companies could
share a commercial arrangement. The department was
currently working with both parties to encourage a
commercial arrangement for a long-term road use agreement
because access to the Pikka field required the Spine Road
crossing the Kuparuk River field. The department was very
engaged and was watching the timelines closely because it
was in the state's interest for Pikka to continue on the
stated timeline.
2:05:22 PM
Representative LeBon thanked the commissioner for the
summary. He asked if the state had the authority to mandate
a settlement if there was not a settlement of the agreement
between the two companies in a timely manner.
Commissioner Feige replied in the affirmative. She informed
the committee that none of the access provisions in any of
the leases or unit agreements were exclusive. The state
believed it had statutory provisions that would enable the
state to help the companies come to an agreement. The state
was hoping the parties came to a commercial arrangement on
their own because it would be the shortest timeline.
Mr. Umekwe moved on to discuss DNR's forecasting approach.
2:07:13 PM
Mr. Umekwe turned to slide 9 and addressed the DNR forecast
process including projects and pools within the forecast.
He relayed that the forecasting process typically began
with the public numbers published by the Alaska Oil and Gas
Conservation Commission (AOGCC). He explained DNR looked at
the pools online at a given date. He detailed that DNR did
projections for pools going into the future using an
industry norm. The department collaborated closely with the
DOR to discuss projects in detail and get its questions
answered. He relayed there were about 20 projects under
development, evaluation, and/or review such as Pikka,
Willow, and others. The department reviewed the projects
and talked with explorers to gain insight into any gaps the
department may have in its understanding of the projects.
He explained that future production from the projects was
adjusted and risked for scope of contribution, chance of
occurrence, and start date. He elaborated that typically
the expected rate was either exceeded or not met. He
pointed out it was difficult to have a forecast that was
100 percent accurate. He stated that the department's
approach was consistent over the years.
Mr. Umekwe turned to slide 10 and addressed categories of
production: ongoing/current vs future production. He began
with production from existing fields including Prudhoe Bay,
Kuparuk, and others. The department considered how
facilities were managed, how base production had been
maintained or managed, and the different enhanced oil
recovery techniques that had been applied to give a good
sense of future production. The department also considered
future production including projects under development
(planned to occur in the next fiscal year) and under
evaluation. He stated projects under evaluation typically
had substantial capital requirements and commerciality
risk.
2:10:54 PM
Mr. Umekwe advanced to slide 11 and addressed major
projects considered in the fall 2021 forecast. He provided
generalized characteristics. First, the projects included
were not online as of the end of FY 21. The projects
required significant investment to get started, they
involved known discoveries with identifiable operators, and
had higher risk factors. He pointed to a map on slide 11
and highlighted that yellow represented federal land, pink
reflected Native land, and blue reflected state land. He
pointed out that royalties the state took from the
different slices of land differed greatly. He elaborated
that the state received 100 percent of the royalties from
state land, while 50 percent of the royalties from the NPRA
area went to a firm handling the mitigation effects of
development. He relayed that the state received about 27
percent of the royalties generated from projects located
about three to six miles from the northern portion of the
state.
Mr. Umekwe relayed that all oil that went to the pipeline
helped the state in some way. He elaborated that it helped
other projects, reduced tariffs, and made other projects
more economic. He reiterated that the slice the state
received from the various locations differed. He relayed
that chapter 6 of the Revenue Sources Book addressed taxes
and royalties for different segments of land.
2:13:09 PM
Representative Edgmon asked about the optimism level going
forward. He referenced the oil price projection of $89 per
barrel, which would suggest the tide may be turning toward
more capital dollars being allocated to the North Slope. He
asked about the outlook relative to oil companies deciding
to put money into development.
Mr. Crowther answered there were competing factors. He
discussed that price drove investment in the sector both
nation and worldwide. He remarked that Alaska had been
blessed with some new understanding of its geology that
made the state comparatively more attractive. There was
tremendous potential in the eastern NPRA and western state
lands that had not existed five years back. He believed the
state had price and geology on its side, which were strong
factors supporting investment in Alaska. He highlighted
that there were sector-wide energy transition pressures
that were making competition for capital - even in a high-
price environment - very intense. He stated that the
department liked to be optimistic, but the situation
tempered the optimism. He shared that the commissioner had
been traveling to tell the department's story and
explaining why even as the sector-wide squeeze was taking
place, Alaska was the place to make low carbon intensity,
environmentally friendly, responsibly developed oil and
gas.
2:15:40 PM
Commissioner Feige believed it was a time of opportunity
for state lands on the North Slope. She stated that
companies on the NPRA and other federal lands around the
country were facing strong headwinds toward any kind of
lease activity and development. She elaborated that as
there had been during the Obama administration, there was a
reinvigorated interest in state lands, especially on the
North Slope. She detailed there were large tracks of
exploration acreage that had yet to be explored and tested
located east of the haul road that were a continuation of
the Nanushuk or Brookian play type, which was one of the
hottest play types in the world. She shared that department
members would attend the upcoming American Petroleum Expo
to present and meet with industry. The department heard
repeatedly that the Brookian plan or Nanushuk formation was
shallow, onshore, and in large volumes. She highlighted
that its location on state lands was another positive
aspect.
Commissioner Feige shared that she and the DOR commissioner
had been meeting with capital providers across the country
(in Houston and New York) and were highlighting that
Environment, Society and Governance (ESG) was not just
something new to Alaska. She continued that ESG had become
trendy in the past year or so because of the change in the
federal administration. She highlighted that the way Alaska
leased its lands, captured revenues, and turned the
revenues around into the Permanent Fund, into a dividend,
and into taxes that went directly to local communities for
schools, and new hospitals in Barrow, fell under the ESG
box. She stressed that ESG was not a new initiative for
Alaska, "it was in the DNA of how we do our business here"
and was in Alaska's statutes and constitution. She pointed
out that Alaska had anti-wasting statutes that prohibited
the venting of natural gas, something that separated Alaska
from places like Texas and the Permian Basin or North
Dakota and the Bakken where venting of natural gas was
commonplace.
Commissioner Feige believed Alaska was positioned very
well. Alaska faced some headwinds in ensuring it could
bring capital to operators that were working and investing
in the state. The state was doing its part to ensure the
capital was available. While at the same time, the
companies were working together to reduce their emissions
at existing operations. The companies were making certain
they were doing good well work and did not have venting or
"fugitive emissions." She summarized there was work to do
and the path was not easy, but she believed it was an
opportunity and there was reason to be optimistic.
2:19:36 PM
Representative Wool referenced testimony that the high
[oil] price regime was attractive to investors. He
highlighted that when price went up, producers (especially
fracking, Permian Basin and other) wanted to produce, which
caused supply to increase and price to go down. He stated
it was a self-regulating cycle. He asked if the cycle was
expected. He asked if there was a price point worked into
projections at which there would be less development and
production (if the price dropped below a certain number).
Mr. Umekwe confirmed that price regulated supply. He
explained that production in the U.S. followed high prices.
Once supply increased, prices should level off. The
expectation was for prices to remain in the $70 range and
higher in the current year declining to the high $60 range
or so in next year. He emphasized that many factors could
change pricing. He referenced the pandemic and noted it was
not possible to know what it would bring. He addressed how
sensitive projects were to price. He looked at projects on
slide 11 and explained that companies all had breakeven
prices needed to make the projects happen. He relayed that
very low prices would result in few projects, whereas high
prices sustained significant activity. He added that the
detail was incorporated into DNR's modeling.
2:22:22 PM
Mr. Umekwe turned to slide 13 and addressed the Fall 2021
North Slope annualized forecast. The department was
forecasting production to around 500,000 barrels per day.
Some of the production would come from Cook Inlet and the
majority would come from the North Slope. He reported that
production was around 493,000 barrels per day in FY 21 and
492,000 barrels per day in FY 22. The department aggregated
numbers provided by operators to determine whether the
department's long-term numbers fell within the same
ballpark. He pointed to a line graph on slide 13 and noted
the gray lines reflected DNR's projections (the top line
reflected the high case, and the bottom line reflected the
low case). The black line reflected the department's
expected case, and the blue line reflected the operators'
long-term outlook. The department did not aim to have the
black and blue lines match up because it would never be the
case; however, the goal was to ensure the lines fell within
the same ballpark. He pointed to the deviation shown
beginning in 2029 going forward and explained that DNR
included all 20 or so projects shown on the map [on slide
11], while the operators' information did not include
projects that had not yet been brought online. He
elaborated that the blue line excluded Pikka, Willow, and
other projects under development.
2:25:06 PM
Vice-Chair Ortiz asked for more detail on how the
department arrived at the black line representing the
expected case.
Mr. Umekwe replied there was uncertainty surrounding how
any project would perform for multiple reasons. For
example, an operator may expect 130,000 barrels of oil per
day; however, when the project actually happened, the
number could be higher or lower. He elaborated the more an
operator developed a reservoir, the better they understood
it. He furthered there was a high chance the actual
production numbers would not match initial projections. He
explained that DNR incorporated that possibility in its
numbers. He elaborated that for each given project, the
department forecasted a range of rates including a mean
case and a case where everything an operator anticipated
came to fruition.
Vice-Chair Ortiz looked at the blue line reflecting
operators' projections on slide 13. He understood the line
did not include some of the projects included in the DNR
projections. He asked if the blue line reflected
expectations that the projects would come to fruition and
become a part of production in future years. He observed
there was a significant difference in the line reflecting
the operators' long-term projections versus the
department's high case scenario.
Mr. Umekwe responded that operators provided numbers for
the projects with operational fields. The operators did not
include production from future fields such as Willow and
Pikka in the data used to generate the blue line. Once the
fields were added, the numbers would start to increase.
Vice-Chair Ortiz thought it seemed at some point the
operators would include the fields in their projections as
part of the forecasting process.
2:28:33 PM
Representative Wool looked at the DNR expected case
reflected by the black line on slide 13. He asked if the
black assumed all 20 projects mentioned earlier by the
department would come online.
Mr. Umekwe answered that the black line expected that some
projects would happen, and some would not. The black line
averaged across the range of possibilities.
Representative Wool asked for verification that the top
line showing over 1 million barrels per day assumed the
best case scenario.
Mr. Umekwe confirmed that the top line reflected the
department's optimistic case. He stated the department
would provide an updated chart showing production at just
under 1 million barrels per day around 2031. The top line
showed a case where many of the projects took place and
took place on time.
Representative Wool surmised it was statistically unlikely.
Mr. Umekwe replied that things would have to line up for
the scenario to occur.
Mr. Umekwe addressed slide 14 showing the fall 2021
statewide oil production forecast including categories of
production. He directed attention to a chart and explained
that some of the forecasted production came from assets
that were already producing (reflected in blue). The rust
colored portion of the chart reflected oil expected from
wells to be drilled in FY 22. He noted that the rust color
had been very small in the last forecast cycle because
projections had been much different at the time. The gray
portion of the chart reflected early stage projects under
evaluation and development. He pointed to the outyears on
the chart and noted an increased contribution from those
projects. He relayed the chart was based on a snapshot in
time based on factors that were subject to change including
operators' plans, commercial climate, and the fiscal
system.
2:32:19 PM
Mr. Umekwe turned to slide 15 and addressed the production
forecast summary. He relayed that DNR's work generating the
forecast was a collaboration with DOR. The department
worked to use the best information to generate the most
realistic outlook for the state. He highlighted that DNR's
fall 2021 outlook showed production of approximately
500,000 barrels per day in FY 22. Across the outlook
period, production was projected to exceed the figure at
times and fall below the figure at times. He added that
companies' responses to the pandemic, including how they
managed fields and what they deployed capital to, could add
to the level of uncertainty in the outlook period. He
turned to the last slide showing individuals who had worked
on the presentation.
Co-Chair Foster thanked the department for the
presentation.
2:34:03 PM
Co-Chair Foster introduced House Finance Committee staff.
2:34:43 PM
AT EASE
2:44:33 PM
RECONVENED
^Presentation: Fall 2021 Revenue Forecast
2:44:45 PM
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE, drew members' attention to
an email notification sent from the Department of Revenue
(DOR) earlier in the day. He explained that the
department's Economic Research Group did a monthly revenue
update for the current and next fiscal year. He detailed
that the information was used for internal purposes. He
elaborated that if the outlook for unrestricted revenue was
more than a 10 percent deviation from the official revenue
forecast, the department would begin sending out an email
to all interested parties. As of earlier in the day, the
updated futures market outlook for FY 22 suggested an oil
price of slightly over $80 per barrel compared to $75.72 in
the fall forecast. Likewise, the FY 23 outlook was just
over $78 per barrel versus $71 per barrel [in the fall
forecast]. The difference amounted to an expected
additional unrestricted general fund (UGF) revenue of $281
million for FY 22 and an additional $467 million for FY 23.
He noted the rest of the information reflected the official
fall revenue forecast released in early December.
Vice-Chair Ortiz asked if Mr. Stickel had said $400 million
for FY 23.
Mr. Stickel clarified the updated forecast was about $467
million above the fall forecast for FY 23.
2:48:15 PM
Mr. Stickel provided a PowerPoint presentation titled "Fall
2021 Forecast Presentation House Finance Committee," dated
January 19, 2022 (copy on file). He began on slide 2 of the
presentation and addressed the agenda. The presentation
included forecast background, economic indicators, and key
assumptions, in addition to the fall 2021 forecast and
petroleum forecast assumptions detail.
Representative Wool referenced the revenue information Mr.
Stickel had provided. He asked for the technical term of
the price and how frequently it would change.
Mr. Stickel answered that the forecast used for cash flow
analysis purposes was based on the futures market for Brent
Crude. He explained that Brent Crude was trading any day
markets were open. The Economic Research Group looked at
the prices once a month to prepare a cash flow update for
internal purposes, which would be the basis for the
notifications the department would send out going forward.
Representative Wool asked if it was a daily price or
average over the month.
Mr. Stickel answered that the department published a daily
price, and the futures market prices were monthly.
2:50:31 PM
Mr. Stickel turned to slide 4 and provided background
information on the fall revenue forecast, which had been
published in December in the annual Revenue Sources Book
(RSB). He noted the publication included information on
historical and forecasted revenue. He elaborated that DOR
gathered data from the tax accounting system, state
accounting system, and various state agencies to report
actual revenue for the most recent fiscal year. The
department maintained models within the Economic Research
Group for all of the major revenue sources to generate its
10-year revenue forecast. The RSB fulfilled the statutory
requirement that the governor provide a revenue forecast
for the current and next fiscal year. The book also
provided the revenue information to fulfill the statutory
requirement for a long-term fiscal plan out of the Office
of Management and Budget. The revenue forecast became the
basis for the governor's official budget proposal and was
updated in a spring forecast in March or April. In addition
to the basic data, the report included detailed narrative
about each of the state's revenue sources and forecast
variables. He relayed that all of the information was
located on the Tax Division's website.
2:51:51 PM
Mr. Stickel moved to slide 5 and discussed key Alaska
economic indicators reflecting data as of January 12, 2022.
He reported that state gross domestic product (GDP) was
down slightly in the third quarter; there had been small
modest growth since late in 2020. He reported the state GDP
was still down 6.3 percent from the similar period in 2019.
The data indicated the value of the economy was holding
steady, but it was still not back to pre-recession levels.
He noted it would be interesting to see what fourth quarter
data [to be released in March] looked like with holiday
shopping and higher oil prices. He stated that employment
was up by 7,200 jobs compared to one year earlier but
remained down over 13,000 jobs from the same month in 2019.
Jobs were up by 26,000 from the COVID-19 lows in April
2020, but jobs were still down by over 51,000 jobs from
pre-pandemic highs in July 2019. The biggest job losses had
been in transportation, leisure and hospitality, and oil
and gas. The industries had only recovered about half of
the losses from the COVID recession.
Mr. Stickel continued to address slide 5. Wages and
salaries had recovered from pandemic woes, which DOR was
attributing to a combination of a strong labor market and
some recovery in the employment situation. Bankruptcies and
foreclosures were still lower than the pre-pandemic levels.
He detailed there had been various government and private
industry policies that had helped people avoid bankruptcy
and stay in their homes, as well as the strong labor market
and extensive stimulus programs. Housing starts had
increased from 2020 and would end around pre-pandemic
levels at the end of 2021. As of the first quarter of 2021
(the most recent data available), average delinquency rates
were lower than the prior year. He explained the low levels
were a very good sign. He elaborated that between the
strong labor market, strong housing prices, and lenders
working with borrowers, there had not been a major uptick
in mortgage delinquencies with the recession.
2:55:25 PM
Representative Edgmon remarked that all data reflected a
snapshot or picture in time. He observed that the numbers
would look different were it not for a substantial influx
in federal spending. He added that the state was on the
cusp of receiving much more federal funding from the
federal infrastructure bill. He remarked, "We live in a
world of windows these days of pre, current, and post
pandemic." He pointed out that the current picture could
look much different in the future.
Representative Rasmussen noted she had seen in the news
recently that the Fed anticipated several rate hikes. She
wondered if any analysis had been done on how it may impact
the economy in Alaska.
Mr. Stickel answered that he had not done any specific
analysis on the issue. He pointed out that the current
level of federal interest rates was historically extremely
low. He reasoned that even if there were several rate
increases over the course of the year, rates would be
moving towards more of a normalization.
2:57:25 PM
Representative Josephson referenced Mr. Stickel's statement
that jobs were still down by 51,000 in comparison to pre-
pandemic. He remarked that Alaska's population had grown
somewhat. He thought some people were moving from a two
income to one income household or they were getting by on
savings or federal largesse or by some combination.
Mr. Stickel speculated that all of the components mentioned
by Representative Josephson were part of the story. He
deferred to the Department of Labor and Workforce
Development for details.
Co-Chair Foster noted that Representative Thompson had
joined the meeting at the start of the current
presentation.
2:58:27 PM
Mr. Stickel moved to slide 6 and discussed fall forecast
assumptions. He noted that the forecast had been finalized
in late November/early December just after the [COVID-19]
omicron variant hit the news. He pointed out that COVID-19
was still a source of uncertainty. He explained that the
approach DOR had taken with the pandemic was to develop a
plausible scenario to forecast the impacts. The forecast
assumed a 5.86 percent return for the Permanent Fund for FY
22 and a 6.2 percent return for FY 23 and beyond. The
federal revenue forecast had incorporated all of the
stimulus funding as of the end of November. The fall
forecast included a preliminary estimate for state revenue
from the federal Infrastructure Investment and Jobs Act
(IIJA). He noted the spring forecast would include a
refined estimate.
Mr. Stickel continued to address slide 6. The oil revenue
forecast was based on a $71 per barrel oil price for FY 23.
The department followed the futures market and had prices
at $68 per barrel by FY 31. The forecast assumed that
underlying economic activity had largely returned to normal
with the exception of tourism. The forecast assumed 1.5
million cruise ship passengers annually with a 75 percent
adjustment for the summer of FY 22 to reflect uncertainty.
3:00:37 PM
Mr. Stickel advanced to an illustration on slide 7 showing
relative contributions to total state revenue for FY 21. He
detailed that investment earnings, federal revenue, and oil
and gas were the biggest sources of state revenue. He
highlighted two windfalls in FY 21 including the extremely
high returns on investments (the Permanent Fund returned
29.7 percent in FY 21) and significant federal revenues
from stimulus packages. He noted that other revenue sources
shown on the slide were meaningful and contributed to the
economy and made up about 3.5 percent of total state
revenue.
Co-Chair Merrick asked what federal revenue would be on a
normal year.
Mr. Stickel answered that federal revenue would likely be
similar in terms of magnitude. He noted that investment
earnings, federal revenue, and petroleum were the top three
[revenue contributors]. He relayed that the information was
available in the RSB.
Co-Chair Merrick thought the stimulus packages would
increase the share of revenue significantly.
Mr. Stickel responded that the stimulus packages did
significantly increase federal revenue; however, in terms
of the share of total revenue, the federal share was likely
in line with historical numbers when factoring in the
extremely large investment earnings.
Representative Wool estimated the total federal money for
the pandemic may have totaled $5 billion to $6 billion. He
referenced the investment earnings and asked if it was the
percent of market value (POMV) draw that went into state
revenue or the total revenue inclusive of the Permanent
Fund's total earnings.
3:03:37 PM
Mr. Stickel answered that total state revenue on slide 7
included the full return of the Permanent Fund, which was
nearly 30 percent for the year. The presentation would
address unrestricted revenue later on, which only included
the POMV draw.
Mr. Stickel turned to slide 9 and discussed the total state
revenue from all sources for FY 21 and the forecast for FY
22 and FY 23. He highlighted that total state revenue came
from four broad sources including investment revenue,
federal receipts, petroleum revenue, and non-petroleum
revenues. He noted that revenues were further broken down
into four categories of restriction in the forecast and
budget documents. He began with UGF, revenues that could be
appropriated for any purpose and most commonly discussed in
budget discussions. Designated general funds (DGF) were
technically available for appropriation but were
customarily appropriated for a specific purpose. For
example, half of the revenue from the state's alcohol tax
was customarily appropriated to the alcohol and other drug
abuse treatment and prevention fund. The use of the "other
restricted revenues" category was dedicated for a specific
use and generally the use of the funds was restricted. He
highlighted examples including the constitutional
dedication of royalty revenue to the Permanent Fund and
school fund or motor fuel tax revenue that had to be used
for a specific purpose for aviation per federal law.
Mr. Stickel listed federal revenue as the fourth funding
category on slide 9. He relayed that federal revenues had
certain caveats around the way they had to be used and were
shown as restricted revenue in the DOR forecast. He noted
that sometimes designated, other, and federal funds were
lumped together into a single category of restricted
revenue. In FY 21, total state revenue from all sources was
about $29.8 billion. The department was forecasting total
revenue at $13.4 billion for FY 22 and $14.6 billion for FY
23. The UGF portion of the total was $4.8 billion in FY 21
and forecasted to be $5.7 billion in FY 22 and $5.9 billion
in FY 23. He highlighted two columns on the right showing
the percentage change from FY 21 to FY 23 and FY 22 to FY
23 in the forecast.
Representative Josephson looked at FY 21 investment revenue
of $16 billion [under the other restricted revenue category
on slide 9] and asked why the number went to $1.4 billion
in FY 22.
Mr. Stickel replied that the primary reason for the
difference was Permanent Fund earnings above and beyond the
POMV draw. The POMV draw was considered as unrestricted
general fund revenue and any additional earnings above the
draw were counted as restricted revenue. He explained the
$16.2 billion reflected the strong return of the Permanent
Fund above and beyond the POMV draw.
Representative Josephson surmised the $16.2 billion
reflected that until July 1, 2021, the corpus of the
Permanent Fund was generating more revenue than ever seen.
He surmised DOR was expecting much less revenue in the
current and following fiscal year. He stated his
understanding that DOR believed the stock market could not
sustain the growth seen in the last year.
3:08:58 PM
Mr. Stickel answered that the Permanent Fund return was
extremely high at just shy of 31 percent in FY 21. Callan
Associates, the state's investment consultant, was
projecting more modest returns going forward. The
department was expecting a 5.8 percent total return on the
Permanent Fund in FY 22 and 6.2 percent annual return for
FY 23 and beyond.
Representative Josephson stated that in a way it was not a
surprise, but in another way, it was an enormous statement.
He observed it was certainly the largest item on the table
in terms of the delta from year-to-year.
3:10:11 PM
Mr. Stickel turned to slide 10 and indicated the remainder
of the presentation would focus primarily on the UGF
revenue forecast because it had the most flexibility and
discretion in the budget process. He communicated that
investment revenue had become the largest source of
unrestricted revenue for the state by far. The primary
component was the POMV transfer from the Permanent Fund. He
reported that investment revenue had contributed just over
$3.1 billion in FY 21 and was estimated to contribute $3.1
billion in FY 22 and nearly $3.4 billion in FY 23.
Petroleum revenue generated about $1.2 billion in FY 21 and
was estimated to contribute $2.3 billion in FY 22 and $2.1
billion in FY 23. The non-petroleum revenue sources were
estimated to contribute about $375 million in FY 22 and
about $476 million in FY 23.
Representative Wool asked why investment revenue was going
down in FY 22. He asked if there was a negative year in the
five-year averaging.
Mr. Stickel replied that the POMV transfer was based on the
average value of the first five of the last six fiscal
years. Per statute, the FY 21 transfer had been 5.25
percent of the five year average and 5 percent for FY 22
going forward. He turned to slide 11 showing a summary of
key changes to the unrestricted revenue forecast between
the spring FY 21 and fall FY 21 forecast. The department's
oil price forecast had increased by $14.72 per barrel to
$75.72 for FY 22 and by $9.00 per barrel to $71.00 in FY
23. The increase was due to some of the stabilization and
recovery in the oil markets as the economy continued to
recover from the COVID-19 recession.
Mr. Stickel continued to address slide 11. There was no
change for the FY 22 projection for the Permanent Fund
transfer. He explained it had to do with the transfer being
based on the first five of the last six years. Based on
strong returns, the Permanent Fund transfer estimate was
increased by about $154 million for FY 23. For total
unrestricted revenue, FY 21 came in about $120 million
higher than expected in the spring forecast. The forecast
had increased by about $1 billion for FY 22 versus the
spring and by slightly over $800 million for FY 23. He
noted that the figures did not reflect new information
released by the department earlier in the day.
3:13:44 PM
Mr. Stickel shared that next set of slides would provide
more detail on the sources of unrestricted revenue. He
began with investments on slide 12. He highlighted that the
Permanent Fund transfer was expected to account for between
half and two-thirds of UGF revenue for each year in the 10-
year revenue forecast. He noted it really spoke to the
importance of the Permanent Fund as an asset for the state
and a major source of state revenue. The transfer had been
about $3.1 billion in FY 21 and was expected to contribute
a similar amount in FY 22 and about $3.4 billion in FY 23.
There was also a small amount of other investment revenue,
which primarily represented earnings on cash balances in
the General Fund.
Mr. Stickel advanced to slide 13 showing the estimated
transfer from the Permanent Fund to the General Fund for
the next ten years. The forecast estimated the transfer
would increase to $4.6 billion by FY 31. He highlighted
that the forecast was based on a long-term return
assumption of 6.2 percent and a 5 percent of market value
transfer to the General Fund annually. He stated that the
Permanent Fund was a stable and growing revenue source with
much of the stability coming from the trailing five-year
average used in the calculation for transfer to the General
Fund.
Representative Edgmon referenced Mr. Stickel's previous
statement that the Permanent Fund earnings could account
for one-half to two-thirds of UGF. He asked if the range of
one-half to two-thirds was primarily related to the
volatility of oil revenue. He remarked that the Permanent
Fund was growing over time, but the earnings would come
down from the 30 percent returns in the past year.
Mr. Stickel responded there were several variables
involved. First, oil prices were expected to moderate over
the coming years. Once the strong returns from the
Permanent Fund were fully baked into the revenue forecast,
DOR was expecting the transfer amount to increase. The
estimate of one-half to two-thirds was intended to give an
order of magnitude to illustrate the importance of the
Permanent Fund.
Representative Edgmon stated that all things considered, as
long as the POMV draw was adhered to, the Permanent Fund
was not really the source of the one-half to two-thirds
fluctuations in other sources of revenue. He asked for the
accuracy of his statement.
Mr. Stickel answered it was a combination of Permanent Fund
and oil revenue. For example, the department was expecting
unrestricted petroleum revenue of $2.3 billion in FY 22,
but the amount was expected to drop below $2 billion in
future years, while at the same time there were expected
increases for the Permanent Fund. He stated it was a
combination of the two different revenue sources. All of
the detail behind the calculations was included on page 11
of the RSB and factored in the 10-year revenue forecast for
investment revenue, petroleum revenue, and non-petroleum
revenue.
3:18:38 PM
Representative Edgmon remarked that he had been on the
committee long enough to remember when Permanent Fund
earnings were nowhere near one-half to two-thirds of total
UGF. He observed that things seemed to be changing quickly.
He underlined the importance of the revenue stream from the
Permanent Fund. He referenced the historic nature of
revenue in the state and pointed out that Permanent Fund
earnings were fairly steady. He stated the fund should be
something the state could count on in perpetuity. He
considered that oil had been the state's other source of
mostly permanent revenue and noted it was holding its own
but was nowhere near what it had been in the past.
Representative Josephson was struck by the anticipated $4.6
billion draw in ten years. He commented it was a short
period of time. He asked if it meant the department
believed the total value of the fund would be $95 billion
in 10 years.
Mr. Stickel answered that he did not have the information
on hand, but the number provided by Representative
Josephson sounded in the ballpark. The department was
forecasting the value of the Permanent Fund would continue
to increase given the expectation of a 6.2 percent annual
return and the trailing 5 percent draw, in addition to oil
and gas and other mineral royalties.
3:20:49 PM
Mr. Stickel turned to unrestricted petroleum revenue on
slide 14. He relayed there were four main sources of
petroleum revenue including property tax, corporate income
tax, production tax, and royalties. He detailed that the
state levied a property tax on all oil and gas property in
the state as a fairly stable revenue source generating a
little over $100 million per year in state revenue. He
pointed out the number only reflected the state's share.
There was additional revenue exceeding $400 million per
year in property tax that went to municipalities annually.
The state levied a corporate income tax on qualifying
corporations doing business in the state. He noted the tax
was on profits and because the recession was very difficult
on the oil and gas industry, there had been net refunds
paid out in FY 21. Based on the improved environment in the
petroleum industry, the department was forecasting $145
million of corporate revenue in FY 22 and $240 million in
FY 23.
Mr. Stickel highlighted there had been a provision of the
federal Coronavirus Aid, Relief, and Economic Security
(CARES) Act that allowed corporations to carry back net
operating losses for tax years 2018 through 2020 and
corporations could receive refunds for certain previous
taxes paid. He explained that Alaska's corporate income tax
statute adopted the federal tax code by reference;
therefore, the net operating loss provision had been
automatically adopted into Alaska's tax. The estimated
impact of the carry back refunds was about $2.4 million in
FY 21 and just under $50 million in FY 22.
Representative Wool stated that the legislature had heard
about the carry backward tax the previous year and it had
never been fixed. He asked for verification the situation
meant the state had to write a check for the aforementioned
amount.
Mr. Stickel agreed. He confirmed the provision had remained
in law and some companies were requesting refunds.
Companies could request a refund check or could apply the
amount in lieu of additional tax payments. The state was
starting to see the refund requests come to fruition.
Representative Wool asked for verification Mr. Stickel had
stated the amount was $50 million for FY 22.
Mr. Stickel answered that the department was estimating the
refund impact to be $2.4 million in FY 21 and $49.6 million
in FY 22. He noted there were some modest offsetting
positive impacts in future years.
3:24:20 PM
Mr. Stickel continued with slide 14. He discussed the oil
and gas production tax, the state's severance tax on
petroleum. For the North Slope, the tax consisted of a net
profits tax with a gross minimum tax floor. Given the
current oil price regime, the forecast anticipated most
companies would be paying above the minimum tax throughout
the forecast time horizon. The production tax was expected
to bring in just under $1 billion in FY 22 and about $740
million for FY 23. Royalties were the largest source of
unrestricted petroleum revenue and brought in about $729
million in FY 21 and were expected to bring in about $1
billion in FY 22 and FY 23. He noted the royalty was
limited to the state's General Fund share. The table did
not reflect additional royalty revenue going to the
Permanent Fund and school fund.
Mr. Stickel advanced to slide 15 and discussed unrestricted
non-petroleum revenue for FY 21 to FY 23. The largest
source of non-petroleum revenue was taxes. He stated that
typically, corporate income tax was the largest non-
petroleum tax type. The tax generated a little over $100
million in FY 21. He relayed that CARES Act related refunds
and some of the economic difficulties impacted non-
petroleum tax to the tune of $6.7 million, which was
included in the FY 21 number. The department estimated
about $76.7 million in FY 22. He noted the amount was
imbedded in the $15 million [shown in the first row of the
FY 22 column on slide 15]. Other significant taxes included
mining license tax, insurance premium tax, fisheries taxes,
and excise taxes. He pointed to the "other" category at the
bottom of the slide, which included all other non-petroleum
revenues such as licenses; permits; charges for services;
minerals, rents, and royalties; and miscellaneous revenues
such as state corporation transfers and dividends. In total
the department was expecting non-petroleum revenue of about
$375 million for FY 22 and $476 million in FY 23.
Representative Josephson asked if the refined fuel
surcharge amount [on slide 15] involved the sweep.
Mr. Stickel answered that beginning with the FY 22
forecast, the department was showing the refined fuel
surcharge as DGF. He explained the change had been made in
consultation with the Legislative Finance Division (LFD)
and the Office of Management and Budget (OMB) to match the
way the information was shown in budget documents. He
clarified the revenue source itself did not go away. The
department was merely switching the way it was shown in the
revenue forecast.
Representative Wool asked why there was a significant
increase in mining tax.
3:27:52 PM
Mr. Stickel answered that the $9 million in mining license
tax in FY 21 was an aberration due to low minerals prices
and some difficulties with the COVID recession had impacted
the mining industry, just like many other industries. The
increase to nearly $50 million in FY 22 and FY 23 was a
recovery to historical average levels.
Representative Josephson noted that mining produced
fantastic well-paying jobs but brought in little for the
state. Compared to oil and gas, the revenue was low and
unimpactful. He thought it was important to think about the
issue for the future.
3:29:19 PM
Mr. Stickel turned to slide 17 and provided petroleum
detail and changes to the long-term price forecast. The
slide showed the fall 2021 oil forecast for North Slope
crude in comparison to the spring forecast. The department
had made a change to the way it forecast oil prices in the
fall forecast. Previously, DOR had looked at the futures
market for two years and applied an inflation adjustment.
The change in the fall forecast used futures market data
for as many years as were available. He explained that the
fall forecast used futures market data through FY 29. The
change had been made to provide a more accurate projection
of oil prices and to allow policymakers to focus on policy
discussions instead of whether the forecast was correct or
not.
Mr. Stickel relayed that the department's Economic Research
Group had prepared an analysis of historical prices and
futures market projections and what would have happened had
the forecast used additional years of futures markets. He
explained the analysis made a compelling case that using
more data from the markets provided a better forecast. The
group had presented the findings internally and
subsequently to LFD and OMB. He shared that all parties
agreed the change would provide a more forthcoming and
accurate revenue forecast. The price forecast on slide 17
had been generated on December 9 using futures market data
at the time. The calculation resulted in an FY 23 oil
forecast of about $71 per barrel, which was $9 higher than
the spring forecast. The slide showed moderate declines in
price with prices stabilizing in the mid to upper $60s.
3:31:46 PM
Representative Rasmussen asked if there would be time to
ask LFD Director Alexei Painter questions on the updated
forecast.
Co-Chair Foster stated his understanding of the question.
Representative Rasmussen relayed she was interested in
hearing from Mr. Painter on the updated forecast and new
modeling highlighted by Mr. Stickel.
Co-Chair Foster believed Mr. Painter would be presenting to
the committee on Friday and there would be an opportunity
to ask the questions then.
Representative Wool looked at the dotted red line
reflecting the spring forecast compared to the dotted blue
line reflecting the fall forecast [on slide 17]. He stated
his understanding that both lines included futures market
data through FY 29. He asked why there was a difference
between the two forecasts.
Mr. Stickel answered that the futures market had been in a
state of "backwardation" for some time. He explained it
meant the futures market was expecting oil prices would
show modest declines over the next several years. When the
department prepared the spring forecast, it used the
futures market to inform its FY 22 forecast and had applied
an inflation adjustment beyond FY 22. He elaborated the
department had assumed there would be modest increases in
price after FY 22. Whereas the fall forecast used as many
years as were available in the futures market for the fall
forecast. He explained that DOR had incorporated the
backwardation in the market through FY 29.
Representative Wool stated his understanding the department
had changed its modeling methodology between the spring and
fall forecasts.
Mr. Stickel answered in the affirmative.
Representative Wool wondered if the futures market
indicated the locked price a person could buy or sell oil
for out through FY 27 or FY 29.
Mr. Stickel agreed. He explained it was the price for oil
in the future if someone wanted to trade the oil at
present.
3:35:10 PM
Mr. Stickel turned to slide 18 showing how the department's
petroleum price forecast compared to other forecast
sources. The department's forecast compared to Brent
forecasts from the Energy Information Agency from current
futures markets as of January 11, 2022, and from an average
of analyst forecasts. He explained the department compared
the ANS forecast to Brent because Brent was a global
benchmark crude, which competed with ANS and typically
priced at a very similar level. He highlighted the
department's forecast was in the range of the other
forecasts. He remarked that oil prices had increased over
the last several weeks. He detailed the department's
forecast was on the lower side for the next two years, but
it moved back in the range of other forecasts after that
time. He added that the difference in the next couple of
years had been the justification for starting to provide
monthly revenue updates.
Mr. Stickel moved to a chart on slide 19 showing how
revenue for FY 23 would change with different oil prices.
He detailed that at the forecasted price of $71 per barrel,
the estimated unrestricted revenue excluding the Permanent
Fund transfer was about $2.6 billion. He explained that
each $1 increase above the forecasted price would lead to a
$60 million to $65 million change in the revenue forecast.
Mr. Stickel provided a recap of information presented
earlier by the Department of Natural Resources (DNR). The
slide showed the 10-year outlook for oil production from
the North Slope in addition to the high and low cases. In
general, there was stable to slightly increasing oil
production expected. He highlighted that the official
production forecast was a reference case within a range of
potential outcomes and production could be higher or lower
than forecasts shown.
3:38:33 PM
Vice-Chair Ortiz asked if slide 20 was an exact replica of
information provided earlier by DNR. Alternatively, he
wondered if the information was adjusted based on DOR
input.
Mr. Stickel answered that DOR incorporated additional
months of actual production into the DNR information. The
DOR forecast incorporated actual production through the end
of November into the FY 22 number.
Mr. Stickel addressed a chart on slide 21 showing a
comparison of the fall production forecast to the spring
production forecast. Over the near-term, the fall forecast
increased above the spring forecast primarily due to
increased drilling and activity at the major fields. In the
long-term, there had been some reductions compared to the
spring forecast given the increased uncertainty around
legal and Arctic financing issues.
Mr. Stickel discussed a chart on slide 22 showing the
state's allowable lease expenditures on the North Slope,
including how the numbers had changed over the past decade
and the 10-year forecast. He noted the chart factored in
average oil and gas employment and indicated a strong
correlation between company spending and employment. The
allowable lease expenditures were important in the
production tax calculation because they were deductible
from the net production tax. Company spending was also a
very important measure of current and planned investment in
Alaska.
Mr. Stickel explained that the forecast on slide 22 related
to a question asked earlier by Representative Edgmon about
expectations for future spending. He detailed that in FY 21
the oil and gas industry had been hit hard by the COVID-19
situation. He elaborated that capital expenditures were
about $1.5 billion and operating expenditures were about
$2.4 billion, which reflected at $2.7 billion decrease
year-over-year in company investment in the North Slope.
The department was forecasting a rebound for FY 22 and FY
23. He expounded that as companies started to invest in
major new developments like Pikka and Willow and resumed
drilling at existing fields, capital expenditures would
increase and stabilize at a little over $2 billion per
year. On the operating expenditure side, it was expected
that some of the cuts made over the last year would be
permanent as companies adopted cost saving measures.
Additionally, there were small increases in operating costs
expected in several years associated with bringing new
fields online.
3:42:00 PM
Representative Josephson stated that pursuant to HB 111,
non-producers baring wholly allowable expenses were
required to come into production by a given number of years
or they would lose the opportunity to deduct the expenses.
He asked if his statement was correct.
Mr. Stickel answered that companies currently in production
were allowed to deduct allowable lease expenditures against
the value of the oil they sold when calculating their net
profits. He explained that a company was in a loss
situation (whether it was a current producer with
insufficient revenue or a new company developing a new
field), any of the lease expenditures not applied in the
production tax calculation would become a carried forward
lease expenditure. There was a provision in statute that
the carried forward expenditures decreased in value
thth
beginning in the 8 or 11 year after they were earned.
Representative Josephson stated that if a person was just
beginning a new lease hold and exploration work in 2022,
they had to have confidence they would begin to produce oil
by 2029 or the deductions would be lost over time. He asked
if he was accurate.
Mr. Stickel confirmed the provisions around the carried
forward lease expenditures would be part of a company's
investment decision making process.
3:44:19 PM
Mr. Stickel stated that slide 23 showed a history and
forecast of North Slope transportation costs (also known as
netback costs). He explained the costs reduced the value of
oil for tax and royalty purposes. Transportation costs
included getting oil to market including the Trans-Alaska
Pipeline System (TAPS) tariff, marine costs, and other
smaller items such as feeder pipeline tariffs. In FY 21,
the average transportation cost for North Slope oil was
$9.19 barrel. The forecast was for $9.70 in FY 22 and $9.09
in FY 23. The department was expecting transportation costs
would remain just under $10 per barrel throughout the ten-
year forecast, given that any higher costs of
transportation were generally offset by increasing oil
production and throughput.
Representative Wool asked why the costs in FY 19 and FY 20
were particularly low.
Mr. Stickel replied that the three primary components were
broken out. He explained that in FY 19 and FY 20 there had
been some changes to the way the TAPS pipeline tariff was
calculated that reduced tariffs. He elaborated that a new
settlement methodology had been incorporated. Additionally,
fuel was a major component in marine costs, which had been
impacted by lower oil prices.
3:46:31 PM
Mr. Stickel turned to slide 24 and discussed tax credits
for purchase. He explained that prior to 2016 there had
been various tax credits in state statute that could be
applied against tax liability or turned into a tax credit
certificate. He detailed that the state could then purchase
the tax credits at face value. Changes made by the
legislature in 2016 and 2017 implemented sunset provisions
for all of the tax credits; therefore, there were no new
credits being earned. He highlighted there was still a
large outstanding balance of the tax credit certificates
for activity performed prior to the sunsets. There was a
formula in statute suggesting an annual appropriation for
state purchase of the tax credits. He explained the formula
was based on either 10 percent or 15 percent of estimated
production tax levy before subtracting credits. Prior to
2016, the full amount of eligible tax credits was purchased
by the state annually. Beginning in 2016, less than the
full amount was purchased by the state. In FY 20 and FY 21,
no appropriation was made, and a $54 million appropriation
was made in FY 22, which was still below the statutory
appropriation.
Mr. Stickel stated that under the fall revenue forecast the
statutory appropriation would be $199 million for FY 23.
Slide 24 showed an estimated $587 million in outstanding
tax credits available for state purchase at the end of FY
22. He explained that if the legislature were to make the
statutory appropriation per the fall forecast, the entire
balance of the certificates would be retired by FY 26.
Representative Josephson asked if the FY 23 budget request
was $199 million.
Mr. Stickel believed Representative Josephson was correct
that $199 million was the statutory appropriation.
Mr. Stickel indicated there was one slide remaining that
the Tax Division director would review.
COLLEEN GLOVER, DIRECTOR, TAX DIVISION, DEPARTMENT OF
REVENUE (via teleconference), spoke to slide 26 related to
an oil and gas production tax audit update. She relayed
that DOR was still working to catch up and would like to be
on a three-year audit cycle. She relayed that all of the
division's other tax programs were on a three-year audit
cycle in statute. She explained that oil and gas production
tax was an outlier and there was a six-year statute of
limitations for the audits. In the past, the department had
been at the late date of getting the audits completed. She
reiterated the division was working to catch up and get on
a three-year cycle. She reported that the progress had
slipped a bit from the previous year, but she believed the
work was still on track. She relayed departures in
personnel had contributed to the delay. She believed the
division was in the same situation as many employers across
the nation and it was struggling to recruit new employees.
She noted that the division's teams were small and even
several vacancies hindered its ability to get work done.
3:50:56 PM
Ms. Glover continued to speak to slide 26. She referenced
how COVID had resulted in the state embracing telework. She
lauded the oil and gas production audit team for being the
leading team on embracing technology. She remarked that the
team had used little paper prior to COVID; therefore,
teleworking had not hindered the ability to get audits
done. The division continued to try to leverage its
technology and used [Microsoft] Teams meetings to stay
connected. She noted that audits were done by teams, not
individual people. The division had been working to have
consistency in its audits. She highlighted improvements
made by a risk-based approach. She detailed that instead of
doing labor intensive audits that may not generate
significant findings, the division looked at past audits
and high risk areas to perform targeted audits in order to
leverage its resources. She summarized that work had
slipped by one or two quarters, but she believed the
division was on track to be on the three-year cycle by the
time it completed its 2018 and 2019 audits in 2023.
Representative Josephson looked at the petroleum revenue
projection of $2.082 billion in FY 23 on slide 10. He asked
if the money was paid from the producers and uncontested.
Alternatively, he asked if some of the funding was possibly
litigated.
Ms. Glover answered that the unrestricted revenue shown
under the production tax revenue reflected monthly
estimated payments. She clarified the data did not include
any settlements or litigation amounts.
Representative Wool asked if it was fair to say that many
of the audits would end up being settled for less than the
face value.
Ms. Glover replied that every audit and result was
different. She would not say audits were typically settled
or negotiated for less. There were audits that got
litigated all the way up to the supreme court. Much of it
related to the state's confidence in its ability to
litigate and how strong the Department of Law's opinion
was.
3:55:26 PM
Co-Chair Merrick thought a couple of tax auditors had been
added the last year. She asked if it was within the DOR
budget.
Ms. Glover answered that the two corporate income tax
auditor positions had not been included in the final FY 22
budget.
Co-Chair Merrick reviewed the schedule for the following
day.
ADJOURNMENT
3:56:24 PM
The meeting was adjourned at 3:56 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HFIN Fall 2021 Revenue Forecast Presentation 2022.01.19.pdf |
HFIN 1/19/2022 1:30:00 PM |
|
| DNR Fall 2021 Production Forecast_House.pdf |
HFIN 1/19/2022 1:30:00 PM |
|
| DNR Production Forecast_HFIN_Replacement slide 011922.pdf |
HFIN 1/19/2022 1:30:00 PM |