Legislature(2023 - 2024)ADAMS 519
02/09/2023 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Presentation: Order of Operations - Alaska's Oil Tax Regime | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
HOUSE FINANCE COMMITTEE
February 9, 2023
1:35 p.m.
1:35:09 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
Dan Stickel, Chief Economist, Economic Research Group, Tax
Division, Department of Revenue.
SUMMARY
PRESENTATION: ORDER OF OPERATIONS - ALASKA'S OIL TAX REGIME
1:35:15 PM
Co-Chair Johnson reviewed the meeting agenda.
^PRESENTATION: ORDER OF OPERATIONS - ALASKA'S OIL TAX
REGIME
1:36:22 PM
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE, introduced the PowerPoint
presentation titled, "Order of Operations Presentation
House Finance Committee," dated February 9, 2023. He
briefly addressed slide 2 which included a list of acronyms
associated with the oil industry.
Mr. Stickel continued on slide 3 and went through the
agenda of the presentation. He would start by looking at
the sources of revenue from the state. The focus of the
presentation overall would be on North Slope oil.
Mr. Stickel moved to slide 4 and offered a disclaimer that
the presentation would be taking a complex tax system and
simplifying it for the purpose of palatability. He
emphasized that anything he said was not tax advice nor an
official tax interpretation. He advanced to slide 5, which
touched on the four sources of oil and gas revenue for the
state. The state received a royalty based on the gross
value of production on state land. The rates varied but
were typically around 12.5 percent of 16.67 percent in
Alaska. The state had a corporate income tax that applied
to most, if not all, oil and gas companies. The state
received a property tax based on the value of oil and gas
property. The tax as 2 percent of assessed value or "20
mills." Any property tax paid to municipalities was allowed
as a credit to offset the state tax paid. The final source
was the production tax, which would be the focus of the
majority of the presentation.
1:40:26 PM
Co-Chair Johnson asked if 2 percent property tax was the
rule across the state.
Mr. Stickel responded that the property tax was levied at
the 2 percent rate and any municipal tax up to 2 percent
was allowed as a credit against the state tax. The owner of
the property would pay the 2 percent tax regardless of the
municipal tax rate.
Co-Chair Johnson asked if in the state received the full 20
mills in unorganized areas of the state.
Mr. Stickel responded the state received the full 20 mills
tax when there was no borough. The state received a smaller
portion in areas where there was a borough.
Representative Hannan understood there were three main
municipalities that received the property tax: Fairbanks,
Valdez, and the North Slope. She asked if any area was
receiving the full 20 mills.
Mr. Stickel responded that the city of Valdez was leveling
at the full 20 mills and the state was not receiving any
state property tax for the City of Valdez. All of the other
municipalities were levying less than the full 20 mills as
of FY 22.
Representative Josephson asked whether occupying the full
tax availability was entirely at the discretion of the
municipality.
Mr. Stickel responded that it was up to the municipality to
set the rate, but the municipality was limited in that it
could not tax oil and gas property at a higher rate than
other properties were taxed.
Mr. Stickel continued on slide 6, which showed five years
of revenue data from various oil and gas revenue sources.
The slide included a chart showing two years of historical
data, the status of the current fiscal year, and two years
of future projections. The property tax on the chart was
the state share only. The municipalities received about
$450 million above the state share in FY 22. There were
some temporary impacts in FY 21 related to refunds paid out
due to losses in 2020 due to the pandemic. Production tax
was comprised entirely of general fund revenue. Another
revenue source was royalties, though a significant share of
royalties were dedicated to the Permanent Fund and the
school fund. A smaller source was any settlement as a
result an assessment or dispute, which was deposited in the
Constitutional Budget Reserve (CBR). The state also
received a small share of revenue from the National
Petroleum Reserve - Alaska (NPR-A). Additionally, the
Willow project would significantly increase the revenue
source.
1:45:51 PM
Representative Hannan asked if the NPR-A was set in federal
statute or if there were opportunities for negotiation.
Mr. Stickel responded that he believed it was set by
federal statute. The NPR-A was a 50 percent share of
revenue back to the state and there were specific
provisions around how the resulting revenue could be used.
The state was required to use the revenue for the benefit
of communities impacted by the oil developments.
Representative Hannan asked if the entirety of the 50
percent share was required to be distributed to the
impacted communities.
Mr. Stickel responded in the affirmative.
Representative Hannan asked if any of the revenue would be
distributed to the state general fund.
Mr. Stickel responded, "Correct."
Representative Stapp understood that Mr. Stickel was using
the fall revenue forecast for the projections. He asked how
much of a discrepancy there was between the FY 22 oil price
projections and the current price of oil.
Mr. Stickel responded that the Department of Revenue (DOR)
compiled a monthly cash flow update and it would be
finalized in the following week. The projections for 2023
and 2024 were accurate based on the January 2023 update and
did not meet the 10 percent threshold requiring that an
official notification be released. The oil prices and
revenues were tracking close to the revenue forecast.
Representative Galvin asked for more details on the Willow
projections. She understood that the oil companies Santos
Limited and Conoco Phillips might differ in regard to
production and the ways in which the state provided
credits. She asked how the potential differences might
impact the revenue returning to Alaska.
Mr. Stickel responded that Santos was the manager of the
Pikka Unit project on the North Slope and Conoco was the
manager of the Willow project. Both projects would be
subject to property tax, production tax, and corporate
income tax. The two differed in the ways royalties would
apply and he had a slide later in the presentation that
went into detail on the topic.
1:49:20 PM
Representative Josephson understood that the severance tax
structure for the Willow project and Pikka project was
identical, but the royalty revenue was not identical.
Willow had great economic value, but it was located on
federal land; therefore, the Pikka project would have more
value to the state.
Mr. Stickel responded that the state would receive
relatively more revenue from Willow than it would from
Pikka.
Representative Josephson commented that royalties in the
2014 and 2015 time frame were significant and a larger part
of the revenue picture. He understood that royalties were
now occupying the most traditional second share position in
terms of its value to the state. He asked if he was
correct.
Mr. Stickel responded that whether royalties or production
tax brought in more revenue to the state was largely a
function of the price of oil. Production tax was based on
net tax and was progressive to price whereas royalties were
based in gross value. Relatively lower oil prices generally
meant that royalties would exceed production taxes. There
were several years in the 2010s during which production tax
generated more revenue than royalties, but royalties had
generated more revenue than production tax in the last
several years.
Mr. Stickel advanced to slide 7, which showed the overall
order of operations for the state's fiscal system. The
order was as follows: royalties, property tax, production
tax, state corporate income tax, and federal corporate
income tax. He would go into detail on each step. Firstly,
he explained that landowners received their share of oil
before any other entity. The second step was property
taxes, which were considered lease expenditures for the
purpose of calculating the production tax and were also
deductible against corporate income taxes. The third step
was production tax, which was calculated after royalties
had been deducted and property taxes had been considered.
The production tax would then become an allowable deduction
in calculating corporate income tax. Finally, the state
corporate income tax acted as a deduction when calculating
the federal corporate income tax.
Representative Galvin understood that investment dollars
for Conoco could receive a different tax treatment than
investment dollars for Santos. She asked if Mr. Stickel
could provide more detail.
Mr. Stickel responded that he could not speak to specific
companies. However, it was true that an incumbent producer
that had existing production and revenue on the North Slope
could offset revenues with investments in new production.
Investments by a company that did not have existing
production were treated differently.
1:54:19 PM
Representative Cronk asked about the revenues for FY 21 and
FY 22 on slide 6. He asked for confirmation that the state
received $1.6 billion in FY 21.
Mr. Stickel responded in the affirmative.
Representative Cronk understood that the state was
collecting about 20 percent of the value of a barrel of
oil. He asked if he had made a correct assessment.
Mr. Stickel responded that DOR had provided the Senate with
some information about how the cash flowed from a typical
barrel to the producers. He would be happy to provide the
committee with the same information. He noted that a
significant share of the value of a barrel was dependent
upon transportation costs of getting the oil to market,
which averaged around $10 per barrel. When assessing the
distribution of the value of a barrel, it was important to
look at the distribution of the production tax value and
how the profit would be shared between the various
entities.
Co-Chair Johnson thought that it would be helpful to get
the information about cash flow. She suggested holding
questions until later on in the meeting.
1:57:10 PM
Mr. Stickel moved to slide 8, which was the basic
calculation of the production tax on the North Slope. The
calculation was based on the income statement presented in
Appendix E of the Revenue Sources Book released by DOR. He
noted there was an error in the original book because the
leap year in FY 24 was overlooked. The FY 24 forecast was
for $81 per barrel and 503,700 barrels in production, which
gave a total value of about $41 million per day of North
Slope oil production.
Mr. Stickel advanced to slide 9, which was royalty barrels
and taxable barrels. Royalty barrels were subtracted before
accounting for taxes, which included any state, federal, or
private royalty barrels. There was also a small portion of
production that was outside of state jurisdiction. After
subtracting the royalties, the total was around 160 million
barrels of production in FY 24 that were considered taxable
with a $13 billion taxable value.
Mr. Stickel moved to slide 10. The next step in the
calculation was subtracting the transportation costs to
arrive at the gross value at the point of production. The
transportation costs included the price of getting the oil
to market. The price for North Slope oil was priced at
market in Long Beach, California. The marine transportation
costs were then subtracted, such as the Alaska Pipeline
tariff and any other tariffs, and other minor adjustments
were made. For FY 24, the average transportation cost
estimate was $9.37 per barrel. The average gross value at
the point of production was $71.63 per barrel with a total
gross value of about $11.5 billion.
Mr. Stickel continued to slide 11 and lease expenditures.
The production tax was essentially a modified version of a
net profits tax. Deductions of both capital and operating
expenditures were taken in order to calculate the
production tax. The department used guidelines from the
Internal Revenue Service (IRS) to determine what was
considered a capital expenditure. There was no depreciation
provision in the production tax which meant that a company
was permitted to deduct its entire capital expenditure in
the year incurred. There were two terms to understand:
allowable lease expenditures and deductible lease
expenditures. Allowable lease expenditures were any costs
in the unit directly associated with producing oil and gas.
Deductible lease expenditures were developed within DOR to
represent the share of allowable lease expenditures that
could be applied against the value of production in the
year incurred. He added that lease expenditures were
treated differently depending on the company. Any lease
expenditures that were not deducted in the year incurred
became carried forward lease expenditures, which could be
used as deductible lease expenditures in a future year's
tax calculation. There was a provision in the tax code in
which the lease expenditures lost value after a certain
amount of time. If a company had not achieved enough
production to use the lease expenditures, they would begin
to decrease in value.
2:04:06 PM
Mr. Stickel moved to slide 12 showing the calculation of
production tax value. The calculation was gross value minus
lease expenditures. For FY 24, the total production tax
value was estimated at about $7.1 billion. The value would
be different for every company.
Mr. Stickel advanced to slide 13 and detailed the tax
calculations once the production tax value had been
determined. There were two tax calculations involved: a
gross minimum tax floor calculation and a net tax
calculation. The minimum tax floor calculation was 4
percent of the gross value at the point of production. For
FY 24, the minimum tax floor would be about $460 million.
Representative Stapp asked if the minimum tax could be
offset using operating expenditures or capital
expenditures.
Mr. Stickel responded that the operating and capital
expenditures were part of the calculation for the net tax
only. The minimum tax floor was based on the gross value
and there was no allowance for operating and capital
expenditures.
Representative Josephson commented that prior to HB 247,
there were ways for a company's tax rate to be less than 4
percent of gross. He understood that it was no longer
allowable.
Mr. Stickel responded in the affirmative. In the past,
companies had been able to use tax credits to reduce their
tax liability below the minimum tax floor. Currently, there
was one credit that could be used to take the liability
below the minimum tax floor. He would discuss it in more
detail later on in the presentation.
2:07:59 PM
Mr. Stickel continued on slide 14 which looked at the net
tax and gross value reduction (GVR). He explained that GVR
was an incentive for new development and provided a
temporary incentive by excluding 20 or 30 percent of the
gross of qualifying new production. The 30 percent applied
if there was a unit with qualifying new production and the
unit was an entirely state issued lease with greater than
12.5 percent royalty. Any other qualifying new production
would get the 20 percent benefit. The GVR was taken out of
the production tax value before applying the tax rate.
Additionally, any of the oil that qualified for the GVR
provision received a flat $5 per taxable barrel credit
rather than the sliding scale credit that applied to all
other production. The GVR was a temporary benefit and
expired after seven years or after any three years in which
oil prices had exceeded $70 per barrel. In FY 24, the
production tax value was about $6.9 billion after the GVR.
The statutory tax rate was 35 percent of the value, which
resulted in a production tax of slightly over $2.4 billion
before credits.
Mr. Stickel moved to slide 15 which compared the net
profits tax and the minimum tax floor. The higher of the
two calculations would become the starting point for the
tax before credits. In FY 24, the $2.4 billion net tax was
expected to prevail over the $460 million minimum tax
floor. The major tax credits in place were the per taxable
barrel credits. One of the credits applied to the GVR
eligible oil and was a flat $5 dollar per barrel tax
credit, and the other credit applied to all other oil. The
second credit was a sliding scale ranging from $8 per
barrel when the wellhead value was less than $80 per
barrel. The gross value at the point of production for FY
24 was expected to be $71.63, which meant than an $8 per
taxable barrel credit would apply. He explained that the
credit phased out in $10 increments of wellhead value. If
the wellhead value exceeded $150 per barrel, the sliding
scale credit would phase down to zero. If any of the per
taxable barrel credits were not used in the year incurred,
the credit would be forfeited as there was no provision for
state purchase or carry-forward of the credits. The sliding
scale per taxable barrel credit could not reduce tax
liability below the minimum tax floor. He noted there were
a small number of other tax credits against liability,
primarily including the small producer credit. The small
producer credit was being phased out, but a couple of small
companies were still able to claim the credit. If a company
did not use any of the sliding scale credits, it could
potentially use the $5 per barrel credit to reduce its tax
below the minimum tax floor. After deducting all of the
credits, the total tax was about $1.2 billion for FY 24.
2:13:02 PM
Representative Josephson commented that around FY 12, the
$1.2 billion number was around $6 billion. He highlighted
the difference because constituents wanted legislators to
spend within the means of the state and the state's means
were much less than they were in FY 12.
Mr. Stickel responded that it was correct that production
tax had been very volatile. In FY 13, the production tax
was around $4 billion, then in FY 17 it was $126 million.
The production tax varied significantly depending on oil
prices.
Representative Stapp understood that the transportation
costs were factored in prior to factoring in the wellhead
value. He asked if it would be $90 per barrel and not $80
per barrel because the transportation costs were taken out
before the wellhead value was calculated.
Mr. Stickel responded that when there was a quote of $80
per barrel, it was typically the destination value. The
transportation cost would need to be subtracted to
approximate the wellhead value in Alaska. The sliding scale
calculation in statute specifically referenced the wellhead
value, not the destination value.
Mr. Stickel moved to slide 16. There were some other items
that would be added to the tax calculation to determine the
total tax revenue that was received by the state in a given
fiscal year. The items included things like payments of
prior year taxes, refunds of prior year taxes, taxes on
private landowner royalties, taxes on gas production on the
North Slope, surcharges, and any adjustments for company-
specific differences. In FY 24, it was estimated that the
adjustments would add up to about $16.9 million with a
total tax paid to the state of a little over $2 billion.
All but $8 million of the total was considered unrestricted
general fund revenue. After the calculation of the taxes,
the department had estimated that there was about $880
million of lease expenditures in FY 24 that would be earned
by companies making investments in the North Slope that
could not be applied to production taxes in FY 24. The $882
million would carry forward and be available to offset
future tax liabilities.
2:17:32 PM
Representative Josephson was confounded by Mr. Stickel's
last comment because the treasury received a total of
$1.236 billon. He thought it would be difficult to make
accurate predictions for future years assuming that the
carry-forward lease expenditures could be utilized in the
out years.
Mr. Stickel responded DOR maintained a company-specific
modeling of production tax liabilities and was keeping
track of which companies were earning the credits and
estimating each company's production tax liability. The
department assumed that the companies would utilize the
carry forward lease expenditures to the maximum extent
possible. The uncertainty around the lease expenditures had
to do with the possibility that the expenditures could
decrease in value after eight or ten years if it was not
utilized.
2:19:05 PM
Mr. Stickel moved to slide 17 which took the same analysis
that had been performed for FY 24 and projected it out
across five years from FY 21 through FY 25. It was
estimated that production tax value ranged from about $3.5
billion in FY 21 to $8.8 billion in FY 22 and slight
decreases were predicted year over year based on the lower
oil prices. The net tax paid to the state followed along
with $389 million of production tax in FY 21 and over $1.8
billion in FY 22 and decreased to a projection of a little
over $1 billion in FY 25. There were two new rows at the
bottom of the slide in response to the feedback in the
prior year's presentation. The first new addition was an
estimate of the total ending value of the carried forward
lease expenditures, which were expected to be nearly $3.3
billion at the end of FY 25. The lease expenditures would
be available to offset future taxes for companies. The
second addition was a calculated effective tax rate, which
depended upon production tax value and evaluated the total
amount of tax paid to the state as a result of North Slope
production tax value for oil. The effective tax rate was 11
percent in FY 21 and 20 percent in FY 22 and FY 23.
Representative Ortiz asked how Alaska's oil tax regime
compared to that of other states.
Mr. Stickel responded he was not prepared to speak on the
topic.
Representative Ortiz noted the overall general trend
projecting a decrease in revenue in future years. He asked
if the reduction was entirely due to projected price or if
production had an impact as well.
Mr. Stickel responded that the effective tax rate was a
result of price and spending and the production had been
fairly stable overall. However, higher prices would impact
tax rates and lower lease expenditures.
Representative Hannan asked about the carried forward lease
expenditures and net lease expenditures at the bottom of
slide 17. She noted that the carried forward expenditures
were slightly more than the net expenditures in FY 21.
However, the carried forward expenditures had nearly
tripled by FY 24 and had increased fivefold by FY 25. She
asked if it was due to there being less development and why
it was increasing at such a fast rate.
Mr. Stickel responded that the carried forward lease
expenditures were a fairly new provision of tax law. The
system changed from tax credits to the carried forward
system, which became a deduction. The chart on slide 17
indicated that the net lease expenditures carried forward
and represented the net earned in a given fiscal year. The
total carried forward lease expenditures line on the chart
referred to a cumulative calculation and would grow over
time. It was expected that the net lease expenditures
earned in a given year would increase each year.
Representative Hannan asked if there was a risk to the new
system. She supposed that if all expenditures were paid
off, no tax would be earned due to the process of
compounding.
Mr. Stickel responded that the state would still receive a
tax. The carried forward lease expenditures were limited to
the specific company and the specific development that
incurred the lease expenditures. They were also limited by
the minimum tax floor. Companies with sufficient revenue
could chose to reduce the tax liability down to the minimum
tax floor.
2:25:50 PM
Mr. Stickel moved to slide 18 which modeled a scenario of
there being only a single taxpayer on the North Slope. The
scenario assumed that there was only one company that
operated all of the fields and made all of the investments.
The primary difference with the current forecast was that
there were some small companies that were not able to use
the full $8 per barrel taxable credit. If there was a
single producer, it would be expected that the producer
would use the entire $8 per barrel credit to offset tax
liability. In the scenario, the total production tax
deposited into the treasury would be about $1.19 billion,
as opposed to $1.24 billion in the official forecast. It
was a small difference given the pricing expected in FY 24.
The slide intended to highlight the impact of the economics
of individual companies on the tax as well as the fact that
each company had its own portfolio of operations and
investments.
Representative Galvin commented that she had read somewhere
that a past governor was sorry that they had included
worldwide investments in the tax structure as opposed to
just Alaska. She was not familiar enough with the topic to
discern what that meant, but she thought that Mr. Stickel's
comments were related.
Mr. Stickel responded that there had been some debate over
corporate income tax in particular. The current corporate
income tax structure involved taking a company's worldwide
income and apportioning it to Alaska rather than
calculating a separate income for corporate income tax.
Representative Josephson stated he was struggling with the
hypothetical scenarios on the carried forward lease
expenditures. He thought there would be circumstances
dependent upon the production tax value (PTV) in which the
state might not make a lot of money for the treasury.
However, once the costs had been sunk and paid for,
"everyone would come out a winner" in the following year.
He asked if he was understanding the concept correctly.
Mr. Stickel responded in the affirmative. The idea with the
carried forward lease expenditures was to give companies
the opportunity to deduct lease expenditures against tax
calculations. Incumbent producers could deduct the
expenditures in the year that the expenditures were
incurred, and new producers could deduct the expenditures
in a future year.
2:30:36 PM
Mr. Stickel continued on slide 19, which showed how
petroleum revenues varied by land type. The concept behind
the slide was that not all oil was equal and the amount of
revenue the state would receive from oil depended on where
the oil originated. There currently was no production
beyond six miles offshore of state land. The state would
not receive any revenue from intercontinental oil
production; however, it could receive economic benefits and
it could have a positive impact on the tariff. The state
would not apply taxes to production three to six miles
offshore, but the state would receive a 27 percent share of
federal royalties. There was currently a small amount of
production that fell into the three to six mile category.
Within the three mile limit, property tax, corporate tax,
and production tax was applied the same across all
developments. State royalty applied to any production on
state land. Any production within the NPR-A was on federal
land and 50 percent of royalties were shared back to the
state, but the proceeds were required to be used for the
benefit of local communities. Additionally, any production
within the Alaska National Wildlife Refuge (ANWR) was also
on federal land, but the state received a 50 percent
royalty with no restrictions. Other federal land would
receive a 90 percent share back. Production on private land
was primarily owned by Native corporations and a private
royalty applied on the land in addition to a 5 percent
gross tax as part of the production tax.
Representative Hannan understood that the expectation of
the amount that the state general fund would receive from
the Willow project was limited. She asked if it was zero.
Mr. Stickel responded that the revenue impact of Willow
would be non-zero as production tax, corporate income tax,
and property tax would all apply. Significant production
from Willow would also reduce pipeline tariffs.
2:35:03 PM
Mr. Stickel continued on slide 20 and briefly touched on
the GVR. He explained that the GVR was an incentive program
for new oil fields that was part of the SB 21 tax reform
enacted in 2013. It was available for the first seven years
of production and ended early if North Slope prices
averaged over $70 per barrel for any three years. It also
allowed companies to exclude 20 percent or 30 percent of
the gross value from the net production tax calculation.
Mr. Stickel moved to slide 21, which was a repeat of a
chart from a previous presentation. The chart showed how
unrestricted revenue for FY 24 would change with different
oil prices. He relayed that each dollar change in oil price
equated to about a $70 million change in UGF revenue. The
production tax was progressive in that once the oil price
exceeded $90 per barrel, the per barrel revenue increased.
Similarly, once prices sunk below $70 per barrel, the
companies started paying below the tax floor at a cost of
between $50 and $70 per barrel.
Mr. Stickel advanced to slide 22, which put the information
on slide 21 in table form. The table was taken from
Appendix A from DOR's Revenue Sources Book.
Mr. Stickel continued to slide 23 which was added in
response to a question from the Senate. The slide included
a chart comparing the effective tax rate at a range of
prices for FY 24 to the statutory net tax rate of 35
percent. The lowest effective tax rate was observed at
about $52 per barrel, which was a 9.8 percent effective tax
rate. Once the price exceeded $52 per barrel, the tax levy
increased with the net profits tax. When prices were below
the $52 threshold, the increase also occurred because the
tax was governed by the gross minimum tax floor, which
meant that a company's profits were decreasing faster than
the gross value. He concluded his presentation.
Representative Cronk asked how much of the transportation
costs were the Trans Alaska Pipeline System (TAPS).
Mr. Stickel responded it was about half of the
transportation costs. For FY 24, transportation costs were
forecasted to be about $9.37 per barrel with $4.88 of the
cost being the estimated TAPS portion.
Representative Cronk asked if the transportation costs
would drop if the new oil fields were online.
Mr. Stickel responded that the costs could be stable or
potentially decrease. The department was forecasting fairly
stable transportation costs due to expected moderate
increases in production.
2:40:43 PM
Representative Stapp asked for more detail about the use of
the 50 percent royalty share from NPRA.
Mr. Stickel responded that there was a provision by the
federal government that required that the money be used for
programs and communities that were impacted by the oil
development. He understood that there was a grant program
that the state used to distribute the funds.
Representative Stapp understood that the funds would be
going directly to people like those who had visited his
office recently and spoke about the impacts that oil
production had on their communities. He asked if he was
correct.
Mr. Stickel responded that it would be going to the
impacted communities.
Representative Tomaszewski asked about the disclaimer on
slide 4 and read from it:
Alaska's severance tax is one of the most complex in
the world and portions are subject to interpretation
and dispute.
Representative Tomaszewski asked if the oil companies liked
the tax regime in the state.
Mr. Stickel responded that he would defer the question to
the oil companies. He added that multiple consultants had
reported that Alaska had one of the most complex tax
systems in the world and the uncertainties could create
difficulties.
Representative Tomaszewski asked if the state and the
department liked the tax regime.
Mr. Stickel responded he would defer the question as well
since it was policy related. From a personal standpoint, he
acknowledged that the regime could be tricky and
complicated.
Representative Hannan asked if the tax was complicated due
to the regulations surrounding surface ownership and
subsurface ownership. In most other jurisdictions, the
ownership was unified, but Alaska reserved the subsurface
rights. An additional hurdle was the great distance oil
needed to travel across the state.
Mr. Stickel responded that it was definitely a contributing
factor. An additional factor was that there had been many
changes throughout the years which had complicated the
process.
Representative Cronk commented that he related the oil tax
regime to the Base Student Allocation (BSA) because no one
could explain how it worked.
2:45:22 PM
Representative Tomaszewski asked if the forward lease
expenditures were specific to a particular lease of if the
expenditures could be used on other leases.
Mr. Stickel responded that the carried forward lease
expenditures were tied to a specific lease and a company
needed to bring the lease into production and apply the
lease expenditures in its tax calculation.
Representative Tomaszewski asked if there was a time or
value cap.
Mr. Stickel responded that eight or ten years after the
lease expenditures were earned, they started to decrease in
value if they had not been used. There was not a dollar
amount limit to how much a company could invest to earn the
lease expenditures.
Representative Josephson asked if it was true that using
the carried forward lease expenditures was not prohibited
for a taxpayer like Conoco. He understood that Conoco could
use the expenditures when in profit near Prudhoe Bay or not
in profit in another field. He thought whether or not they
were in profit was a North Slope question.
Mr. Stickel responded that if an existing producer like
Conoco had sufficient gross revenue and made an investment
in a new field, it would be able to apply the lease
expenditures in the year in which the investment was made.
Co-Chair Johnson reviewed the following day's agenda.
2:48:33 PM
ADJOURNMENT
The meeting was adjourned at 2:48 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Order of Operations HFIN 2023.02.09.pdf |
HFIN 2/9/2023 1:30:00 PM |
DOR - HFIN |
| DOR Response to HFIN Order of Ops 2023.02.09.pdf |
HFIN 2/9/2023 1:30:00 PM |