Legislature(2025 - 2026)SENATE FINANCE 532
02/13/2025 09:00 AM Senate FINANCE
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| Start | |
| Presentation: Order of Operations – Department of Revenue | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
SENATE FINANCE COMMITTEE
February 13, 2025
9:01 a.m.
9:01:41 AM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 9:01 a.m.
MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Mike Cronk
Senator James Kaufman
Senator Jesse Kiehl
Senator Kelly Merrick
MEMBERS ABSENT
Senator Donny Olson, Co-Chair
ALSO PRESENT
Dan Stickel, Chief Economist, Economic Research Group, Tax
Division, Department of Revenue; Senator Cathy Giessel.
SUMMARY
PRESENTATION: ORDER OF OPERATIONS DEPARTMENT OF REVENUE
Co-Chair Stedman discussed the agenda. He commented that
the presentation on the order of operation would address
the state's oil and gas tax structure. He commented that
the structure was one of the most complex on the planet.
^PRESENTATION: ORDER OF OPERATIONS DEPARTMENT OF REVENUE
9:04:13 AM
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE, discussed a presentation
entitled "Order of Operations Presentation Senate Finance
Committee" (copy on file). He relayed that the purpose of
the presentation was to provide a high-level overview of
Alaska's oil and gas production tax. The presentation would
focus on Alaska North Slope (ANS) oil. He agreed that there
was a lot of complexity and nuance in the tax code.
Mr. Stickel showed slide 2, "Acronyms," and noted that he
would endeavor to minimize the use of jargon in his
presentation.
Mr. Stickel spoke to slide 3, " Agenda
• Oil and Gas Revenue Sources
o FY 2023 FY 2027 oil and gas revenues
• Production Tax Calculation "Order of Operations"
o Detailed walk-through of for FY 2026
o FY 2023 FY 2027 comparison
• Additional Discussion
o FY 2026 Illustration Challenges
o Examples of spending scenarios and tax impact
o State Revenue by Land Type
o Revenue per $1 of Oil Price and Historical
Context
Mr. Stickel relayed that he would offer a high-level
overview of oil and gas revenue sources for the previous
couple of fiscal years, with projections to FY 27. The
presentation was not intended to be policy but rather
illustrate the nuts and bolts of the fiscal system and set
the groundwork for future discussions. The additional
discussion listed on the slide was related to questions
from the committee.
Mr. Stickel referenced slide 4, " Disclaimer
• Alaska's severance tax is one of the most complex in
the world and portions are subject to interpretation
and dispute.
• These numbers are rough approximations based on
public data, as presented in the Fall 2024 Forecast
and other revenue forecasts.
• This presentation is solely for illustrative general
purposes.
•Not an official statement as to any particular tax
liability, interpretation, or treatment.
•Not tax advice or guidance. • Some numbers may differ
due to rounding.
Mr. Stickel expanded that he was attempting to take a
complex, nuanced tax system and put it in easily
understandable pieces. He noted that he was an economist
rather than an auditor or tax lawyer, and his comments were
not an official tax interpretation.
9:07:53 AM
Mr. Stickel turned to slide 5, "Oil and Gas Revenue
Sources
• Royalty based on gross value of production
o Plus bonuses, rents, and interest
o Paid to Owner of the land: State, Federal, or
Private
o Usually 12.5% or 16.67% in Alaska, but rates
vary
• Corporate Income Tax based on net income
o Paid to State (9.4% top rate)
o Paid to Federal (21% top rate)
o Only C-Corporations* pay this tax
• Property Tax based on value of oil & gas property
o Paid to State (2% of assessed value or "20
mills")
o Paid to Municipalities credit offsets state
tax paid
• Production Tax based on "production tax value"
o Paid to State calculation to follow
Oil and Gas Revenue Sources
* C-Corporation is a business term that is used to
distinguish the type of business entity, as defined
under subchapter C of the federal Internal Revenue
Code.
Co-Chair Stedman asked for Mr. Stickel with help defining
royalty, and whether it applied to gross or net profit.
Mr. Stickel explained that royalty represented the state's
share of oil as a landowner. The royalty would go to the
landowner, which was primarily the state. There was also
oil produced on federal land, and the royalty went to the
federal government. A small portion of the federal royalty
was shared with the state. There was a small portion of
production on private land, and the royalty went to the
private landowner. Most royalty was assessed on a gross
value basis and was typically one-eighth or one-sixth,
which was 12.5 percent or 16 and two-thirds percent of the
value of the oil. There were some royalties that
incorporated a net-profit scheme, which was referred to as
net profit share lease royalties, which were less common.
The royalty represented the state's share of the oil as
landowner, after leasing out the land to companies to do
the production.
Mr. Stickel explained that the severance tax was a levy
that the state assessed as a sovereign for the privilege of
severing resources from the state. There was a net profits
component to the severance tax as well as a gross
component.
9:11:21 AM
Mr. Stickel considered slide 6, "Oil and Gas Revenue
Sources: Five-Year Comparison of State Revenue," which
showed a table with all revenue from oil and gas from FY 23
to FY 27. He noted that the property tax revenue shown was
state share of property tax, and there was an additional
significant amount of over $500 million per year that went
to municipalities. The corporate income tax applied to C
corporations. There was a bit of a reduction between FY 23
and FY 24 primarily due to lowering oil prices as well as
some refunds and one-time impacts in FY 24. He mentioned
production tax, the value of which had dropped quite a bit
over the years due to oil prices and higher company
investment.
Mr. Stickel addressed the royalties shown on the table,
which represented the state share as well as the Permanent
Fund and School Fund shares. The amount represented the
unrestricted and restricted portion of the royalties. He
highlighted two smaller sources of revenue. The
Constitutional Budget Reserve Fund (CBR) Settlements, which
were any settlements from oil and gas disputes. The Natural
Petroleum Reserve-Alaska (NPRA) shared revenue was half of
royalties received by the state from the NPRA were shared
with the state and had special restrictions on spending.
The funding functioned similarly to a pass-through to
impacted communities. The revenue was expected to increase
quite a bit beyond the time horizon of the slide as new
developments such as Willow came online in the NPRA.
Co-Chair Stedman asked for more detail on why there was
$1.6 billion more to balance the budget in 2023.
Mr. Stickel relayed that the primary driver for the higher
oil and gas revenue in FY 23 was the ANS oil price shown on
the first line. He noted that $86.63 per-barrel (bbl) was a
fiscal year average. Prices throughout the year showed
higher value months earlier in the fiscal year. The state
had a very progressive production tax system and generated
quite a bit more revenue when prices were high.
Co-Chair Stedman thought the difference was important to
point out while working on the budget and observing the
difference in revenue. He summarized that the difference
was primarily due to price.
Mr. Stickel affirmed that the difference was primarily a
function of price but was also a function of increased
investment by certain taxpayers.
9:16:05 AM
Mr. Stickel displayed slide 7, "Fiscal System: Overall
Order of Operations," which showed a high-level flow chart
of the order of operations. The chart showed how the
elements of the oil and gas fiscal system were applied.
Royalites were first, and the landowner got their share of
the resource off the top before calculating of any taxes
levied. State and local property taxes came second and were
considered lease expenditures or allowable costs for the
production tax and other tax calculations. Production tax
came after royalties and allowed a deduction for property
tax and came before calculation of corporate income tax.
Mr. Stickel continued and discussed state corporate income
tax, which used worldwide income as part of the tax base.
Property taxes and production taxes were excluded from the
calculation of worldwide income. Lastly came federal
corporate income tax. All state taxes were allowed as
deductions against the federal corporate income tax,
including any state corporate income tax paid.
Co-Chair Stedman asked about state corporate income tax,
and why the tax counted revenue all over the planet.
Mr. Stickel thought he was not the person to best elucidate
the policy decision of how the state did the apportionment.
Co-Chair Stedman asked Mr. Stickel to provide a high-level
answer. He discussed apportionment, which he thought was
started under the Hammond Administration.
Mr. Stickel reiterated that he was not a tax lawyer. He
mentioned that for determining corporate income tax, there
were a few options. There was an option for separate
accounting, in which a company would account for all its
revenues and expenditures in the taxing jurisdiction, which
was similar to what the state did for production tax
calculation. The state chose to look at all of a company's
revenue and expenditures all around the world and determine
what share was attributable to Alaska. He recalled that at
one point the state had shifted the Alaska-specific
methodology and separate accounting and there had been
litigation. Ultimately the state had prevailed, and the
court allowed the state to use the separate accounting
methodology, however the state had chosen to retain the
apportionment methodology for corporate income tax.
9:20:34 AM
Mr. Stickel highlighted slide 8, "Production Tax "Order of
Operations": FY 2026," which showed a table showing gross
oil production and price down to total tax paid to the
state at the bottom. He noted that several slides would
address the topic. The information was based on the income
statement as presented in Appendix E of the Revenue Sources
Book (RSB). The table walked through the FY 26 production
tax calculation and was focused on ANS oil, as it was the
largest portion of the state's oil and gas production tax
revenue. He highlighted the $70/bbl oil Department of
Natural Resources (DNR) forecast price, and a production
forecast of 469,000/bpd, which calculated out a value of
$33 million per day or about $12 billion for the year. He
noted that the focus of the next several slides was taking
the annual value of $12 billion of oil and looking at how
it was taxed and split between the different components.
Co-Chair Stedman referenced property tax and noted that the
committee was viewing the presentation from the state's
perspective. He pondered how a company's perspective on
property tax would differ.
Mr. Stickel explained that property tax was a cost of
operation and equated to 2 percent of value or 2 mills of
tax. The state allowed for a deduction for property taxes
in the production tax calculation, to the extent that the
tax was levied on pipeline structure or production and
exploration infrastructure.
Co-Chair Stedman asked if the state looked at property tax
disregarding who ended up with the property. He thought
sometimes people looked at only the state's portion, which
he thought could lead to confusion. He surmised that for a
company, the property tax recipient did not matter but it
was an expense.
Mr. Stickel answered affirmatively.
9:24:06 AM
Senator Kiehl asked if the oil and gas property tax
included everything a company owned, including a building
in Anchorage or a company truck. He referenced pipelines
and field infrastructure.
Mr. Stickel explained that the oil and gas property tax
applied to exploration and production property. The
building Senator Kiehl mentioned would not be subject to
the oil and gas property tax.
Senator Kiehl did not think there was a slide on how the
tax structure treated other municipal taxes such as taxes
on office buildings.
Mr. Stickel emphasized that the oil and gas property tax
was accounted for and allowed as a lease expenditure. Other
administrative overhead expenses were not directly
accounted for, although there was an allowance for
overhead. The production tax calculation allowed for a 4.5
percent overhead allowance that was treated as an operating
expenditure.
Senator Kiehl requested that Mr. Stickel make note of the
allowance when addressing the production tax calculation.
Co-Chair Stedman thought some of the items would not show
in the calculation. He mentioned that the state used the
Internal Revenue Service (IRS) definition of capital
expenditures.
Mr. Stickel agreed and noted he would be addressing more on
the topic on slide 11.
Mr. Stickel looked at slide 9, "Production Tax "Order of
Operations": FY 2026," which showed the same table as the
previous slide, but focused on the first step of the tax
calculation with royalty and taxable barrels. He explained
that royalty barrels were subtracted from the tax
calculation regardless of the owner. Typical rates were
one-eighth or one-sixth of value, but rates did vary. For
purposes of the production tax calculation, the state
subtracted federal and private land royalty as well as the
small number of barrels that were not subject to tax due to
being in offshore federal waters beyond the 3-mile limit.
Subtracting the items from total production arrived at the
taxable barrels calculation of about 149 million barrels in
FY 26, for a total taxable value of about $10.5 billion.
9:28:06 AM
Mr. Stickel addressed slide 10, "Production Tax "Order of
Operations": FY 2026," which showed the same table as the
previous slide, but focused on the second step of the tax
calculation by addressing the gross value at point of
production (GVPP), also known as well-head value. He
relayed that the concept was widely used in both the tax
calculation as well as the royalty calculation in
determining the gross value. To get to gross value,
transportation costs were subtracted, which included all of
the costs of getting oil from the wellhead on the North
Slope to market, typically on the West Coast. The official
ANS price was priced in Long Beach, California. The
calculation deducted marine transportation costs, the
Trans-Alaska Pipeline System (TAPS) tariff, and any feeder
pipeline tariffs or miscellaneous adjustments. For FY 26,
the transportation costs were estimated to amount to
$10.38/bbl, which left an average wellhead value of
$59.62/bbl, with a total gross value for tax purposes of
$8.9 billion.
Mr. Stickel advanced to slide 11, "Production Tax "Order of
Operations": FY 2026," which showed the same table as the
previous slide, with lease expenditures highlighted. He
noted that production tax was essentially a modified
version of a net profits tax. The state allowed companies
to deduct costs of operation when calculating the net
profits. For capital expenditures, the state generally used
IRS guidelines. The expenditures were typically investments
that had a lifespan of a year or more. He noted that the
state did not have a depreciation calculation for capital
expenditures. Companies were allowed to immediately deduct
all capital costs in the year in which the costs were
incurred. Operating expenditures were any allowable
expenditures other than capital expenditures, typically the
ongoing costs of operations and labor, including property
tax and an allowance for overhead.
Mr. Stickel noted that there were two terms to understand
on the slide. He addressed allowable lease expenditures,
which were any of the costs directly associated with
production of the oil that were allowed in the tax
calculation. There were some items that were specifically
excluded, including financing costs, costs of acquiring
leases, and dismantlement costs. He addressed deductible
lease expenditures, an unofficial term developed by the
Department of Revenue (DOR) that referenced that portion of
the allowable lease expenditures that were applied to the
tax calculation in the year incurred up to the gross value.
He pondered how much of the lease expenditures reduced the
tax calculation. He explained that to the extent that a
company did not have sufficient gross value to apply the
lease expenditures in the tax calculation, any additional
lease expenditures became carry-forward lease expenditures,
which could potentially reduce a future years' taxes.
9:33:07 AM
Co-Chair Stedman thought it was important to note that when
considering deductibility, some expenditures that were not
deductible as lease expenditures but were deductible under
federal income tax. Capital expenditures were fully
deductible under the state tax structure but were spread
out in the corporate tax environment. He clarified that
there was not "double dipping" happening. He mentioned
severance tax.
Senator Kiehl mentioned operating expenditures and 4.5
percent for overhead including local taxes. He asked
whether the state's oil and gas corporate income tax was
deductible.
Mr. Stickel referenced the overall order of operations and
noted that the production tax came before corporate income
tax.
Senator Kiehl referenced things that were disallowed from
being deductible. He asked about advertising and lobbying,
and whether the expenses were excluded.
Mr. Stickel thought the items would be categorized as
"overhead," and would not be costs directly associated with
producing or exploring for oil and gas.
Senator Kiehl asked if the items were excluded.
Mr. Stickel thought the items would be excluded from
allowable lease expenditures, as they were not considered
direct costs of exploring for or producing oil and gas. The
overhead allowance was intended to account for all
ancillary expenditures above and beyond exploring for and
producing oil and gas.
Mr. Stickel continued to address slide 11 and summarized
that there was an estimated $7.6 billion of allowable lease
expenditures in FY 26. He pointed out that $6.5 billion was
forecast to be deducted in the tax calculation. The last
line showed a forecast of $1.1 billion in lease
expenditures in FY 26 to be not deducted and carried
forward as lease expenditures to offset a future year's
tax.
Co-Chair Stedman asked about carry-forward expenditures.
Mr. Stickel affirmed that there were some examples in the
presentation. He offered that in a nutshell, if a company
did not have sufficient gross value of production to apply
all of its lease expenditures, the state allowed to carry
the expenditures forward and potentially offset a future
year's tax liability. He mentioned a new entrant that was
developing a field and would potentially get benefit from
the spending similar to the way an existing producer would.
He thought the concept could be counter-intuitive and
mentioned that there were three examples towards the end of
the presentation that looked at what happened with
different companies making investments in the state and how
the companies benefitted from the lease expenditures.
9:38:08 AM
Mr. Stickel looked at slide 12, "Production Tax "Order of
Operations": FY 2026 which showed the same table as the
previous slide, but focused on the calculation of the
production tax value (PTV), which was the gross value minus
the deductible lease expenditures. He described a "slope-
wide ring fence," in which each company calculated its
production tax value based on its all its slope-wide
activity, including all fields and developments. The
concept was important since each company operating in the
state had a different portfolio of producing properties and
investments. He cited that the production tax value worked
out to roughly $16/bbl or about $2.4 billion total for FY
26.
Co-Chair Stedman thought it was an important point that in
the scenario Mr. Stickel described he had referred to three
companies with varying levels of profitability. He noted
that the legislature received company data in an aggregated
fashion, despite the companies having different structures.
He thought it was challenging when the legislature set
policy to consider a tax structure to fit the variability.
He referenced companies testifying indifference to the tax
policy, while others expressed favor or disfavor. He
thought it was an important nuance.
Mr. Stickel showed slide 13, "Production Tax "Order of
Operations": FY 2026," which showed the same table as the
previous slide, but focused on the gross minimum tax floor.
He described two calculations done side-by-side, after
which the company paid the state the higher of the two. The
minimum tax floor was four percent of gross value anytime
annual oil prices were greater than $25/bbl. In the chance
that oil prices were lower on an annual average, there was
a graduating scale of lower minimum tax rates. For FY 26,
in the aggregate there was a projected gross value of $8.9
billion. At the 4 percent minimum tax floor there was a
minimum tax of about $356 million. The minimum tax was
compared to the net tax (shown on slide 14). The net tax
took a 35 percent statutory tax rate and applied it to the
PTV to determine the tax before credits, which was the
higher of the net tax or gross tax. The department was
forecasting that the tax before credits would be a net tax
of about $843 million.
9:42:43 AM
Mr. Stickel advanced to slide 14, "Production Tax "Order of
Operations": FY 2026," which showed the same table as the
previous slide, but focused on the net tax and gross value
reduction (GVR). The state was not forecasting the GVR
would affect the gross value reduction in FY 26. The GVR
was a benefit for companies that were developing a new
field, under which it could exclude 20 percent or 30
percent of the gross value of production from qualifying
new fields in the calculation of production tax value. The
next tax was calculated after any applicable reduction for
the GVR. The department did not forecast that the GVR would
impact the production tax calculation for FY 26.
Co-Chair Stedman acknowledged that Senator Cathy Giessel
was in attendance.
Mr. Stickel turned to slide 15, "Production Tax "Order of
Operations": FY 2026," which showed the same table as the
previous slide, but focused on tax credit against
liability. He explained that after calculating tax before
credits on the previous slide, then any tax credits against
liability would be applied. The major credits in the system
included two versions of per-taxable-barrel credits. One
version was for non-GVR eligible oil for fields that had
been in production for several years. The fields had a
sliding scale of per-taxable-barrel credit that ranged from
zero (when the wellhead value was greater than $150/bbl) up
to $8/bbl (when the wellhead value was less than $80/bbl).
Mr. Stickel relayed that in FY 26 and throughout the time
horizon of the revenue forecast, DOR was forecasting that
companies would generate the full $8/bbl sliding scale tax
credit. There was a separate flat $5/bbl tax credit that
was generated for GVR-eligible production. A company could
only use the sliding scale credits to reduce tax liability
down to the minimum tax floor. If the company chose to
forego sliding scale credits or was a new producer not
generating any sliding scale credits, the company could use
the other credits to reduce the tax below the minimum tax
floor.
Mr. Stickel continued that for FY 26, DOR was estimating
that $1.19 billion worth of per-taxable-barrel credits
would be generated and was forecasting that $572 million of
the amount would be used against the tax calculation. A
little over half of the generated credits were forecast to
be foregone, and then could not be cashed out or carried
forward. The average credit value per barrel was estimated
to be between $2.33/bbl for the GVR-eligible credits, and
an average of $3.86/bbl that was realized for the sliding
scale tax credits.
9:47:30 AM
Senator Kiehl asked Mr. Stickel to discuss how the credit
functioned. He asked whether companies could make a profit
at $90/bbl.
Mr. Stickel explained that the calculation of the tax
credit, and how much was generated, was irrespective of
profit and was based on the wellhead value. The sliding
scale credit was $8 per taxable barrel when the wellhead
value (the gross value) was $80/bbl or lower. Given
transportation costs, the price roughly equated to a
$90/bbl market price. The ability of the company to apply
and realize the full benefit of the tax credit would depend
upon profitability. He mentioned that there were examples
later in the presentation. He mentioned that of the $8/bbl
that was forecast to be generated, only about $3.86 of the
amount on average would actually end up reducing taxes.
Co-Chair Stedman asked about the tax floor and "leaks" in
the floor.
Mr. Stickel mentioned the gross minimum tax floor of 4
percent of gross value. If a company applied any sliding
scale tax credits, it could not reduce its tax liability
below the minimum tax floor. However, if a company did not
apply slidingscale tax credits, it could use other tax
credits to go below the minimum tax floor.
Co-Chair Stedman asked if Mr. Stickel would address the
credits that went under the minimum tax floor.
Mr. Stickel explained that the other credits would
primarily be per-taxable-barrel credits for GVR-eligible
oil. If there was a new entrant that did not have sliding-
scale tax credits, for the first three to seven years of
production would receive the GVR and would receive a $5/bbl
credit that it could use to pay below the minimum tax
floor. He mentioned the small producer credit, which was
phasing out in the next few years but could be applied to
go below the minimum tax floor.
9:50:48 AM
Mr. Stickel considered slide 16, "Production Tax "Order of
Operations": FY 2026," which showed the same table as the
previous slide, but focused on some other items that were
incorporated into production tax revenue received by the
state in a given tax year. He listed prior year taxes or
refunds, taxes on Cook Inlet oil and gas, gas on the North
Slope, and a conservation surcharge. The primary item
included in FY 26 was adjustment for company-specific
issues. He mentioned companies that were in very different
tax situations, which resulted in total tax paid to the
state being different than taking an aggregate calculation.
He identified that for the order of operations chart, there
was about a $180 million difference. The adjustment item
trued up the aggregate calculation to the actual revenue
that DOR was forecasting. He identified that the per-barrel
credits and minimum tax floor being two key components.
Mr. Stickel displayed slide 17, "Order of Operations: Five
Year Comparison," which showed the same analysis of
previous slides but shown over a five-year period. For FY
23, there was a net profit of about $7.5 billion, and about
$1.5 billion of total tax paid to the state for an
effective tax rate of about 20 percent. He pointed out the
effective tax rate on the bottom line as being fairly
stable, with a roughly 19 percent effective tax rate in FY
27, based on a lower production tax value of about $2.2
billion and a lower tax paid to the state of about $427
million. He considered the five years and discussed changes
in components, with lower production value and gross value
based on changes in oil price, quite a bit higher lease
expenditures based on increased company spending on new
investments. The combination of two factors led to the
reductions in estimated profit or production tax value.
9:54:22 AM
Mr. Stickel highlighted slide 18, "Question: Why Doesn't
the FY 2026 Tax Calculate Exactly?" He noted that the
previous slides had been the main presentation, while the
next several slides walked through specific issues in the
current year, and some questions DOR had received. He
pondered the question of why the tax didn't calculate out
perfectly for FY 26. He explained that if one just looked
at the aggregated calculation, versus the forecast for
production value, there was a roughly $180 million
difference which had to do with the significantly different
tax situations for each of the companies operating in the
state. He discussed the aggregated tax illustration, which
was done to try and tie to specific numbers as possible.
The per-taxable-barrel credits were higher in the company-
specific calculations than they were in the aggregate
calculation. He explained that some companies were able to
realize the full $8/bbl credit and were paying tax revenue
above the floor. Other companies were able to utilize less
than the $8/bbl and some companies were not able realize
any per-taxable-barrel credits at all.
Mr. Stickel explained that tax paid to the state was higher
when calculated on a per-company basis than the aggregate
calculation, because some companies paid the minimum tax
floor and each individual company completed the "higher of"
calculation. Some companies ended up paying the state more
due to the minimum tax floor than they would if based on
the net tax calculation minus credits. He noted that there
were a couple of examples that would walk through how the
structure would work for different companies.
Co-Chair Stedman noted that previously it was possible to
calculate the numbers more closely.
Mr. Stickel explained that the change had to do with some
of the major investments taking place, as well as the
position of oil price. He mentioned that at an oil price of
about $70 /bbl, the state was very close to the threshold
between companies paying at the minimum tax floor and
paying above the minimum tax floor, which made the
calculation more challenging.
9:58:44 AM
Mr. Stickel noted that the following couple of slides
showed examples of how a company's tax situation could vary
depending on its portfolio of producing properties and
investments. He noted that the slides were not intended to
reflect any particular producer. He looked at slide 19,
"Example 1: Low-Cost Producer," which showed a table that
assumed a company with 50,000 bpd of production. The
example considered lease expenditures that were lower than
the slope-wide average, and the company would be paying the
net profits tax. The lease expenditures were $24/bbl,
giving a production tax value of about $35/bbl. The net
profits tax would be $588 million, and the company would be
able to utilize the full value of all per-taxable-barrel
credits to reduce tax liability down to about $208 million,
still paying above the minimum tax floor.
Mr. Stickel addressed slide 20, "Example 1a: Low-Cost
Producer w/ Increased Spending of $100 Million," which
showed the same table as the previous slide, using the
assumption that the company paid $100 million of additional
lease expenditures. Under the scenario, the company still
ended up paying above the minimum tax floor. The tax due
went from $209 million to $172 million. The $100 million
additional investment gave a 36.6 percent tax benefit,
while still paying above the minimum. The company was able
to deduct the $100 million as a lease expenditure, plus the
overhead allowance on the $100 million.
Mr. Stickel advanced to slide 21, "Example 2: Mid-Cost
Producer," which showed the same table and example of the
previous slide, but using a company with 150,000 bpd of
production with an average cost structure. The company
operated a mix of fields and was making investments into
developing new fields. Under the example, the producer had
a tax before credits of $266 million, which was the next
tax. It earned the same $380 million of per-taxable-barrel
credits as the first example but were only able to use $152
million of the credits in the tax calculation. The company
was limited by the minimum tax floor and so ended up paying
the state the $114 minimum tax floor. The company only
realized $3.24/bbl of per-barrel tax credits versus the
$8/bbl on the prior example.
10:02:57 AM
Mr. Stickel looked at slide 22, "Example 2a: Mid-Cost
Producer w/ Increased Spending of $100 Million," which
showed the same table and example of the previous slide,
but showing an additional $100 million investment. With
additional investment, the company still paid the minimum
tax floor. The company would reduce its net profits tax but
would be also able to use less per-taxable-barrel credits
to get down to the minimum tax. For the company's $100
million additional investment, it received no tax benefit.
Since it had a positive production tax value, it also
earned no carry-forward lease expenditures.
Mr. Stickel spoke to slide 23, "Example 3: New Entrant,"
which showed the table example depicting a new entrant
without current production. The example could also be an
existing producer with very high investment expenditures
relating to whatever current production it did have. The
new entrant would pay no tax to the state but would earn a
carry forward for the expenditures it was making. The
example showed $1 billion in expenditures plus the overhead
uplift, generating a $1 billion and $45 million carry-
forward lease expenditure that could potentially be used to
offset a future year's tax liability.
Mr. Stickel referenced slide 24, "Example 3a: New Entrant
w/ Increased Spending of $100 Million," which showed the
table depicting the example of a new entrant with $100
million of additional spending. The new entrant would get
to increase the value of its carry-forward lease
expenditure by the $100 million plus the uplift. The
company would get a potential 35 percent benefit by the
spending in a future year.
Senator Kiehl asked if the company would get a benefit from
new barrels produced.
Mr. Stickel answered affirmatively.
Senator Kiehl asked if there was an allowance for new
production.
Mr. Stickel noted that the state offered the GVR, which was
a benefit in the production tax calculation for new
barrels, in which a company could reduce the net profits
tax portion of the tax calculation for up to three to seven
years of production.
Senator Kiehl asked if the amount was additive to the
carry-forward benefits.
Mr. Stickel affirmed that the company would get both
benefits, which showed up in different places in the tax
calculation.
10:06:25 AM
Mr. Stickel turned to slide 25, "Three Production Tax
Situations
• Low cost producer
•All lease expenditures applied in tax
calculation
•Full benefit of per-taxable-barrel credit
•Pays above minimum tax floor (net tax)
• Higher cost producer
•All lease expenditures applied in tax
calculation
•Zero or partial benefit of per-taxable-barrel
credit
•Pays at minimum tax floor
•No benefit for additional lease expenditures
"the Donut Hole"
• New entrant
•No lease expenditures applied in tax calculation
•Zero benefit of per-taxable-barrel credit
•Pays no tax, earns carry-forwards
Mr. Stickel noted that the slide summarized the three
previous examples. He explained that most major companies
working on the slope fell into one of the three categories
listed on the slide. He described what was termed a "donut
hole," in which there was one group of companies that would
benefit from new investment (the lower cost producers), one
group that would benefit as a new entrant earning carry-
forwards, and then a group of companies in the middle that
would not get any additional benefit from investment within
a certain range because of the position of profitability
and minimum tax.
10:08:35 AM
Mr. Stickel considered slide 26, "State Petroleum Revenue
by Land Type," which showed a table of how petroleum
revenues to the state varied by land type. He relayed that
DOR had received a question related to the revenue impact
of new developments such as Willow, and how the state's
revenues compared to other production in the state. The
slide showed how the petroleum revenues varied by land
type. He noted that there was a version of the slide in the
RSB. For any oil produced in federal waters more than six
miles offshore, the state would not receive any direct
revenue, and there was currently no production in the
category. For any oil produced within three to six miles
offshore, the state received 27 percent of the federal
royalty, but state taxes would not apply. The only
production on the North Slope that fell into the category
was a small portion for North Star.
Mr. Stickel continued that for anything on state land and
up to three miles offshore, all state taxes applied
regardless of land ownership. For any land within the
three-mile limit, royalty applied and depended upon
landowner. The state collected a direct royalty on state-
owned land. For federal owned land and the NPRA, the
federal royalty applied, and the government shared 50
percent back to the state. The state had to use the funds
to support impacted communities, which was essentially
pass-through revenues for the NPRA. He added that for
federal owned production in the Alaska National Wildlife
Refuge (ANWR), under current law the federal government
shared 50 percent of revenues back to the state with no
spending restrictions. For other federal land, the federal
royalty applied, and 90 percent would be shared back to the
state with no restrictions. There was currently no land in
the category.
Mr. Stickel continued that for private land, which was
primarily Native corporation owned land, there was a
privately negotiated royalty. The state did not get a
direct share of the royalty but did levy a tax on private
landowner royalty value as part of production tax.
Co-Chair Stedman thought it would be helpful if the table
on slide 26 had an additional column that showed the number
of estimated barrels for each land type.
10:12:13 AM
Senator Kiehl referenced Mr. Stickel's earlier comment that
new barrels provided a benefit to all. He pointed out that
as he looked at the chart, it looked as though the state
provided all the credits whether the state got a royalty or
not and no matter what the share to the state from the
federal government. He thought it would be different if the
state had a structure in which all the new barrels paid all
the taxes. He thought the return to the state was highly
dependent upon where the oil came from.
Mr. Stickel affirmed that the value to the state was
dependent upon the source of the oil. He referenced the
slide and noted that state land had the oil that belonged
to the state and naturally received a higher value. He
referenced a white paper and analysis on the department's
website that looked at the Willow project in particular
that indicated the new projects were beneficial to the
state. He mentioned the benefit of new development being
more oil going through the pipeline, allowing the cost of
the pipeline to be spread amongst a greater number of
barrels, making the barrels more valuable.
Senator Kiehl understood the dynamic. He referenced earlier
slides that looked at $10.50 downstream costs. He thought
the value got thin quickly.
Co-Chair Stedman asked Mr. Stickel to provide the document
he referenced. He thought the concern referenced by Senator
Kiehl that "all oil was not equal" was frequently raised.
10:16:15 AM
Mr. Stickel displayed slide 27, "Petroleum Detail: UGF
Relative to Price per Barrel (without POMV), FY 2026*,"
which showed a graph that showed how unrestricted revenue
for FY 26 could change with different oil prices. He
mentioned questions about how state revenue might change
with higher or lower oil prices than what was forecast. He
cited that near the forecast price, a $1 increase or
decrease led to about a $35 million change for revenue in
FY 26.
Co-Chair Stedman mentioned that one of the issues that had
yet to be explained to the public was the source of
information related to companies' expenditures. He asked
Mr. Stickel to provide information on how often DOR
interacted with industry.
Mr. Stickel explained that DOR had a very robust set of
filing requirements for companies and received monthly
information filings with an incredible amount of detail
included to support tax calculations. There were annual
filings that trued up the entire year of tax information.
The submissions were the basis for actual and historical
data from companies. There were two supplemental tax
filings for the economic research group. One was a
production forecast filing with details about future
production plans and was collected once per year in
collaboration with DNR. There was a cost-forecast filing,
through which companies submitted projections and
documentation for operating and capital cost on a unit-
specific basis that was collected twice per year.
Mr. Stickel described conversations and written outreach to
companies. For some companies there were follow-up
meetings, on an as-needed basis, that were in collaboration
with DNR. The production outlook was a ten-year outlook and
the cost outlook was a five-year outlook with additional
information gathered through meetings and written
responses.
10:20:34 AM
Mr. Stickel highlighted slide 28, "Question: Why Only about
$35 million per $1 ANS Change?
•Comparing to several years ago when the rule of thumb
was closer to $100 million
•Somewhat lower production impacts tax and royalty
•Somewhat more non-state-land production impacts
royalty
•Somewhat more non-C-corp production impacts
corporate tax
•Progressive production tax
•Lower price especially in real terms
•Higher lease expenditures
•More companies at minimum tax floor
Mr. Stickel noted that the slide built on the previous
slide. He highlighted the progressive production tax
system, emphasizing that oil prices were lower and costs
for investment were higher, so there was a lot less profit
in the system to tax. He referenced the five-year
comparison with over $7 billion in production tax value
going down over five years to just over $2 billion in
production tax value. There were more companies paying at
the minimum tax floor. When at the minimum tax floor, a
change in oil price only benefited the state 4 percent.
When above the minimum tax floor, the state benefitted 35
percent of the change in oil price. All of the impacts led
to the $35 million rule of thumb being used for FY 26. At
higher oil prices such as $110/bbl or higher, the heuristic
would be closer to a $75 million impact for every dollar
change in oil price.
Co-Chair Stedman asked about the $75 million impact for
every $1 change in oil price.
Mr. Stickel affirmed that if the oil price was over
$110/bbl there would be a $75 million impact.
Co-Chair Stedman thought expenditures on development of the
North Slope had made a big impact.
Mr. Stickel agreed and considered that all the impacts
together had brought the state to the $35 million impact he
referenced.
Co-Chair Stedman asked if Mr. Stickel had any good news.
Mr. Stickel affirmed that oil prices had been running
slightly above the forecast, and he hoped to bring more
good news later in the session.
Co-Chair Stedman hoped for DNR and DOR to make productions
as accurately as possible without skewing to the positive
or negative based on political considerations. He asked if
Mr. Stickel could recall the first time he had given the
presentation in Senate Finance.
Mr. Stickel could not recall but thought it had been at
least a decade.
Co-Chair Stedman thanked Mr. Stickel for his work and
appreciated the layout of his presentation. He noted that
the committee had asked the pension actuary to follow the
structure used by Mr. Stickel in his presentation.
Mr. Stickel looked at slide 29, "THANK YOU":
Dan Stickel
Chief Economist
Department of Revenue
[email protected]
(907) 465-3279
ADJOURNMENT
10:27:01 AM
The meeting was adjourned at 10:26 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 021325 S.FIN Order of Operations.pdf |
SFIN 2/13/2025 9:00:00 AM |
|
| 021325 DOR Response to SFIN Order of Operations presentation 02.27.25.pdf |
SFIN 2/13/2025 9:00:00 AM |