Legislature(2021 - 2022)SENATE FINANCE 532
03/02/2022 09:00 AM Senate FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Presentation: Oil & Gas Severance Tax - Order of Operations | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
SENATE FINANCE COMMITTEE
March 2, 2022
9:01 a.m.
9:01:02 AM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 9:01 a.m.
MEMBERS PRESENT
Senator Click Bishop, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Donny Olson
Senator Bill Wielechowski
Senator David Wilson
MEMBERS ABSENT
Senator Lyman Hoffman
Senator Natasha von Imhof
ALSO PRESENT
Dan Stickel, Chief Economist, Economic Research Group, Tax
Division, Department of Revenue.
SUMMARY
^PRESENTATION: OIL & GAS SEVERANCE TAX - ORDER OF
OPERATIONS
9:01:27 AM
Co-Chair Stedman explained that the committee would hear a
presentation from the Department of Revenue (DOR) on oil
and gas severance tax. The committee would consider the
order of operations and how the state's oil and gas
severance tax was structured. He emphasized that the
states oil tax structure was one of the most complex in
the world. The committee would consider FY 22 and FY 23,
and the following day would hear testimony from consultants
regarding the state's competitive position of its oil basin
compared to other basins in the world.
9:03:24 AM
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE, discussed the presentation
"Order of Operations Presentation - Senate Finance
Committee" (copy on file). He stated that the purpose of
the presentation was to provide a high-level overview of
how the oil and gas production tax worked for the North
Slope.
Mr. Stickel showed slide 2, "Acronyms":
ANS Alaska North Slope
ANWR Arctic National Wildlife Refuge
Avg Average
Bbl Barrel
CBRF Constitutional Budget Reserve Fund
CIT Corporate Income Tax
DOR Department of Revenue
FY Fiscal Year Acronyms
GVPP Gross Value at Point of Production
GVR Gross Value Reduction
NPR-A National Petroleum Reserve Alaska
OCS Outer Continental Shelf
PTV Production Tax Value
SB21 Senate Bill 21, passed in 2013
TAPS Trans Alaska Pipeline System
Ths - Thousands
Co-Chair Stedman asked Mr. Stickel to try not to use
acronyms as much as possible to ensure the public could
easily understand what was being discussed.
Mr. Stickel agreed.
Mr. Stickel spoke to slide 3, "Agenda":
?Oil and Gas Revenue Sources
o How production tax fits in
o FY 2020 FY 2024 oil and gas revenues
?Production Tax Calculation "Order of Operations"
o Detailed walk-through of each step of tax
calculation
o Defining commonly used terms
o Focus on North Slope oil
o FY 2020 FY 2024 comparison
Co-Chair Stedman thought the presentation was more of a
mechanical discussion, while the discussion planned for the
following day would address the merits of policy in detail.
9:06:43 AM
Mr. Stickel referenced slide 4, "Overview":
?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 2021 Revenue
Sources Book 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 cautioned that the presentation attempted to
take a very complex tax system and break it in to
understandable pieces. The data used aggregated numbers
amongst all the companies doing business on the North
Slope, while official revenue forecasts modeled on a
company-specific basis. He noted he was an economist rather
than an auditor and his comments were not an official tax
interpretation.
Co-Chair Stedman asked Mr. Stickel to expand on the comment
that the numbers used were in aggregate.
Mr. Stickel explained that there were multiple producers
and companies doing business in the state, and there were a
few major producers on the North Slope. He continued that
when DOR did its official revenue forecast, it was modeling
each individual producers tax liability using confidential
tax information. Due to the confidentiality provisions in
state statute, the department was not allowed to release
any information that would identify the particulars of any
taxpayer, so when information was presented to the
legislature or the public, all of the companys information
was aggregated into a single set of numbers.
Co-Chair Stedman asked if the weekly, monthly, and daily
data was rolled up into individual corporations and then
consolidated into an annual figure. He thought that the
information was what the legislature had in order to set
policy.
Mr. Stickel agreed.
Co-Chair Stedman mentioned that it was a challenge that the
data did not necessarily reflect any individual company,
while in many circumstances the state had looked at changes
to the structure that may affect companies in different
ways. He commented on the challenge on setting consolidated
policy for the basin or the state that all of the producers
would be favorable to. He thought there were differences
amongst the companies.
Mr. Stickel agreed that each company had a different
portfolio of operations and a different cost structure, and
the impacts of policies would vary between companies.
Co-Chair Stedman wanted to set to the stage as to why there
was so much discussion on the topic over the years.
9:10:11 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.
Mr. Stickel noted that there was an upcoming slide that
described how the royalty provisions differed for all the
different forms of land in the state. He explained that the
production tax applied to any production within the state
and within the three-mile limit regardless of land
ownership.
Co-Chair Stedman asked Mr. Stickel to explain why there was
a royalty and production tax, and to define the components.
Mr. Stickel explained that royalty was the payment to the
landowner. The state leased land to companies that would
make investments to develop the oil and gas on the land and
would typically pay an upfront bonus bid for the initial
right to do exploration and development. Additionally, the
company would pay an ongoing rental for use of the land and
would pay a royalty interest as production came out of the
ground. He qualified that the royalty interest would be set
at the time the leases were issued, and for most leases on
state land the royalty was 12.5 percent. The production tax
was a more general tax for the privilege of producing oil
and gas in the state.
Co-Chair Stedman asked if the royalty was by contract.
Mr. Stickel answered affirmatively.
Co-Chair Stedman noted that the legislature did not change
royalty rates but did have policy discussions and
modifications of the production tax. He reminded that the
state had royalty contracts that went back to the 1960s or
perhaps even earlier. He thought the contracts were
transferrable. He mentioned the oil company BP transferring
its contract to a new operator.
Mr. Stickel thought Co-Chair Stedman was correct.
9:14:00 AM
Mr. Stickel considered slide 6, "Oil and Gas Revenue
Sources: Five-Year Comparison of State Revenue," which
showed a table of all the sources of state revenue from oil
and gas from FY 20 up through a forecast of FY 24. He noted
that the property tax revenue shown was indicative of the
state's share. Additionally, there was a much larger number
in the $400 million to $500 million range that went to
municipalities. The corporate tax applied only to C
corporations. There were some temporary impacts for revenue
in FY 20 and FY 21, which related to low oil prices and
some federal tax changes related to the Covid-19 recovery
act.
Mr. Stickel discussed royalty information, which included
bonuses, rents and interest, the states Unrestricted
General Fund (UGF) share of royalties, and the
constitutionally dedicated share of royalties that went to
the Permanent Fund and the School Fund. He mentioned
settlements to the Constitutional Budget Reserve (CBR)
Fund, based on any assessments or disputes of prior years'
production tax royalty or other oil and gas minerals taxes.
The last category was shared revenue from the Natural
Petroleum Reserve-Alaska (NPRA), which was the 50 percent
share of any bonuses, rents, or royalties that the federal
government received for production in the petroleum
reserve. There were special restrictions as to how the
funds could be used by the state, and the revenue source
had been historically small. He expected the revenue source
to be larger in the future as additional production came
online.
Co-Chair Stedman asked if the NPRA royalties flowed through
the state to the impacted local communities in the area.
Mr. Stickel affirmed that the state administered a grant
program to direct the revenue to impacted communities on
the North Slope.
Mr. Stickel noted that the revenue numbers in the
presentation looked at current law and current year tax
liabilities and fiscal impacts. He mentioned the issue of
tax credits left over from prior tax regimes and available
for state purchase. He cited that there was about $565
million in outstanding tax credits available for state
purchase as of January 1, 2022. He relayed that the
presentation did not address the outstanding liability for
past tax credits.
Co-Chair Stedman noted he had asked Mr. Stickel to
delineate the topic so it was clear to see the flow of the
tax structure in any given year. There was accrued
liabilities from the past that had to be considered. He
thought the number Mr. Stickel provided was more accurate
and explained the committee would discuss the matter during
the work on the operating budget. He cautioned that if
counting the tax credits against state revenue, the
following year would be distorted if the amount was counted
again. He considered that the amount of outstanding tax
credits was sitting on the sidelines waiting for an
appropriation but thought discussing the issues separately
would minimize confusion.
9:19:30 AM
Senator Olson asked about the total of the tax credit
liability.
Mr. Stickel stated that he had quoted $565 million, which
was submitted in a letter as of January 1, 2022. The number
in the Fall Revenue Forecast had been $587 million.
Senator Olson asked if the number included what was going
to the Arctic Slope Regional Corporation (ASRC).
Mr. Stickel replied that the total included all outstanding
credits available for state purchase.
Co-Chair Stedman asked Mr. Stickel to address how the tax
credits worked. He thought the credits could be traded
between companies. He thought there was some maneuvering
and that the number changed from time to time.
Mr. Stickel explained that the outstanding tax credits,
which were no longer available to be earned, could be
certificated by the state. If a company had production and
sufficient tax liability, it could use the credit to offset
its tax liability. The company could request state
purchase. He explained that prior to FY 16, the state
purchased the whole outstanding balance of eligible tax
credits each year, but since that time the state had
purchased less than the full balance and companies would
get on a list for credit purchase. A company could also
transfer or assign the credits to a financial entity that
could provide financing in exchange for the right to the
tax credit certificate. The credits could also be sold to
another company to apply against tax liability.
Senator Olson understood that the ASRC did not have the
ability to trade or sell the tax credits, nor use them
toward a tax liability. He asked if Mr. Stickel could
confirm the information.
Mr. Stickel was not prepared to speak to the specifics of a
particular taxpayer.
Senator Olson thought some tax credits were different.
Mr. Stickel noted that there had been various changes made
to the tax credit provisions over the years.
9:23:02 AM
Co-Chair Stedman asked about tax credits being assigned to
another entity and wondered if it meant that a bank or
lending institution could pick up the tax credits.
Mr. Stickel explained that several of the companies had
built the idea of monetizing the tax credits into ongoing
plans for financing, considering that the state was
purchasing the full balance of tax credits prior to FY 16.
In the absence of the state purchasing the credits,
companies had assigned the credits to a lending
institution, which had allowed companies to get the needed
financing to continue work, and then the credits were held
by the lending institution. When the state ultimately
purchased the tax credits, the money would flow through to
the lending institution.
Mr. Stickel displayed slide 7, "Fiscal System: Overall
Order of Operations":
Royalties (State, Federal, or Private)
Property Tax
Production Tax
State Corporate Income Tax
Federal Corporate Income Tax
Mr. Stickel explained that the graphic showed the overall
order in which the elements of the fiscal system were
applied. He noted that royalties were taken before any
taxes were taken. Downstream expenditures flowed through
into the transportation cost for calculation of the
production tax.
Co-Chair Stedman asked what "downstream" signified.
Mr. Stickel explained that upstream and downstream
delineated activity on the lease versus off the lease. In
the oil field where production was taking place, it was
considered upstream of production, while midstream
referenced the transportation structure, and downstream
was the end result of the oil going into a refinery and to
distribution.
Co-Chair Stedman asked if upstream was a wellhead.
Mr. Stickel explained that when he used the term
upstream, it denoted upstream of the point of production
on the lease.
Mr. Stickel continued that production tax was calculated
after royalties and did allow for property tax as a
deduction. State corporate income tax used worldwide income
as part of the tax base, which excluded the property tax,
production tax, and royalties in its calculation. He
explained that all state taxes, including the state
corporate income tax, were deductible in calculating the
federal corporate income tax.
9:26:47 AM
Mr. Stickel highlighted slide 8, "Production Tax "Order of
Operations": FY 2023," which showed a table. He explained
that he would address the table in a series of slides. The
numbers were based on the income statement presentation,
which was an illustration of the production tax calculation
for 2023 in particular. The information was included in
Appendix E of the 2021 Revenue Sources Book (RSB). He
addressed the fall revenue forecast, which showed an
average oil price of $71/bbl and a production forecast of
500,200 barrels per day of daily production, which
calculated out to an annual number of barrels of just over
182 million barrels of oil with a value of about $13
billion. The next several slides would focus on how the $13
billion was split and taxed. He reminded that the slides
represented an aggregation of the tax calculation, and the
actual taxes were based on monthly filings and calendar
year returns for all the different producers.
Mr. Stickel looked at slide 9, "Production Tax "Order of
Operations": FY 2023," which showed a table that
represented royalty and taxable barrels. Step 1 was
calculating the taxable barrels, which were subject to the
production tax. Any royalty barrels were subtracted
regardless of the owner of the barrels. The typical rates
were 12.5 percent or 16.67 percent, but the rates varied.
In addition to the state royalty, any federal and private
land royalty barrels were also subtracted in calculating
the taxable barrels.
Mr. Stickel added that also any barrels not subject to
taxation would be subtracted including a small portion of
production beyond the states 3-mile limit. He cited that
currently there was a small portion of production at the
North Star field that fell into the category, as well as
potential future developments such as the Liberty field. He
continued that after subtracting the royalty barrels, there
was about 160 million taxable barrels for FY 23 with a
total value of $11.4 billion.
9:29:50 AM
Mr. Stickel addressed slide 10, "Production Tax "Order of
Operations": FY 2023," which showed information on gross
value at point of production (GVPP), which was also called
well-head value. He noted that transportation costs
(known as net-back costs) were subtracted from the total
taxable value, to arrive at the GVPP. He described starting
with the oil sale, which in the forecast was $71/bbl on the
West Coast. All the transportation costs were deducted,
including marine transportation, the Trans-Alaska Pipeline
System (TAPS) tariffs, and any feeder pipelines to get to
TAPS. Subtracting the transportation costs got to an
average wellhead value of $61.91/bbl for FY 23, with a
total value of about $9.9 billion.
Co-Chair Stedman asked for more detail on downstream costs.
He commented that "not all oil is equal" due to different
severance tax or royalty issues. He asked Mr. Stickel to
discuss the $9.09 of tariff to move the oil down the
pipeline and over the ocean.
Mr. Stickel explained that he endeavored to understand the
value of the oil when it left the lease on the North Slope.
There was not a posted price for the value, and the value
within the tax calculation was called a net back. He
continued that the net back calculation started with the
sale value (typically on the West Coast), and then netted
back all the different costs to get to an assumed value at
the lease. He noted that there was a public assessment of
the end value. The cost for the pipelines and the tankers
was deducted.
9:33:11 AM
Co-Chair Bishop asked if the downstream cost would go down
if the state was producing 800,000 barrels a day.
Mr. Stickel answered "yes." He explained that some of the
costs were fairly constant on a per barrel basis, while
there were some downstream costs (such as the operation of
TAPS) that were fixed and therefore the average per-barrel
cost would be lower if there were more barrels of oil going
down the pipeline. He cited that in recent years production
had stabilized and so had transportation costs.
Senator Wielechowski knew that the argument had been made
when the More Alaskan Production Act was passed. He
recalled that the state had been told it would get one
million barrels of oil per day and it would lower
downstream tariffs, and the state would make more money. He
reflected that unfortunately the state was getting only
half of what was promised. He asked what percentage of the
$9.09 downstream transportation costs was the cost for
pipelines in Alaska. He asked about ownership of the
pipelines.
Mr. Stickel detailed that the $9.09 broke down into:
$3.47/bbl in marine costs, $4.98/bbl forecasted tariffs for
TAPS, $.56/bbl for feeder pipeline tariffs, $.07/bbl
adjustment for quality bank adjustments, and $.15 in other
adjustments which was primarily pipeline and tanker gains
and losses. He cited that the information was from page B1
in the RSB.
Co-Chair Stedman asked who owned the tankers and TAPS.
Mr. Stickel explained that TAPS was operated by an
independent third party, in which the major operators
shared ownership.
Co-Chair Stedman asked if the tankers were also owned by
the same entity.
Mr. Stickel stated that some producers owned tankers, while
others chartered tankers.
9:36:31 AM
Senator Wielechowski asked if there was a regulated return
on the downstream costs.
Mr. Stickel relayed that there were all sorts of
regulations surrounding the transportation costs. He did
not have the rate of return at hand.
Co-Chair Stedman asked Mr. Stickel to get back to the
committee with the information. He noted that the state had
had disagreements with some of the tariff structures and
had had court cases and settlements numerous times.
Senator Wielechowski understood that there was a 10 percent
to 14 percent regulated return. He asked about the
rationale for deduction of transportation costs. He noted
that the companies were making a profit on the
transportation.
Mr. Stickel thought the approach was typical worldwide. The
state was not taxing the oil when it was sold in California
when it was sold, but rather was attempting to tax the
value of the oil that came out of the ground on the North
Slope. Absent a market price for oil coming out of the
ground on the North Slope, the state needed a method for
valuation, and the net-back approach was the way the state
had chosen to arrive at the calculation.
Co-Chair Stedman asked if the calculation was by contract.
Mr. Stickel relayed that the net-back calculation was laid
out in statute. He thought for production tax was specified
in contract, and a there was a similar approach used in
royalty calculation.
Co-Chair Bishop asked about the .07 cent adjustment for the
quality bank mentioned by Mr. Stickel.
Mr. Stickel described that a quality bank was a financial
accounting done for pipelines. The issue was that each
field on the North Slope had a different quality of oil,
and when the oil was mixed in TAPS the end product was
different than what producers put into the pipeline. He
continued that the quality bank was a financial mechanism
that allowed a producer to pay or be compensated according
to the differences of the oil put into the pipeline versus
what came out of the pipeline.
Mr. Stickel continued that also along TAPS there were
refineries, and if a refinery took oil out of the pipeline,
it produced higher value end products, and the net oil at
the end was of a slightly lower quality. The refineries
also paid into the quality bank. The .07 cents per barrel
was the forecasted increase of the value that accrues to
producers due to the refinery impact.
9:40:59 AM
Mr. Stickel advanced to slide 11, "Production Tax "Order of
Operations": FY 2023," and addressed lease expenditures. He
noted that the production tax was essentially a modified
net profit tax, and the state allowed companies to deduct
expenses in calculating their tax value. For capital
expenditures, they were usually defined using guidelines
from the Internal Revenue Service (IRS) to define what was
a capital expense. There was no depreciation required for a
capital expense in the production tax. He explained that
operating expenditures were any allowable expenses that
were not a capital expense, and were typically the ongoing
cost of operations and labor.
Mr. Stickel discussed the terms allowable and
deductible lease expenditures. He defined that allowable
lease expenditures signified any cost in the unit that was
directly associated with producing the oil. Not all costs
were allowable. He gave examples of costs that were not
allowable in the production tax calculation: any financing
costs, lease acquisition costs, costs of dispute
resolution, and dismantlement, removal, and restorations
costs. He noted that DOR had created the term deductible
lease expenditures, which was not used in any statute or
regulation and referred to that portion of allowable lease
expenditures that were applied to the tax calculation in a
given year. Non-deductible lease expenditures were any
allowable expenses beyond a companys gross value that were
not deducted against the tax calculation in a given year.
Mr. Stickel explained that the non-deductible lease
expenditures were translated into carry-forward losses. He
directed attention to the bottom of the table which showed
a forecast of about $681 million of lease expenditures that
would be made in FY 23 and not deducted in the tax
calculation. The amount would turn into carry-forward.
Co-Chair Stedman asked if the forecasted amount came from
smaller companies, or companies with no production that
were most likely not one of the largest three companies. He
assumed that the expenditures that were incurred with no
revenue, and the companies were allowed to carry forward
the expenditures to deduct when production of oil was
underway.
Mr. Stickel affirmed that Co-Chair Stedman's description
was accurate. He explained that the carry-forward lease
expenditures benefit would be available to any company.
Given the current and expected price forecast, the benefit
would primarily be for not existing producers that were
making significant investments in exploration and
development of future production.
9:44:39 AM
Co-Chair Stedman asked if companies could carry forward the
expenditures forever or trade the deductions to other
companies. He asked for more detail on how the $681 million
in forecast lease expenditures would be handled.
Mr. Stickel explained that the carry-forward lease
expenditures could not be transferred to another company
and were held by the company that earned them until
production, at which time the expenditures could be applied
against a future tax liability. The carry-forward lease
expenditures belonged to a specific year earned and
beginning with the eighth or eleventh year would reduce in
value 10 percent annually if not used.
Co-Chair Stedman considered that the carry forward
expenditures had a trigger and then then reduced in value
towards zero.
Mr. Stickel explained that the ten percent reduction was
called a downlift, and was based on the prior years
ending value, so the value of the lease expenditures would
never disappear. Rather, the value would reduce by 10
percent of the prior year in perpetuity if not used.
Co-Chair Stedman wondered if the state could face up to as
much as $1 million in carry forwards if there was expansion
on the North Slope.
Mr. Stickel agreed that to the extent that there were
significant investments made in future production by new
entrants, there would be a significant outstanding value of
the carry-forward lease expenditures. He cited that Table
8-4 in the RSB included a projection of the tax value of
the future lease expenditures with a value that would
exceed $1 billion.
Co-Chair Stedman asked if the carry forwards were a
standard practice and why Alaska participated in the
practice. He asked about the effect if the state did not
allow for carry forwards.
Mr. Stickel explained that allowing companies to recoup
costs was very much a standard practice in oil and gas
fiscal systems around the world. He continued that if the
state did not allow for lease expenditures to be carried
forward and only allowed the expenditures to be deducted by
companies with current revenue, the incentive would be for
a lot less investment by new entrants and would concentrate
investment in existing companies.
9:48:16 AM
Co-Chair Stedman discussed the timing of cash flow and
pondered a company sinking a significant amount of funds
over four to five years before production and revenue
return. He pondered that if the state did now allow for
deductibility of expenditures, it would significantly alter
companys cash flow models and time value of money
calculations to the negative. He thought a lack of carry-
forward of lease expenditures would make it difficult to
have a project that was economic. He referenced the amount
of time the legislature spent in making changes to
adjusting cash flow timing to encourage investment in the
states oil and gas. He asked what the investment losses
could be counted against geographically.
Mr. Stickel discussed the carry forward loss provision,
which was currently available for the North Slope and
Middle Earth. The department was not forecasting
significant investment in Middle Earth.
Co-Chair Stedman asked Mr. Stickel to discuss Middle Earth.
Mr. Stickel explained that there were two primary oil and
gas basins in the state, the North Slope and Cook Inlet.
There was a separate tax regime for everything outside the
North Slope and Cook Inlet, and colloquially it was
referred to as Middle Earth. He continued that for any
carry-forward lease expenditures on the North Slope could
only be applied against North Slope production. There was a
provision that required a company to come into production
in order to utilize the carry-forward of lease
expenditures.
9:52:30 AM
Senator Wielechowski referenced Mr. Stickel's remark that
allowing carry forwards was common around the world. He
asked how many other states allowed for the carry forward
of the expenses.
Mr. Stickel thought most states in the United States had a
less sophisticated tax regime than Alaska and instead were
based on taxing the gross value on a lower tax rate. He
stated that Alaska's tax regime was more comparable to
other countries in the world.
Co-Chair Stedman asked Mr. Stickel to speak to how Alaska
was different than other states, in a way beyond just
geography. He mentioned the subsurface.
Mr. Stickel explained that in Alaska the state owned the
subsurface rights to most of the oil and gas production,
while in most other states private landowners owned a
significant share. He continued that Prudhoe Bay was a
world-class oil field and the state had a world-class oil
basin, which was very different than the type of production
that was dominating in other states where there was shale-
oil production. He thought the states consultants would
indicate that the most direct comparison for the states
production tax and competitiveness were other oil-producing
countries and other world-class oil basins around the
world.
Co-Chair Stedman reminded that in most other states,
farmers or ranchers owned the subsurface rates and there
were higher royalties. He mentioned Alberta, Canada. He
thought it was important to remember that Alaska was
different and cautioned against comparing it to other
states. He thought the finer points of Senator
Wielechowski's question would be addressed the following
day at the meeting with the states oil and gas
consultants.
9:55:47 AM
Senator Wielechowski asked if it was correct that no states
in the United States allowed carry forwards.
Co-Chair Stedman asked to leave the question until the
following day. He emphasized that Alaska was the only state
in the union that owned the subsurface rights. He mentioned
additional components including property tax, royalties,
corporate income tax, and severance tax. He thought that
Alaska was the only state that had a production-sharing
contract structure.
Senator Wielechowski recalled that Mr. Stickel had
discussed differences and called Alaska a "world class
basin." He asked why the state was not receiving the same
amount of royalties and taxes as in Texas and North Dakota.
He asked if Alaska should be producing more than half of
what the other states were producing.
Mr. Stickel thought Senator Wielechowski had posed policy
questions, while his presentation was intended to address
the nuts and bolts of how the tax system worked.
Co-Chair Stedman thought Senator Wielechowski's question
would be addressed the following day, as well as
comparisons. He mentioned transferability of royalty
contracts and commented that the royalty contracts had been
signed decades previously and were very valuable due to
significant changes in the structure. He thought there was
concern amongst members, as cited by Senator Wielechowski,
whether the sharing relationship was fair relative to other
basins. He reiterated that the meeting the following day
would address the concerns expressed.
9:59:02 AM
Senator Wielechowski understood that the topic would be
addressed later and understood the presenter was an
economist. He thought Mr. Stickel was "wading into policy
areas" and had made a portrayal that was not completely
accurate. He thought Alaska could be compared to other
states or other profit-sharing countries. He used the
example of Norway, which allowed for 100 percent recoupment
like Alaska but taxed at 78 percent. He continued that Iraq
allowed for 100 percent recoupment but taxed at 99 percent.
He pondered that Alaska allowed 100 percent recoupment yet
had a gross tax of $4.63 on $71/bbl oil which equated to
6.5 percent. He thought Alaska had the lowest tax rate in
the world. He thought it was important to have the
information presented in an objective way without the
information being slanted to make the tax structure seem as
if it was good for the state. He thought the policy had
been horrific and terrible for the state.
Co-Chair Stedman thought all the comparisons would be
discussed. He discussed the size of the states oil basin
and cited that the North Slope was the largest conventional
oil field in North America. He emphasized that the state
would not run out of oil or gas in the near future and
thought there was little to no chance of the field being
shut down in the future. He emphasized the value of the oil
field.
Senator Olson wanted to summarize the states net take
after the formula was enacted. He wondered if the state
received more or less than it would if it had a less
complex system.
Mr. Stickel thought Senator Olson had asked a nuanced
question.
Senator Olson questioned what way would result in more net-
back to the state.
Co-Chair Stedman thought Senator Olson's questions were
policy-related and asked to focus on the structure.
Senator Olson wanted a simple answer.
Co-Chair Stedman reiterated that the committee would
address the topic of lease expenditures the following day,
as well as the subject of ring fencing.
10:03:42 AM
Senator Wielechowski asked if any of the lease expenditure
deductions were allowed for fields from which the state
would receive no royalties or very little taxes in the
future.
Mr. Stickel relayed that lease expenditures were allowed to
be deducted for any activity within the area in which the
state levied the production tax, which was any activity on
state land or within the states three-mile limit.
Co-Chair Stedman stated that the last slide would address
the topic, which was a point of concern. He thought it was
a question that the incentives offered were offered on
lands where revenue could be received. He thought that was
the point of Senator Wielechowski's question.
Senator Wielechowski reiterated the question of whether the
state was allowing the industry to write off expenses on
fields for which the state would not receive royalties.
Mr. Sickel affirmed that the state received some tax or
royalty benefit for all production on state land and within
the three-mile limit. The exact nature of the benefit and
amount of royalty received was dependent on the landowner.
Co-Chair Stedman reiterated that the topic would be
addressed later in the presentation and would also be
discussed with the consultant the following day. He thought
the order of magnitude was a concern as the state went
forward and developed other areas outside state ownership.
Mr. Stickel looked at slide 12, "Production Tax "Order of
Operations": FY 2023," and addressed production tax value
(PTV), which was the gross value at point of production
less the deductible lease expenditures. The PTV was the net
profit proxy or tax base that the state used for levying
the production tax. He explained that each company
calculated its PTV based on all of its North Slope
activity, including all fields and developments including
new developments.
10:06:39 AM
Mr. Stickel showed slide 13, "Production Tax "Order of
Operations": FY 2023," which addressed gross minimum tax
floor. He explained that there were two primary
calculations done in the production tax calculation, the
net tax levy and a gross minimum tax floor. The minimum tax
floor was four percent of gross value when annual oil
prices were greater than $25/bbl. There were lower
percentages for the floor if the annual oil price were to
be less than $25/bbl. For FY 23, the minimum tax floor of
four percent multiplied by the gross value at point of
production of $9.9 billion got to a minimum tax floor of
$396.7 million.
Co-Chair Stedman thought the calculation was confusing. He
considered the tax rates applied to gross tax and net tax.
He asked Mr. Stickel to discuss how to switch between the
two.
Mr. Stickel noted that a following slide would discuss the
calculation of the tax.
Mr. Stickel referenced slide 14, "Gross Value Reduction":
? Gross Value Reduction (GVR) is an incentive program
for new fields.
? Available for the first seven years of production
and ends early if ANS prices average over $70 per
barrel for any three years.
? Allows companies to exclude 20% or 30% of the gross
value from the net production tax calculation.
? In lieu of sliding scale Non-GVR Per-Taxable Barrel
Credit, qualifying production receives a flat $5 GVR
Per-Taxable-Barrel Credit.
? The $5 GVR Per-Taxable-Barrel Credit can be applied
to reduce tax liability below the minimum tax floor,
assuming that the producer does not apply any sliding
scale Non-GVR Per-Taxable Barrel Credits.
Mr. Stickel explained that the GVR had been part of SB 21,
oil and gas tax reform legislation passed in 2013. The GVR
provided a temporary benefit used to reduce the value of
oil subject to tax for new fields. He cited that the GVR
was available exclusively for fields that were including
only state-issued leases with greater than 12.5 percent
royalty.
Co-Chair Stedman thought Mr. Stickel indicated that GVR was
available only for newer leases.
Mr. Stickel answered affirmatively. To qualify for the GVR,
a field must be comprised exclusively of state-issued
leases with greater than 12.5 percent royalty. He addressed
the last bullet on the slide. He thought a future slide
would address the taxable per-barrel credits.
Co-Chair Stedman asked if the floor was "leaky."
Mr. Stickel expanded that as an added benefit for GVR, the
new fields with $5 per-barrel tax credit could reduce
liability below the floor.
10:11:08 AM
Mr. Stickel turned to slide 15, "Production Tax "Order of
Operations": FY 2023," and spoke to the net tax calculation
and GVR. The net tax was a 35 percent statutory tax rate
applied against the production tax value. For companies
with qualifying new production, they were able to reduce
production tax value by the value of the gross value
reduction. He cited that for FY 23 there was an estimated
$5.7 billion of production tax value (after the gross value
reduction) multiplied by the statutory 35 percent tax rate,
to give a tax before credits of about $2 billion. He
reminded that the amount signified the tax before any tax
credits.
Co-Chair Stedman asked about the effective tax rate.
Mr. Stickel stated that the effective tax rate would be a
little less. He explained that typically the way an
effective tax rate was shown, the department looked at the
total tax paid to the state divided by the production tax
value.
Co-Chair Stedman asked Mr. Stickel to provide the committee
with more information. He thought the effective tax rate
was significantly different than 35 percent.
Mr. Stickel estimated that the amount was somewhere between
10 percent and 20 percent.
Co-Chair Stedman asked Mr. Stickel to get back to the
committee with more information, using the table on the
slide. He asked about the per-barrel deduction.
Mr. Stickel considered slide 16, "Production Tax "Order of
Operations": FY 2023," which addressed tax credits against
liability. He explained that the two major tax credits were
the per-taxable-barrel credits, and there was one for GVR-
eligible oil and one for all other oil. He noted that
currently the vast majority of oil was non-GVR-eligible
oil, which could change as future fields came online. For
most production, the oil was not GVR-eligible and there was
a sliding scale credit that ranged from zero to $8 per
taxable barrel. The zero sliding scale credit applied when
the wellhead value of oil was greater than $150/bbl. For
each $10 of oil, there was a change in the value of credit.
The $8 per barrel credit applied when the wellhead value
was less than $80 per taxable barrel of oil.
Mr. Stickel continued to address slide 16. He explained
that the sliding scale per taxable barrel credit could not
be used to reduce the tax below the minimum tax floor. He
noted that companies claiming the credit could not pay
below the minimum tax floor under any circumstances. For
GVR-eligible production there was a flat $5 per barrel
credit per barrel of taxable production, and the credit
could be used to reduce tax below the minimum floor,
providing the company did not apply any sliding scale
credits. He noted that any per taxable barrel credits not
used in the year earned were forfeited, and could not be
re-purchased, transferred, or carried forward.
Mr. Stickel informed that given the current pricing at
$71/bbl oil, the department was forecasting that companies
would be able to utilize nearly all of the credits
generated. For FY 23, there was a forecast for $1.25
billion of per taxable barrel credits generated, nearly all
of which would be deducted in the tax calculation. There
were some other tax credits against liability, but they had
relatively minor fiscal impact.
10:16:22 AM
Senator Wielechowski asked about the non-GVR-eligible tax
credits and asked why the figures were not even numbers.
Mr. Stickel responded that at $71/bbl oil, companies would
generate $8 per taxable barrel tax credits, and the credits
could only be used to reduce tax liability to the gross
minimum tax floor. He explained that while the vast
majority of the credits were applied in the tax
calculation, there were some companies that could not
utilize the $8 per barrel, resulting in the weighted
average of $7.45 per taxable barrel.
Co-Chair Stedman referenced the 35 percent tax rate
mentioned earlier but estimated that the states effective
tax rate was around 13 percent. He thought the deductions
were significant. He knew there was some concern about the
statutory rate of 35 percent and the per barrel sliding
rate of $5 to $8. He thought at $8 per barrel the total
would equate to almost $1.2 billion in deductions and
acknowledged there was some concern that the calculation
led to significant distortions over different price ranges
and holding the state to the minimum tax for longer than
anticipated. He thought the matter would be addressed in
the meeting with consultants the following day. He thought
the state should not be afraid of using the statutory rate
of 35 percent and using the effective rate to observe the
impact on the numbers. He thought the top rate for the
deduction was $8.
Mr. Stickel agreed.
Co-Chair Stedman asked if Senator Wielechowski's question
was answered regarding the effective tax rate.
Senator Wielechowski discussed the per barrel tax credits
and wondered if certain amounts were combined.
Mr. Stickel referenced Table 8-4 of the 2021 RSB and
explained that on line 11 the two per-taxable-barrel
credits were combined.
10:20:17 AM
Mr. Stickel displayed slide 17, "Production Tax "Order of
Operations": FY 2023," which addressed adjustments and
total tax paid. He explained that there were some other
items that were added to the total production tax revenue
received by the state. He listed prior year tax payments or
refunds, a tax on private landowner royalties, tax on gas
produced on the North Slope, any net tax liability from
Cook Inlet and other areas, any some company-specific
adjustments. The numbers had been aggregated on the chart.
He cited that for FY 23, the $741.2 million represented the
total cash expected into the General Fund from the
production tax. There was an additional $681 million in
non-deductible lease expenditures expected to be incurred
in FY 23 and carried forward, which could potentially be
applied against a future year tax liability. He noted that
the bottom line showed the General Fund impact, which did
not include about $8 million in hazardous release
surcharge, which was a $.05 tax on non-royalty barrels and
was considered designated revenue.
Co-Chair Stedman noted that over the years the legislature
had asked the department to provide the gross revenue for
the oil field. He recounted that almost twenty years
previously there had been reluctance to provide the
information. The slide showed $12.9 billion in gross stock.
He recounted working with the department, which showed the
flow of deductions to get to the net figure for budgeting
purposes. He thanked the department for always keeping the
numbers clear.
Co-Chair Stedman continued his remarks. He suggested that
if oil averaged $100/bbl for FY 23, the state would end up
with about $18 billion in gross stock. He commented that
the numbers could significantly change.
10:24:13 AM
Senator Wielechowski referenced Table 8-4, where the
production revenue forecast showed $785 million in carry-
forward credits. He was curious about the discrepancy with
the $681 million in carry-forward lease expenditures shown
on the slide.
Mr. Stickel looked at line 22 on Table 8-4 of the Fall 2021
RSB, which showed a calculation that estimated the net tax
impact of all outstanding carry-forward lease expenditures,
as well as any carry-forward credits held by producers. The
$785 million in FY 23 would take all of the tax credits and
lease expenditures that had been carried forward through
the end of FY 23 (for all prior years) assuming they were
offsetting the 35 percent statutory tax rate, would get to
the estimated $785 million tax impact. He directed
attention to the bottom line of slide 17, which showed $681
million, which was the total amount of lease expenditures
estimated to be incurred just for FY 23 and carried
forward. He explained that the $681 million, multiplied
times the 35 percent statutory tax rate, was embedded in
the $785 million in Table 8-4 of the RSB.
Senator Wielechowski looked at Table 8-4 of the RSB, which
showed the number grew to over $1 billion in FY 24, then
grew to $1.3 billion within a few years. He asked about the
impact of a net operating loss of $1 on the state
production tax of $741 million.
Mr. Stickel explained that carry forward annual losses that
a company may choose to apply to its tax liability and may
not reduce its tax liability below the minimum tax floor
using the carry-forward lease expenditures. In a
hypothetical situation in which all companies had very
large amounts of carry-forward annual losses, he expected
the tax to be reduced to the minimum.
Senator Wielechowski estimated that in FY 23, the minimum
tax would have been about $396 million.
Mr. Stickel stated that Senator Wielechowski was correct.
Senator Wielechowski asked if there were any net loss carry
forwards calculated into the forecast.
Mr. Stickel explained that the forecast assumed very
minimal impact of prior year carry forward losses. He
continued he vast majority of carry forward losses being
earned were being earned with companies without significant
current tax liability, which were those making the large
investments in exploration and development of future
production.
Co-Chair Stedman thought Senator Wielechowski was concerned
that carry forwards would overwhelm future revenue or
carry-forwards coming against the state from areas where
the state had significantly less revenue potential. He
reiterated that the committee would be asking the
consultant the following day about how other regimes dealt
with the issue, and whether there were limits on
deductibility to ensure that the sovereign always had cash
flow.
10:29:05 AM
Senator Wielechowski asked if the department had included
the future use of net operating loss carry forwards in the
ten-year production forecast.
Mr. Stickel relayed that the department's ten-year revenue
forecast modelled each companys projected tax liability,
including the expected use of the carry forwards.
Senator Wielechowski referenced hearing from the DOR Deputy
Commissioner that the administration had done some analysis
on lowering the per-barrel taxable credits. He asked if Mr.
Stickel was a part of the analysis.
Mr. Stickel noted that the departments economic research
group supported all sorts of analysis and thought the
deputy commissioner was available for questions.
Co-Chair Stedman relayed that when working on oil tax
structure, the Senate had passed a fixed $5 per-barrel
credit, and the House had added a sliding component well as
the 35 percent tax (which he thought had been 25 percent in
the Senate). The Senate had concurred with the action and
adjourned. He recounted that there had always been concern
in the Senate that the change was not a good of a policy
call as hoped. He recalled having support from the industry
for a 25 percent tax and a $5 credit. He asked Mr. Stickel
to address the hypothetical tax structure that had been
supported by the Senate.
Mr. Stickel recounted that back in 2013, Governor Parnell
had introduced the original version of SB 21, which had a
25 percent net profit tax rate and no per-taxable-barrel
credit. The version of SB 21 that passed the Senate had
included a 35 percent net profits tax rate and a $5 per-
taxable-barrel credit for all production.
Co-Chair Stedman stood corrected.
Mr. Stickel recalled there had been multiple iterations of
the legislation.
Co-Chair Stedman asked Mr. Stickel to discuss the results
if there were a 35 percent tax rate with a capped $5
credit.
Mr. Stickel estimated that holding all else equal for
investment and production with a $5 per-taxable-barrel
credit for all production, the state would receive about
$443 million of additional revenue in FY 23 with the
forecast oil price. He noted that the calculation came from
the state fiscal model on the DOR website, and reducing the
taxable barrel credit schedule was one of the options
included in the model. He thoguht the model could be the
analysis that the deputy commissioner had referenced.
10:33:40 AM
Co-Chair Stedman asked if the $443 million included
severance tax or any other tax issues.
Mr. Stickel affirmed that the calculation did not
incorporate any potential impacts on company decision-
making as a result of the tax increase.
Co-Chair Stedman asked about other taxes, which he thought
stayed the same in the calculation.
Mr. Stickel answered affirmatively.
Co-Chair Stedman thought the committee could go into
further detail with the consultants regarding the
competitiveness. He wondered if Senator Wielechowski
recalled testimony on the topic.
Senator Wielechowski stated there was a legal obligation
for a company to produce when the industry could make a
reasonable profit. He thought there was a tendency for
people in the building to compare the state with other
states and nations and asserted that the states attorneys
analyzed things differently. He noted that multiple times
over the years the analysis had focused on whether
companies could make a reasonable profit and had looked at
internal rates of return. He emphasized that the state was
not competing against other states or nations.
10:35:59 AM
Mr. Stickel highlighted slide 18, "Order of Operations:
Five Year Comparison," which showed a table with a similar
analysis as previous slides and a five-year spread
including two years of history, the current year, as well
as two years of forecast. He pointed out that FY 20 was a
minimum tax floor year, when most companies were paying the
minimum tax. Some companies paid above the minimum tax
floor in FY 21. For the current year and all future years,
the current revenue forecast showed the state expecting to
receive revenue above and beyond the minimum tax floor.
Co-Chair Stedman asked for Mr. Stickel to discuss where the
"trigger point" was.
Mr. Stickel extrapolated that for the major companies for
FY 23, the price at which the companies paid above the
minimum tax floor was in the $50/bbl to $70/bbl range. The
point at which the state received greater than the minimum
tax floor was around the $50/bbl range. He reminded that
each company had a different relationship between the
minimum tax floor and its net tax depending on the fields
and investments it was making.
Co-Chair Stedman wondered about the consolidation of the
policy and what the price per barrel would be.
Mr. Stickel estimated that with an aggregate calculation,
it would be about $50/bbl.
Co-Chair Stedman thoguht the number would change if there
was a flat $5 credit rather than a sliding credit.
Mr. Stickel did not have an estimation.
Co-Chair Stedman looked at the bottom of the table which
showed net new lease expenditures earned and carried
forward. He asked if the line reflected the aggregate
liability for any given year, or if there should be another
line to show accumulation.
Mr. Stickel explained that the net new lease expenditures
were those expenditures that would become carry-forward
annual losses in that given fiscal year.
Co-Chair Stedman asked about the line that showed the
accumulation of liability to the state. He thought the
accumulation was important to track and consider the pros
and cons. He mentioned the issue of the effective rate.
10:40:12 AM
Mr. Stickel looked at slide 19, "Illustration Assuming a
Single North Slope Taxpayer: FY 2023," which contemplated
how non-GVR credits "reduce" net tax to the gross minimum
tax floor. He explained that with a single taxpayer, he
expected get about $50 million more in revenue. He reminded
that there were some companies paying less than the minimum
tax floor, primarily those companies operating the GVR-
eligible fields and were using the $5 flat per-barrel
credit rather than the sliding scale. He relayed that the
point of the slide was to illustrate that each company had
a different set of economics and a different portfolio of
operations and investments, which he suggested to keep in
mind when looking at data.
Co-Chair Stedman expressed that he had asked Mr. Stickel to
create the slide. He thought it was hard to understand the
minutiae of the impact of deductions and incentives when
looking at aggregate numbers versus looking at the impact
of the numbers as a single taxpayer. He thought the
different might be $50 million.
Mr. Stickel noted that the initial forecast estimated
$741.2 million in General Fund Production Tax revenue, and
the estimation of a single payer was $794.5 million.
Co-Chair Stedman thought the last slide would be relevant
to the discussion regarding revenue sources and incentives.
10:43:24 AM
Mr. Stickel addressed slide 20, "State Petroleum Revenue by
Land Type," which showed a table of land lease status and
revenue components. He reiterated that the basic concept
was that not all oil was the same, and the revenue from oil
production was dependent upon where the oil came from. He
cited that for any oil produced in federal waters that were
more than six miles offshore, the state would not receive
any revenue, and noted that there was currently not any
production on the North Slope that fell into the category.
Mr. Stickel continued that for any oil produced within
three to six miles offshore, the state received 27 percent
of the federal royalty, but taxes did not apply to the oil.
There was a small amount of production that fell into the
category, primarily the portion of the North Star Oilfield
that extended beyond the states three-mile limit. For
anything on state land and up to three miles offshore, all
taxes applied regardless of the landownership, including
the production tax, state corporate income tax, and
property tax.
Mr. Stickel continued to address slide 20, and relayed that
royalties had a lot of variation, depending upon the
landowner. He explained that royalties applied to any state
land and anything within the three-mile limit. If the state
was the landowner, it collected a direct royalty. He cited
that most production was at the 12.5 percent royalty rate.
Federal royalty applied For federally owned land in the
NPRA, and 50 percent was shared back to the state, which
must be used to benefit impacted communities on the North
Slope. For federally owned land in the Alaska National
Wildlife Refuge (were it to come into production), federal
royalty would apply, and 50 percent would be shared back to
the state. There were currently no restrictions on how the
50 percent could be used.
Mr. Stickel informed that for other federal land, the
federal royalty applied, with 90 percent going back to the
state without spending restrictions. For private land
(primarily Native corporation owned land), there was a
private negotiated royalty that applied, and the state did
tax the private royalty value as part of the production
tax.
Co-Chair Stedman asked about Point Thomson on the North
Slope.
Mr. Stickel shared that the Point Thomson development was
state-owned leases, which would be on the third category
under Land Lease Type shown on the table on slide 20.
Co-Chair Stedman asked to have the slide available for the
following day, as he expected questions pertaining to
deductibility versus ownership.
Mr. Stickel showed slide 21, "Thank You," which showed
contact information.
10:46:55 AM
Senator Wielechowski asked for copies of the analysis of
cutting the oil tax credits.
Mr. Stickel explained that the analysis was incorporated
into the departments fiscal model, which was on the DOR
website. He relayed that he was happy to break out the
information and include it in his response to the
committee.
Co-Chair Stedman asked Mr. Stickel to provide the
information by 9 oclock in the morning the following day,
so that members would have access to the information.
Mr. Stickel agreed.
Senator Wilson thanked Mr. Stickel for the chart on new
production.
Mr. Stickel pointed out that the majority of the analysis
was done by the Department of Natural Resources.
Co-Chair Stedman thanked Mr. Stickel for his testimony.
Co-Chair Stedman discussed the agenda for the following
day.
ADJOURNMENT
10:49:13 AM
The meeting was adjourned at 10:49 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 030222 DOR Order of Operations SFIN_2022 FINAL_2022.03.02.pdf |
SFIN 3/2/2022 9:00:00 AM |
|
| 030222 DOR Response to March 2022 Order of Operations SFIN 2022.03.10.pdf |
SFIN 3/2/2022 9:00:00 AM |