Legislature(2021 - 2022)ADAMS 519
03/03/2021 01:30 PM House FINANCE
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| Audio | Topic |
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| Start | |
| Presentation: Order of Operations by the Department of Revenue | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| *+ | HB 68 | TELECONFERENCED | |
| *+ | HB 84 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
HOUSE FINANCE COMMITTEE
March 3, 2021
1:34 p.m.
1:34:15 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 1:34 p.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Kelly Merrick, Co-Chair
Representative Dan Ortiz, Vice-Chair
Representative Ben Carpenter
Representative Bryce Edgmon
Representative DeLena Johnson
Representative Andy Josephson
Representative Bart LeBon
Representative Sara Rasmussen (via teleconference)
Representative Steve Thompson
Representative Adam Wool
MEMBERS ABSENT
None
PRESENT VIA TELECONFERENCE
Dan Stickel, Chief Economist, Economic Research Group, Tax
Division, Department of Revenue; Colleen Glover, Director,
Tax Division, Department of Revenue.
SUMMARY
PRESENTATION: ORDER OF OPERATIONS BY THE DEPARTMENT OF
REVENUE
Co-Chair Foster reviewed the meeting agenda. He remarked
that the presentation was not meant to spur an oil tax
policy debate.
^PRESENTATION: ORDER OF OPERATIONS BY THE DEPARTMENT OF
REVENUE
1:35:31 PM
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE (via teleconference),
provided a PowerPoint presentation titled "Order of
Operations Presentation: House Finance Committee," dated
March 3, 2021 (copy on file).
Co-Chair Foster observed that the PowerPoint was complex,
and the committee would take questions throughout the
presentation. He asked committee members to be cognizant of
the time.
1:36:41 PM
Mr. Stickel shared that the purpose of the presentation was
to present a high-level overview of how Alaska's oil and
gas production tax worked for the North Slope. He noted
that the discussion was likely a refresher for some
committee members, but the hope was to help viewers less
familiar with oil taxes to better understand the current
system. He moved to slide 2 showing a list of acronyms
pertaining to the oil and gas industry. He shared that the
industry and tax system tended to have a lot of jargon and
he would try to minimize them as much as possible. The
slide acted as a reference of terms.
Mr. Stickel turned to slide 3 and reviewed the presentation
agenda. He noted that the presentation was not intended to
talk about policy, but to make sure there was a solid
understanding of how the existing tax system worked for
North Slope oil. He would begin by reviewing all of the
sources for oil and gas revenue to the state, followed by a
detailed explanation of each step of the production tax
calculation. The presentation would look at FY 22 per the
fall 2020 forecast. The end of the presentation included a
five-year overview from FY 19 to FY 23.
1:38:51 PM
Mr. Stickel turned to a disclaimer on slide 4. He shared
that the analysis was attempting to break a complex tax
system down into understandable pieces. He elaborated that
the analysis was based on aggregated data and the
Department of Revenue (DOR) fall forecast estimates of
various items in the tax calculation. He clarified that he
was an economist, not an auditor; therefore, anything he
said was not an official tax interpretation. The
presentation was a review of the revenue forecast to
illustrate the tax calculation.
Mr. Stickel advanced to slide 5 titled "Oil and Gas Revenue
Sources." He highlighted that Alaska received oil and gas
revenue from four primary sources [state royalty, corporate
income tax, property tax, and production tax]. State
royalty was received for any production from state land.
Alaska also received a share of royalty from production on
federal land. Corporate income tax was based on worldwide
income apportioned to Alaska, which applied to many, but
not all of the companies operating in the state. Property
tax applied to all property anywhere in the state and
within the state's three-mile limit. Production tax was the
severance tax on Alaska's oil and gas. He noted that
production tax also applied to all production anywhere
within the state and within the state's three-mile limit
offshore.
Mr. Stickel added that with a couple of the revenue
sources, royalty in particular, not all oil was the same.
He relayed there was a slide at the end of the presentation
focused on how production from different categories of land
was treated for revenue purposes.
1:40:38 PM
Mr. Stickel moved to a table on slide 6 showing a five-year
comparison of state revenue from oil and gas revenue
sources from FY 19 to FY 23. He noted that the property tax
reflected on the slide represented the state's share only
(an additional amount of property tax went to
municipalities including the North Slope Borough). The
corporate income tax applied only to C corporations under
federal tax law. There were some temporary impacts to the
corporate income tax in FY 20 through FY 22 that had to do
with the federal tax law changes in the federal Coronavirus
Aid, Relief, and Economic Security (CARES) Act discussed in
the DOR fall forecast presentation several weeks earlier.
Representative Wool referenced corporate income tax and C
corporations. He remarked that BP had been sold as a C
corporation to Hilcorp, which was an S corporation. He
asked if Hilcorp was the only notable S corporation in the
oil production world. He asked if there were other small
corporations that were not at the forefront like Hilcorp.
Mr. Stickel answered that the department could not speak to
whether any specific company was a taxpayer or what their
corporate status was due to taxpayer confidentiality rules.
He relayed that there were multiple producers in the state
that were not C corporations and would be passthrough
entities. Those producers represented about 30 percent of
the total oil and gas production in Alaska.
Representative Wool asked for verification that all of the
S corporations accounted for 30 percent of the oil
production on the North Slope. He believed that Mr.
Stickel's statements meant there was more than one S
corporation. He understood that Mr. Stickel would not
disclose confidential information. He noted that some of
the companies were common knowledge.
Mr. Stickel clarified that the 30 percent represented
production from companies that were not subject to the
corporate income tax. The group encompassed various
passthrough entities including S corporations and
partnerships.
Mr. Stickel continued to review a table showing a five-year
comparison of state revenue on slide 6. The third line
showed production tax, which was the focus of most of the
presentation. The fourth line showed state royalties, which
included royalty revenue in addition to related bonuses,
rents, and interest. The table reflected total royalties to
the state, which included the share of royalties going to
the Permanent Fund and school fund [Public School Trust
Fund]. The fifth line showed Constitutional Budget Reserve
(CBR) Fund settlements, based on assessments or disputes
regarding any prior year production tax royalty or other
oil and gas taxes; the funds were deposited to the CBR per
the state constitution. The last oil and gas revenue source
was shared revenue from the Natural Petroleum Reserve-
Alaska (NPRA). He detailed that 50 percent of any of the
federal royalties and related revenues from NPRA were
shared back to the state. He noted there were special
provisions outlining how the funds could be spent by the
state. He added that revenue from the NPRA was relatively
small currently; however, as new developments came online,
it was expected to become a larger revenue source in future
years.
1:45:09 PM
Mr. Stickel addressed the fiscal system order of operations
on slide 7 as follows: royalties, property tax, production
tax, state corporate income tax, and federal corporate
income tax. Royalties were first and were based on the
ownership of the land. He detailed that landowners received
their share of the resource off the top before any taxes
were applied. Property tax came second - state and local
property taxes were considered lease expenditures that
could be applied against production tax. Production tax
came after royalties were subtracted and it allowed
property tax as a deduction. State corporate income tax
used worldwide income as part of the tax base. He noted
that property tax and production taxes were excluded from
the state income tax base. Last was federal corporate
income tax, which allowed all state taxes including the
state corporate income tax, to be deducted when calculating
the federal corporate income tax.
Representative Johnson asked if there would be a separate
overview on royalties and deductions that were taken from
the state's royalty share.
Co-Chair Foster asked Mr. Stickel if the information was
included in the presentation.
Mr. Stickel answered that the focus of the current
presentation was on production tax. The purpose of slide 7
was to put production tax in context. He believed in prior
years the Department of Natural Resources (DNR) had
provided a similar overview presentation on royalties. He
deferred to DNR on the royalty calculation.
1:47:20 PM
Mr. Stickel moved to a table showing the production tax
order of operations for FY 22 on slide 8. Due to the
abundance of information in the table, there were a handful
of slides on the topic [slides 8 through 13]. He relayed
the table was based on the income statement in Appendix E
of the DOR Revenue Sources Book. He began with the fall
forecast average oil price of $48 per barrel and the
forecasted daily production of 439,600 barrels to calculate
the annual barrels and the dollar value of production. He
reported that the focus for the next several slides would
be on the total annual value of $7.7 billion and how it was
split and taxed. He pointed out that the information was an
aggregation of the tax calculation for the North Slope
only. He noted that the North Slope accounted for the
largest portion of the production tax revenue.
Mr. Stickel reviewed the income statement on slide 9. The
first step was calculating taxable barrels. He detailed
that any royalty barrels were subtracted regardless of the
ownership of the barrels. Typical royalty rates were one-
eighth (12.5 percent) or one-sixth (16.67 percent). He
noted that rates varied by field. Federal and private land
royalty was subtracted in addition to state royalty. The
adjustment also subtracted any production not subject to
tax located in federal waters, which included a small
portion of North Star production and fields like Liberty.
The department was estimating 141 million taxable barrels
for a total taxable value of $6.8 billion.
Representative Wool looked at the total annual production
value highlighted on slide 9. He stated his understanding
that royalty value had been deducted. He did not know
whether the slide showed a deduction of one-eighth or
other. He surmised that royalty was deducted because a
certain percentage of the oil produced belonged to the
state and was calculated in barrels. He asked for
verification that the barrels were converted to dollars and
the value of the oil was deducted from the $48 per barrel
price to arrive at a price of $38. He thought the
calculation reverse engineered the price based on the
deduction of barrels paid in royalty.
1:50:38 PM
Mr. Stickel reiterated that the calculation of taxable
barrels began with the total annual production estimated at
160 million barrels; of the total, DOR estimated 19 million
barrels would be royalty [and federal] barrels, which were
not subject to production tax. The resulting taxable
barrels came out to 141 million. Given an estimated oil
price of $48 per barrel, the total value was estimated at
$6.8 billion. He noted that the calculation was limited to
determining the tax base for the production tax.
Mr. Stickel turned to slide 10 and reviewed the calculation
for the gross value at point of production (GVPP). He
shared that the term was used widely in production tax and
royalty and was also know as the wellhead value. To get to
the GVPP, transportation costs (also known as netback
costs) were subtracted. He began with the sales price at
market of $48 per barrel and subtracted the transportation
cost to determine the wellhead value. The $48 per barrel
price was at the West Coast at major destinations of Long
Beach, CA and Anacortes, WA. He explained that marine
tanker costs, Trans-Alaska Pipeline System (TAPS) tariff,
any feeder pipeline tariffs, and other [inaudible]
adjustments were subtracted from the per barrel price. In
FY 22, transportation costs of just under $10 [per barrel]
resulted in an average GVPP of $38.09 per barrel. The total
worked out to $5.4 billion GVPP.
1:53:28 PM
Mr. Stickel turned to slide 11, which began the process of
getting to the production tax value. The production tax was
essentially a modified net profits tax. He explained that
companies were able to deduct capital and operating
expenditures when calculating their tax base. The
department used Internal Revenue Service (IRS) guidelines
to define what constituted a capital expense. Companies
were not required to use any depreciation for production
tax; companies received an immediate deduction of all
capital costs in the year incurred. Operating expenditures
were any allowable expenditures other than the capital
expenditures. Generally, operating costs included the
ongoing costs of operations and labor.
Mr. Stickel highlighted the terms allowable and deductible
lease expenditures. Allowable lease expenditures included
any cost of a unit directly associated with producing oil.
He noted that not everything was allowable, such as
financing costs, lease acquisition costs, litigation costs,
dismantlement, removal, restoration, and other. Deductible
lease expenditure was a term of art developed by DOR for
presentation purposes. He noted that the term was not part
of any statute or regulation. Deductible lease expenditures
were the portion of allowable lease expenditures that were
applied in the tax calculation in the year incurred, up to
the gross value. He clarified that nondeductible lease
expenditures included any allowable expenditures beyond a
company's gross value, which could be turned into
carryforwards that could be potentially used to offset
production taxes in future years.
1:55:37 PM
Representative Josephson looked at slide 11. He recalled
that in HB 111 several years back, the legislature
effectively said that if a company had operating and
capital expenditures and no production, it could deduct the
expenditures against future production for a period of
seven to ten years. He remarked that a company would need
to be fairly confident that it would begin production
relatively soon or it may be stuck with the costs. He asked
if his statements were accurate.
Mr. Stickel replied in the affirmative. He explained that
the situation described by Representative Josephson was a
nuance of the carryforward lease expenditures. He
elaborated that if a company earned the carryforward lease
expenditures, the expenditures began to decrease in value
beginning in the eighth or eleventh year after being
earned.
Representative Josephson stated that one of the impacts of
the reform was that companies needed to have confidence in
their production plan and have good geologists.
Mr. Stickel responded that before HB 111, a company had
been able to get a credit for lease expenditures that were
not applicable against a tax liability. He explained that
the credit could in some ways be cashed out by the state.
The current system gave companies the ability to
carryforward lease expenditures. Depending on whether a
company had a future tax liability, it may or may not be
able to receive the full value of the carryforward. He
stated that the system impacted decision making and the
economics of making investments.
Vice-Chair Ortiz looked at the downstream transportation
costs category on slide 11. He asked if the amount varied.
He believed the number reflected a percentage of the per
barrel value. He wondered if any other factors caused the
transportation figure to change.
1:59:21 PM
Mr. Stickel replied that there were several important
variables impacting transportation costs over time. One
variable was the overall level of production. Specific to
TAPS, more production going through the pipeline meant that
fixed operations costs were distributed over a greater
number of barrels, which resulted in lower per barrel
costs. He relayed there was a transportation cost variance
between the different fields. He expounded that some fields
had feeder pipelines and tariffs were paid on those lines,
whereas Prudhoe Bay did not have a feeder pipeline and oil
went directly into TAPS.
Representative Wool looked at the deductible operating
expenditures of $2.3 billion and deductible capital
expenditures of $2 billion under the value column on slide
11. He surmised that the calculation included dividing by
the number of barrels to get the per barrel expenditures.
He asked for verification that no one calculated their
expenditures per barrel initially.
Mr. Stickel replied in the affirmative.
Representative Wool referenced Vice-Chair Ortiz's question
on transportation [costs]. He remarked that transportation
costs depended on production because the more oil produced,
the cheaper it was to move per barrel. He wondered if the
value of the pipeline was used as a production cost,
whether the cost diminished over time because the pipeline
had been paid for "a few times over." He wondered if it was
cheaper to move oil through the pipeline over time, aside
from maintenance costs.
2:01:49 PM
Mr. Stickel deferred the question to a colleague. He stated
the department could follow up.
COLLEEN GLOVER, DIRECTOR, TAX DIVISION, DEPARTMENT OF
REVENUE (via teleconference), replied that common carrier
pipelines were regulated by federal and state governments.
There were specific provisions on what the pipelines could
charge. She explained that a cost of service model was used
to recoup cost and return on investment. The return amount
varied over time. She stated that it was a function of the
cost it took to run a pipeline and the [oil] volume
traveling through.
Representative Thompson recalled that several years back
there had been a conversation about the deduction of
capital or operating expenses. He believed there may have
been a move for worldwide companies to try out new drilling
methods or ways to extract more oil from sands in Alaska
because they could deduct all of the costs from taxes and
production. He asked if he was remembering the situation
accurately.
Mr. Stickel answered that Alaska had been through several
oil tax debates and there had been discussion in previous
debates about the motivations behind some of the spending
that took place. He communicated that he would prefer not
to rehash the debate during the current meeting if it could
be avoided.
2:04:35 PM
Mr. Stickel addressed the production tax value (PTV), which
was the tax base for the production tax (slide 12). He
detailed that the PTV is calculated by subtracting
deductible lease expenditures from the GVPP. He explained
that PTV reflected the net profit on the North Slope. He
informed the committee that each company calculated its PTV
based on all of its North Slope activity, including all
fields and any new developments the company was
undertaking.
Mr. Steininger advanced to slide 13 and explained there
were two parallel calculations done and the final tax ended
up being the higher of the two. In addition to the PTV,
there was a tax calculation of a minimum tax floor. The
minimum floor was 4 percent of GVPP when oil prices were
greater than $25 per barrel for the year. He relayed that
if oil prices averaged less than $25 per barrel for one
year, the minimum tax rate would decrease below 4 percent.
For FY 22, the department was forecasting a minimum tax
rate of 4 percent applied to the GVPP of $5.4 billion, for
a total minimum tax floor of about $215.5 million.
2:06:49 PM
Representative Wool asked about the $74.5 [million]
deduction in the net tax.
Mr. Stickel answered that he would provide further
information in the upcoming slides. He explained that slide
13 focused on the two side-by-side calculations of the
minimum tax floor and the net profits tax. He would review
both calculations.
Mr. Stickel turned to slide 14 titled "Gross Value
Reduction." He explained that the gross value reduction
(GVR) was an incentive for new development that was enacted
as part of the SB 21 (oil and gas production tax
legislation passed in 2013). The GVR was a temporary
benefit used to refer to oil from qualifying new fields. He
detailed that the GVR expired after seven years of
production or any three years where oil prices exceeded $70
per barrel. The GVR allowed a company to exclude 20 or 30
percent of the gross value from the qualifying fields when
calculating its production tax value, which reduced the net
tax calculation for the fields. The 20 percent was for new
fields and the 30 percent applied if a field was comprised
exclusively of state issued leases with greater than 12.5
percent royalty.
Mr. Stickel continued to review the GVR on slide 14. He
stated that another wrinkle related to the GVR was that
eligible production received a flat $5 per barrel of
taxable production credit that could be used to reduce tax
below the minimum tax for any companies that did not take a
sliding scale credit. He would address the distinction
between the per barrel credits in several slides.
Vice-Chair Ortiz referred to slide 13 and the minimum tax
calculation of $215.5 million, reflecting the floor tax of
4 percent. He looked at the bottom of the "Value" column
and observed that $163 million was actually paid. He asked
what enabled a company to go below the minimum floor in
actual taxes paid.
Mr. Stickel answered that he had been planning to address
the question later in the presentation, but he would
address it at present. He explained that the minimum tax
floor on slide 13 reflected an aggregate calculation. He
clarified that in reality, each company calculated its own
minimum tax. He elaborated that if a company chose not to
take any sliding scale per taxable barrel credits, it may
use other credits to take its tax liability below the
minimum tax. The minimum tax was a hard floor for companies
that chose to take the sliding scale per taxable barrel
credits; however, if a company opted to forgo the sliding
scale credits, it could use other credits to go below the
minimum tax. He reported that DOR's official revenue
forecast assumed that at $40 per barrel oil, some companies
would elect not to use the sliding scale credits in order
to pay below the minimum tax.
Mr. Stickel reviewed the calculation of the net tax,
including the GVR, on slide 15. He highlighted that the
headline net tax rate was 35 percent of PTV. The slide
showed the impact of the GVR, which applied to companies
with a positive production tax value that were able to
reduce it with the GVR provision. The 35 percent tax rate
applied to the PTV after GVR yielded a net tax of $367
million for FY 22.
Mr. Stickel moved on to review tax credits against
liability on slide 16. The major credits were the per
taxable barrel credits, which were actually two separate
credits in statute. The first was the $5 per barrel credit
for GVR eligible oil and the other was a sliding scale
credit for non-GVR oil. The vast majority was the non-GVR
credits, but it could change with major new fields coming
online in the future. There was an $8 sliding scale credit
for non-GVR production fields at wellhead values of $80 and
below. The credit gradually stepped down to zero at
wellhead values greater than $150 per barrel of taxable
production. He reiterated his earlier statement that the
non-GVR sliding scale credits could not be used to reduce
the tax below the minimum tax. Additionally, any companies
claiming the credit could not use other credits to pay
below the minimum tax.
Mr. Stickel stated that the GVR eligible production credit
could be used to reduce tax below the minimum floor if
companies did not take any sliding scale credits. He
reported that the per taxable barrel credits were "use it
or lose it" and could not be carried forward or refunded.
In FY 22, DOR was estimating that $186 million in per
taxable barrel credits would be deducted in calculating the
tax liability even though $1.1 billion in per taxable
barrel credits would be generated. He reiterated his
previous statements that a company could only use credits
to get down to the minimum tax for the sliding scale and in
some instances to go below the minimum floor with non-
sliding scale credits. Other tax credits against liability
included small producer credits.
2:15:37 PM
Mr. Stickel moved to slide 17 and reviewed other items and
adjustments in the production tax calculation. The slide
showed a reconciliation of the simple calculation with
DOR's official revenue forecast for FY 22. The adjustments
number included any prior year tax payments or refunds,
private landowner royalty interest, hazardous release
surcharge or "nickel per barrel tax", any taxes on gas on
the North Slope, any net tax liability from Cook Inlet oil
and gas, and any additional company specific details in the
tax calculation. For FY 22, the $163.3 million represented
the fall forecast of total cash into the General Fund from
the production tax. The department was also estimating an
additional $563 million of nondeductible lease expenditures
were expected to be carried forward and would potentially
be available to apply against future year tax liabilities.
Mr. Stickel referenced an earlier question asked by Vice-
Chair Ortiz and reiterated his earlier answer. He stated
that some people would look at the $163.3 million of total
production tax and ask why it was lower than the minimum
tax of $215.5 million. He explained it was because the
minimum tax was applied on a company-by-company basis. He
elaborated that companies could not go below the minimum
tax if they used any sliding scale per taxable barrel
credits, but DOR was forecasting that at $48 per barrel oil
prices, some companies would choose to forgo the sliding
scale credits and use other credits to reduce their
payments below the minimum tax. Consequently, when all of
the companies were added together, the net tax calculations
collections were below the aggregate minimum tax
calculation in the forecast.
2:17:47 PM
Representative LeBon asked if there was an example of what
qualified as other credits a company could use against
liability.
Mr. Stickel answered that the small producer credit was an
example of other credits against liability. He elaborated
that it was a credit of up to $12 million per company. A
sunset had been on the small producer credit several years
back but some companies still had eligibility for the
credit. Another example was the net operating loss credit
earned prior to 2018 that companies still had on the books.
Representative Wool observed that after taking away
royalties and transportation, GVPP was $5.38 billion, and
the total paid to the state was $163 million. He could see
why people were scratching their heads related to the
specific portion. He asked if the royalty of $912 million
went to the state in its entirety. He believed it would
bring the state take up to about $1 billion.
Mr. Stickel answered that the majority of the royalty went
to the state. He referred back to slide 6 and reported that
DOR was estimating that the state royalty was $797 million
plus an additional $12 million of shared royalty from the
NPRA. The $912.9 million included state royalties, the
value of federal royalties retained by the federal
government, and the value of private landowner royalties.
The adjustment included any production in federal waters
beyond the state's three-mile limit, which represented a
small share of production from the North Star field.
Representative Wool stated his understanding that the state
received $163 million plus royalties. He looked at new net
lease expenditures earned and carried forward at a total of
$562 million. He asked if carryforwards from the year
before had been or would be applied towards the $163
million.
Mr. Stickel answered there would potentially be
carryforwards earned in prior years. The department was not
estimating that any prior year carryforwards would be
applied in FY 22. He relayed that any carryforwards were
applied at the lease expenditure stage. The idea was that
$562 million became a potential addition to lease
expenditures in a future tax year.
2:21:49 PM
Representative LeBon looked at the top of slide 17 that
showed royalty and federal barrels value at approximately
$913 million. He remarked that a portion of the value was
deposited into the Alaska Permanent Fund. He understood the
amount depended on the field and which formula was used. He
asked approximately how much of the $913 million would flow
to the Permanent Fund.
Mr. Stickel confirmed that a portion of the state royalty
flowed to the Permanent Fund. He explained that the number
was between 25 and 50 percent depending on when the lease
was issued. He reported that the average Permanent Fund
share was about 30 percent of state royalties. He
referenced page 38 of the DOR Fall Revenue Sources book and
highlighted the department's forecast that $199.2 million
of oil and gas royalties and related revenue would go to
the Permanent Fund in FY 22.
Representative Josephson referenced language "net new lease
expenditures" at the bottom of slide 17. He asked for
verification that the new lease expenditures would appear
under North Slope lease expenditures in a future year.
Mr. Stickel replied, "That's correct, potentially."
Representative Josephson asked if the total tax paid would
be less than $163 million in FY 22. Alternatively, he asked
if it was hard to predict because there would be new
production/revenue in addition to the expenditures.
2:23:57 PM
Mr. Stickel responded that a company could opt to carry
forward lease expenditures. Generally, companies applied
carried forward lease expenditures only if they would
expect to be paying above the minimum tax in a future year.
A company would have to have sufficient future year revenue
to be able to benefit from the lease expenditures.
Additionally, in terms of production, there was a provision
that in order to use a carry forward lease expenditure, a
company had to have production from the field where the
lease expenditure was earned.
Representative Josephson recalled that when discussing
state revenue 10 years back, people talked about tax, but
royalty was an afterthought. He remarked that the state had
brought in $6 billion to $7 billion in peak years and
currently it was looking at $163 million. He asked about
the accuracy of his statements.
Mr. Stickel replied that it was true that production tax
represented a significantly larger share of the state's oil
and gas revenue in prior years. He reported that production
tax generated $6.1 billion in FY 12 out of slightly under
$10 billion in total oil revenue that year.
Representative Josephson stated that no one disputed that
the [oil] price was lower [at the present day]; however,
people disputed whether the economy at large in the form of
jobs in the private sector, benefitted from SB 21 and
whether the state was encouraging more production that
would not be there "versus the change in tax." He
understood that Mr. Stickel did not want to revisit the
topic during the current meeting.
2:27:16 PM
Representative Wool surmised that the transportation costs
changed over time based on the tanker charge. He believed
the pipeline cost was fairly fixed. He referenced a time in
the past when production had been 1 million barrels per
day. He used 2012 as an example and asked how high
production impacted transportation cost.
Mr. Stickel answered that it would be necessary to go back
to the early 2000s to reach production of 1 million barrels
per day. He referenced a 10-year history on page 105 of the
DOR Revenue Sources Book. He reported that in 2011 the
total transportation charge had been $6.67 per barrel. He
stated that the transportation charge had been somewhat
lower at that point.
Representative Wool asked for the production and the price
of oil at the time.
Mr. Stickel replied that the price of oil had been $94.49
per barrel [in 2011] and North Slope production had been
about 600,000 barrels per day. He explained that there were
several costs that impacted transportation costs over time.
He elaborated that for some elements like TAPS, the total
production level was a very important factor. Other
elements moved with price and inflation. For example, one
of the important factors influencing tanker cost was the
price of the fuel. Historically, the general trend was that
transportation cost had increased over time, while
production had decreased. There had been a stabilization of
the transportation cost over the past several years, which
had been concurrent with a stabilization of production on
the North Slope.
2:30:24 PM
Representative Wool observed that price of fuel would
impact tanker cost. He expected the tanker cost to be
higher at $94 per barrel oil. He remarked that 600,000
barrels per day was higher than the current daily
production of 500,000 barrels. He found the cost of
transportation interesting and stated that on a $48 barrel,
$10 went to transportation. He noted it was not lost that
the people who owned the oil and the pipeline likely owned
the tankers as well. He commented that it was not a bad
thing that the owners could get a good transport fee for
their oil.
Representative Thompson stated that in the past when there
had been much more oil running through the pipeline, the
oil friction would heat it up. He understood that at
production of 500,000 barrels per day the oil had to be
heated during periods of cold weather in order to keep it
flowing. He asked if there was a fixed cost per year for
heating oil.
Mr. Stickel replied in the affirmative. He stated his
understanding that TAPS had added additional heating
capacity and the costs worked their way through the tariff
calculation and were eventually passed on to the shippers.
2:32:18 PM
Representative LeBon considered the price of oil and where
it had fallen since 2014. He asked if aside from employment
on the North Slope and the volume of oil running through
the pipeline, whether the state was better off with
production tax revenue under SB 21 than under Alaska's
Clear and Equitable Share (ACES) when considering the price
of oil over the past six years.
Mr. Stickel responded that it was the $1 million question.
He was not prepared to opine on an answer to the question.
His goal for the presentation was to provide an
understanding of how the current tax calculations worked.
Representative LeBon remarked that the topic had been
brought up and he had wondered if Mr. Stickel had some
insight into whether the state benefitted from SB 21 versus
ACES at an average lower price of oil over the past six
years.
Vice-Chair Ortiz stated he was not a tax accountant. He
asked if it was safe to say that under Alaska's oil tax
system, the effective tax rate was different for each
company.
Mr. Stickel replied in the affirmative. He expounded that
each company had a separate tax calculation based on the
different fields and developments it was involved in. He
confirmed that the effective tax rate varied between
companies.
2:34:38 PM
Vice-Chair Ortiz asked about the range of the effective tax
rates paid by companies across the state.
Mr. Stickel responded that he did not have the analysis in
front of him and he would follow up with the information.
Mr. Stickel moved to slide 18 showing a five-year overview
from FY 19 to FY 23. He detailed that production tax value
had declined annually from $5.1 billion in FY 19 to the
forecasted $1.1 billion in FY 22 and less than $1 billion
in FY 23. He reported that FY 21 through 23 were forecasted
as minimum tax years under the fall forecast. He elaborated
that it meant that generally companies were able to use
credits to bring production tax down to the minimum level.
At the forecasted oil prices, DOR estimated that some
companies would choose to forego the sliding scale credits
and use other credits to pay below the minimum tax. He
added that the phenomenon was seen in all three of the
years where the estimated production tax to the state was
below the calculated minimum tax floor.
Representative Josephson noted that in the past, the tax
floor had been hardened by either HB 111 or HB 247. He
asked for verification there was nothing that prohibited
the legislature from hardening the floor further. He asked
for confirmation there was no contract doctrine or common
law doctrine that would prevent the legislature from
specifying that a 4 percent floor meant a 4 percent floor.
Mr. Stickel replied affirmatively.
2:37:43 PM
Mr. Stickel relayed that he had concluded the main body of
the presentation. There were several additional slides that
had been requested when the presentation had been provided
to the other body. He turned to slide 19 showing how
revenue would be impacted by different levels of the
sliding scale per taxable barrel credit. Currently the
sliding scale credit went up to $8 per taxable barrel. The
table on slide 19 showed what the FY 22 tax calculation
would look like assuming a maximum value of $5, $4, or $3
per taxable barrel. He explained that not all of the per
taxable barrel credit was used due to the tax floor and in
some cases, companies could use other credits to make up
for a reduction in the per barrel credits. He reported that
an impact on production taxes from a credit change of $1
was less than $1 multiplied by the number of barrels. He
detailed that changing maximum per taxable barrel sliding
scale credit from $8 to $5 would increase estimated
production tax revenue from $163 million to $180 million
for FY 22. Production tax revenue would be $207 million
under a $4 maximum credit and $234 million under a $3
maximum credit.
Mr. Stickel clarified that DOR was not making a policy
suggestion, the department was showing information that had
been requested by the other body [Senate] in the past. He
remarked that any changes in the credit would have impacts
on investment and the economics.
Mr. Stickel moved to slide 20 titled "Illustration Assuming
a Single North Slope Taxpayer: FY 2022." He remarked that
the information on the slide related to an earlier question
asked by Vice-Chair Ortiz. He stated that currently some
companies paid at or above the minimum tax, while others
chose to forgo the sliding scale credits to reduce payments
below the minimum tax. Consequently, the FY 22 production
tax forecast was less than the aggregate minimum tax
calculation. Whereas slide 20 reflected that if there were
only one taxpayer, the department expected the company
would use sliding scale credits to reduce its tax liability
down to the minimum tax (meaning it could not go below the
minimum tax). Under the illustration, the total production
tax to the Treasury would be $229 million in FY 22 compared
to the $163 million in the official forecast. The slide
highlighted the impact of individual company economics on
the tax. He noted that each company had a different
portfolio of operations and investments.
2:41:09 PM
Mr. Stickel concluded on slide 21 titled "State Petroleum
Revenue by Land Type." The slide showed how state petroleum
revenues varied by land type. He noted that the basic
concept was not all oil was the same. He detailed that
production, corporate, and property taxes applied
everywhere in the state except for federal waters beyond
three miles offshore, regardless of the ownership of the
land. Whereas the royalty varied depending on the ownership
of the land. He elaborated that there were different
royalty provisions depending on whether the land was state,
private, or federal.
Mr. Stickel noted there had been a question the previous
day about oil prices that he would like to address. He
shared that the question had pertained to oil prices and
why Alaska's oil prices had diverged from Brent crude
prices in 2020. He explained that Alaska North Slope (ANS)
was not a widely traded crude; therefore, DOR liked to
compare its price to a global benchmark. The department
used Brent crude as the closest comparison, which was a
similar quality, and both had access to world markets by
tanker (also known as "waterborne"). Typically, ANS and
Brent crude were priced very similarly with only slight
differences in value. He noted that ANS may trade for a
dollar or two higher or lower than Brent at any given time.
Mr. Stickel elaborated that at the end of March 2020, ANS
and Brent had been near parity; however, beginning in April
the estimated value of ANS dropped below Brent and the
discount got as large as $28.25 per barrel on April 20. He
reported that it had been the day ANS prices were estimated
at a negative value, the lowest price on record, while
Brent prices had remained over $25. The divergence had
lasted through April and the first part of May and by May
20, ANS prices had been back to trading in tandem with
Brent.
Mr. Stickel addressed the reason for the divergence between
ANS and Brent prices. He explained there had been
significant turmoil in the oil market in the spring of
2020. There had been an unprecedented demand drop as COVID-
19 had started to unfold and oil storage had filled
rapidly, tremendous uncertainty in the oil markets had
occurred. The department believed the ANS/Brent divergence
reflected West Coast and Pacific specific market dynamics.
The West Coast and Pacific had seen some of the largest
drops in demand and at the same time storage in the market
had been filling rapidly. He elaborated that at one point
there had been dozens of oil tankers parked offshore
California looking for a place to put their oil. For a
period of time, when they were trying to sell ANS it had
been selling into an extremely oversaturated market.
Eventually, the markets worked through the supply/demand
and ANS prices had returned to their historical
relationship with Brent. Unfortunately, part of that
supply/demand balance had involved temporary curtailments
in Alaska production, which was one example of how the
markets came back into balance.
2:45:30 PM
Representative LeBon stated that most of the oil from
Alaska went to the West Coast. He asked what percentage
went east. Additionally, he wondered what factors
determined whether oil was shipped to West Coast refineries
or international markets.
Mr. Stickel answered that historically most ANS oil went to
the West Coast, which was still the case. There were some
examples of oil being shipped overseas to Asia markets. The
department had spoken with several industry experts about
the phenomenon and there were a couple of potential
factors. One was the changing mix of oil and gas producers
in Alaska. He elaborated that the state was moving from a
situation where companies had largely been fully integrated
where they owned the oil fields, production, refineries,
and distribution. He reported that some companies were
moving away from the model and were opting to limit their
operations to producing and selling product to the market.
Another impact was taking advantage of pricing trends in
the U.S. versus Asia. He explained that if a company was
selling into a market and did not necessarily own the
refinery, it would look to where it could get the best
price; sometimes the best price was the West Coast and
other times it was in Asia.
Representative LeBon stated that Alaska did not have a say
in where the oil went, whether it was the West Coast or the
Far East. He asked if Alaska was disadvantaged if the oil
went to an international destination versus the West Coast.
2:47:57 PM
Mr. Stickel answered that the one place the state had a say
was in state royalty oil, some of which was taken by the
Department of Natural Resources and sold to the instate
refineries. From a tax perspective, DOR assumed a company
would act in its best interest to get the best value for
its oil. He noted that the state benefitted when a company
received the best possible value for its oil.
Representative Wool thanked Mr. Stickel for the
presentation. He referenced a comment by Representative
Josephson earlier related to incentives and tax credits. He
found it concerning that the production curve did not
appear to be going in the right direction, regardless of
incentives. He observed that the bottom line of $163
million with $5.8 billion after royalties seemed like a
pittance. He reasoned the price was low and he thought it
was the driver of much of the production "stuff." He was
interested in the transportation aspects, including
pipeline and tanker costs, and hoped to go more into depth
on the issue at another time. He speculated that because
much of the transportation was owned by the same
corporations, perhaps there was not a lot of incentive to
lower the price. He thought there was an incentive in
Alaska. He thanked Mr. Stickel for his presentation.
2:50:21 PM
Vice-Chair Ortiz thanked Mr. Stickel for his presentation.
He asked if Mr. Stickel had always worked with DOR. He
wondered if he had worked with the Department of Natural
Resources (DNR) in the past.
Mr. Stickel answered that he had been with DOR for his
entire state career beginning in 2004. He had started as a
non-petroleum economist and had subsequently worked as a
petroleum economist. He reported that he had shifted into a
management role about 10 years back.
Vice-Chair Ortiz asked if the Mr. Stickel's duties included
production forecasting.
Mr. Stickel answered that he was involved in the process.
He explained that DOR worked collaboratively with DNR on
the production forecast, but DNR was the lead.
Vice-Chair Ortiz stated that the production forecasts
looked like they would stay at about 500,000 barrels per
day for the coming 10 years. He recalled that in 2012/2013
when SB 21 had been debated and eventually passed, there
had been talk about increasing production to 1 million
barrels per day. He asked what had changed in the world
situation or Alaska's situation that had caused production
to be much lower, likely around 500,000 barrels per day for
the next ten years.
2:52:31 PM
Mr. Stickel replied that it was a topic that could warrant
its own presentation. He believed that the production goal
of 1 million barrels per day had been aspirational in
nature. Over the past decade, oil prices had fallen
significantly from where they had been in 2013. There had
been some potential sources of new production that had not
come to fruition, such as the Outer Continental Shelf. He
reported there were many different factors that had
contributed to not reaching the goal.
Vice-Chair Ortiz surmised the production was not likely to
get to that amount in the near future.
Mr. Stickel answered that as Vice-Chair Ortiz had observed,
the production forecast anticipated fairly stable
production over the next ten years.
Representative Thompson recalled that the state had been
losing about 6 percent throughput per year. He stated that
when SB 21 had passed, there had been projections that
without the passage of the bill, production would be down
to 300,000 barrels per day. He remembered being told the
pipeline would likely have to be shut down if production
declined to that level. He highlighted that SB 21 had
passed [the legislature]. Subsequently, the 6 percent
decline had ceased, and production had increased. He asked
if he was remembering the situation accurately.
Mr. Stickel answered that his goal was not to rehash any
past oil tax debates during the presentation. He confirmed
there was a correlation, and oil production had roughly
stabilized over the past eight or so years.
2:55:18 PM
Representative Wool referenced a time when the price of oil
had dropped into the negative for a given amount of time.
He remarked that there had been a glut of oil and the
pipeline had been throttled down in response. He reasoned
that if the pipeline were to stop functioning, it would not
be for mechanical or physical reasons, but due to fiscal
reasons. He asked what would happen if the price of oil was
$18 per barrel for a prolonged period and transportation
costs were $10 per barrel. He considered whether there
would be any money remaining after transportation costs. He
surmised that if companies were losing money, at some point
the companies would turn off production regardless of the
mechanical capabilities of the pipeline. He thought an oil
price of $24 per barrel was a decent number in the early
days of the pipeline. He wondered if the problem could
occur if, for example, there was a glut of oil or people
started driving their electric cars.
Mr. Stickel replied that it was a risk. He stated that
transportation costs came off the top before a company
deducted any cost of production. He used the example of a
pie for illustrative purposes and explained that the
greater the transportation cost, the less pie remained. He
highlighted a situation earlier in the spring where the
major companies had elected to curtail production as a
result of the low price environment.
Representative Wool considered the numbers and data
provided by DOR. He contemplated a scenario where the oil
price was $28 per barrel instead of $48 per barrel. He
wondered what the breakeven number was for oil companies.
Mr. Stickel answered that the breakeven price would vary by
company. He elaborated that in the aggregate, DOR estimated
the breakeven price to be somewhere between $40 and $50 per
barrel. The fall forecast was just above that point.
Representative Wool highlighted various factors that could
influence oil price including a geopolitical event, General
Motors' announcement to go to all electric cars in a
certain timeframe, or if there was a glut or low demand. He
surmised that depending on the circumstances, oil prices
could be below $40 for a prolonged period in the near
future. He thought some of the fiscal decisions should
factor in the possibility. He wondered whether the
department thought about the scenario.
Mr. Stickel answered there was always a risk on oil prices.
He brought attention to a table in the Revenue Sources Book
that included a low and high case. He thought it was good
advice to consider how to address the low case scenario. He
added that the state had been fortunate that oil prices had
increased. He concluded that oil prices had been around the
$60 per barrel range recently; however, there was no
guarantee prices would remain at that level.
Co-Chair Foster thanked the presenters. He reviewed the
schedule for the following day.
ADJOURNMENT
3:00:46 PM
The meeting was adjourned at 3:00 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| DOR Order of Operations HFIN_3.3.2021.pdf |
HFIN 3/3/2021 1:30:00 PM |
|
| DOR Response to HFIN Order of Operations 2021.03.22 w Attachment.pdf |
HFIN 3/3/2021 1:30:00 PM |