Legislature(2017 - 2018)HOUSE FINANCE 519
03/22/2017 09:00 AM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB111 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 111 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE BILL NO. 111
"An Act relating to the oil and gas production tax,
tax payments, and credits; relating to interest
applicable to delinquent oil and gas production tax;
and providing for an effective date."
9:08:11 AM
KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE,
relayed he had spent much of the previous day walking
through the history and background of oil tax credits. He
had just started walking through the bill sections of the
presentation titled: "DOR Presentation - HB 111 Background
and Bill Analysis" when the meeting concluded. He briefly
paged through some of the sections that had already been
covered; the interest rate section, the transparency and
executive session sections, and the section on minimum tax.
The committee had stopped at the issue of hardening the
floor when time ran out. He referred to slides 37 and 38
regarding issues with a minimum tax. He had offered that if
the state were to implement a minimum floor the near-term
impact would equate to about $20 million.
Mr. Alper turned to slide 39 to look at the different
issues of hardening the floor. Hardening the floor meant
ensuring that the minimum tax was collected in all
circumstances. There were several separate policy decisions
that needed to be made. If the committee wanted to harden
the floor in some instances and not others it would be
possible to parse out certain items from others.
Mr. Alper continued that there was an issue of producers
not being eligible for refundable credits. He was talking
mostly about the major producers (companies that produced
more than 50,000 barrels per day). They were unable to earn
cash for their credits under current law and were required
to carry them forward. The question was whether there
should be clear direction that the carry forward credit
could not be used to reduce the minimum tax payment. It
would mean that the company would have to hold it and carry
it forward for an additional year or two until the price of
oil recovered sufficiently and they reached above the
minimum tax level.
Mr. Alper continued to discuss a second issue related to
hardening the floor. The small producer credit was
sunsetting but there were still a number of companies
earning it. Upon reaching the minimum tax, he wondered if
the smaller companies should be able to reduce it by the
credit of up to $12 million. The regulatory language
allowed them, under certain circumstances, to reduce their
payments to zero.
Mr. Alper explained that the third issue related to new
oil. The per barrel credit earned on new oil was not
specifically hardened to the floor presently. The $5 credit
could be used to reduce payments to zero on new production.
Generally speaking, the cross over point above a zero tax
was in the $70 range. He suggested that to harden the floor
for new oil would mean that the production during years
that companies earned the Gross Value Reduction (GVR) would
also pay the minimum tax. There was a unique structure in
the bill that had not previously been seen in other oil
bills that would create a reduced minimum tax specifically
for GVR eligible oil. He would discuss this item in another
slide.
Mr. Alper drilled deeper into the minimum tax floor on
slide 40. The slide addressed the major producers. It was
clear in statute that major producers were not able to
receive cash. Tax credits were carried forward. The net
operating losses (NOL)s for the explorers were simply
allowable expenditures. In other words, all of the
explorers' spending became their operating loss because
they did not have any offsetting revenue. The net operating
loss for the producer was when spending exceeded revenues.
The legal term that the state's auditors used was excess
lease expenditures, generally referred to as an operating
loss or an NOL. An excess lease expenditure could be due to
a company doing more drilling and just starting up their
production without a significant amount of oil.
Alternatively, companies could be functional, but if the
price of oil were to go far below expected and their costs
were greater than revenues, they could incur a loss.
Regardless, the state paid a credit based on a fraction of
their operating loss. He clarified that at least one of the
major producers claimed an operating loss in calendar year
2015. He could show members where in the Revenue Sources
book implications showed up. It meant that the company was
able to claim certain loss credits against their taxes
beginning in 2016. He noted that it could be seen in the
2-page table in the Revenue Sources Book. It showed where
the 023-B credits claimed against taxes by North Slope
companies. That added up to $107 million between the three
years, FY 17, FY 18, and FY 19. They were carry forward
NOLs. There was no other 023B credit being earned on the
North Slope that would be used to offset taxes by the major
producers.
9:14:05 AM
Mr. Alper moved to slide 41 which talked about the language
in the bill that would partially harden the floor for new
oil (GVR eligible oil). He noted the three columns on the
slide. He explained that he set the table at $49 per barrel
because the bill had a minimum tax change at $50 - he did
not want the data distorted. He wanted to show the status
quo tax versus what was being proposed in the bill. He
relayed that at $49 oil in 2018 with average costs
including transportation costs and lease expenditures the
production tax value of legacy oil equaled $5.59 (Net Value
After GVR). He noted that there was no GVR with legacy oil.
A tax of 35 percent was applied and equaled $1.96 and the
per barrel credit of $8 wiped the base production tax after
credits to zero. He recapped that under the traditional tax
calculation at $49 oil legacy fields paid zero. However,
that was the point at which the minimum tax would kick in.
Returning to the wellhead value of $39.32 multiplied by 4
percent would equal $1.57 per taxable barrel.
Mr. Alper continued to slide 42 which addressed a new part
of the bill, although it was something members had seen
before. The issue of migrating credits was originally
proposed by the governor in the original version of HB 247
[Legislation passed in 2016 - Short Title: Tax; Credits;
Interest; Refunds; Oil and Gas]. The producers referred to
the issue of migrating credits as the "true-up problem." He
explained that the per taxable barrel was earned on a
month-by-month basis. In statute it stated that, based on
the average gross value of the oil in a specific month, the
credit earned per taxable barrel was $8, $7, or $6 down to
zero depending on the gross value. It also stated that the
credit could not be used below the minimum tax. Inevitably,
in a low-priced month, some of the per barrel credit could
be lost. The credit could not be cashed or carried forward;
it was a use-it or lose-it credit. If a company's average
gross value was so low that it could not use the entire $8,
the credit would essentially be lost. He continued that the
minimum tax at the annual tax calculation was an annual
minimum tax. A company could use certain per barrel credits
that were earned in a low-priced month to offset taxes from
a high-priced month where the company was still paying at
above the minimum tax. He indicated that the following few
graphs would illustrate his point.
Co-Chair Foster relayed that Representative Guttenberg had
joined the table and Representative Geran Tarr was in the
audience.
Vice-Chair Gara had a question about slide 41. He thought
Mr. Alper had suggested some change to a possible minimum
tax for GVR oil in the new bill. He had missed Mr. Alper's
comments. He asked for a recap. Mr. Alper explained that
previous legislation that hardened the floor equated to 4
percent of the gross value being paid. It basically
eliminated any benefit for GVR-eligible oil because 4
percent of the gross was 4 percent of the gross whether it
was old oil or new oil. He furthered that HB 111 took the
gross value upon which the 4 percent or 5 percent were
calculated and adjusted the gross by the GVR. Companies
could take the 20 percent benefit off of the gross value
and then take the 4 percent calculation. He described it as
the minimum tax for GVR oil: 4 percent of 80 percent of the
gross, a 3.2 percent gross tax.
9:20:09 AM
Mr. Alper advanced to slide 43 which he thought provided a
good visual depiction based on actual data for calendar
year 2014. He highlighted the grey line at the top of the
chart representing the price of oil by month with a scale
on the right-hand side. In January, February, and March the
price was in the low $100 range. In June, the price went up
slightly, in July the price of oil began to rapidly
decline, and by December the price of oil reached just over
$50. The bar represented the actual revenue collected by
the state per the monthly estimated tax calculation by the
various producers. He noted that the top yellow bar
represented the total calculated tax of 35 percent of the
production tax value. The green bar showed what was
actually paid to the state. He clarified that the size of
the yellow was the per barrel credit - the amount
subtracted from the tax calculation before the payment
itself. The red bar represented the minimum tax if it came
into play. He commented that that everything was more or
less normal by the time July came around when prices began
to decline but remained comfortably above the minimum tax.
In October, the yellow bar was very large. By October,
producers were earning the entire $8 credit. At the same
time the price of oil was about $75 per barrel. Companies
were able to claim the $8 credit. He pointed to the green
sliver in October which indicated that the amount received
was only slightly above what the minimum tax calculation
would have been. If the price per barrel went down another
$1 or $2 the minimum tax would have kicked in. He reported
that in November the yellow bar was not quite $8 high
because of the little black dotted area on top. The dotted
black area represented the difference between the per
barrel credits that were used and the per barrel credits
that were earned. Producers were able to earn $8 and use $7
per barrel in November. In December, the price failed to
the point where companies might have earned $8 but were
only able to use $2. The dotted line made up the rest of
the per barrel credit that was essentially foregone for the
months of November and December. As far as the monthly
estimated payment went it looked like slide 43.
Mr. Alper turned to slide 44. He highlighted that the two
dotted lines in November and December were more or less
used to offset several taxes from earlier months in the
year. They were shown being connected to January on the
chart. In other words, the difference between the 12
monthly estimated taxes and the end of year true-up was
that the state ended up paying $112 million in refunds
based upon the ability to use the full $8 from the later
months against months in the year that had a higher tax
liability. Conceptually, the issue was that the per barrel
credits were being used in a month other than which they
were earned. He explained that the language in Section 7
and 8 in HB 111 tried to define that the credits could only
be used to offset taxes accruing in the month the credits
were earned. However, unused credits could not be moved to
offset taxes from another month. The language was technical
and had been worked on by the department and the
legislature's legal department. He was not certain that the
technical language did exactly what it was supposed to do.
He suggested that if it was the committee's will to
maintain the section, he wanted the legal teams to work
together to ensure the use of correct language.
9:24:37 AM
Representative Wilson asked how difficult it would be for
the companies and the department to go back and make sure
both parties agreed on what credits were in a specific
month. She asked how the change would be implemented. Mr.
Alper thought it would be fairly easy to implement with the
department's existing software. It was a matter of
programing changes to how different things were treated.
The per barrel credit was earned by the month. The
department knew the gross value and the production to the
number of taxable barrels. The department knew the lease
expenditures which were averaged out over the year with a
one-twelfth formula. It was not like the money a company
spent in January got deducted in January. It was a
company's annual expenses which was in existing law. He
surmised that calculating the taxes owed in a month based
on the numbers was not difficult. The state was not
returning to a monthly tax calculation similar to the way
Alaska's Clear and Equitable Share (ACES) was, which was a
true monthly tax. It was a matter of changing how the
credits were applied.
Mr. Alper turned to slide 45. He explained that the
language stated that the amount paid due in the month could
not be different than the amount that was due based on
another section of the bill. He thought the language was
complicated. However, he did not believe it would be that
complicated to make the change.oweve,Commissioner Hoffbeck
He clarified that the information on the slide was only
relevant in a year where there was substantial volatility.
In a normal year there was no value to the forecast, but
rather an indeterminant revenue item. The reason was
because the department did not forecast volatility. He
provided an example. In order for the section to have any
use or value some months of the year had to result in a tax
collection below the minimum tax cross over and some months
where they were above the minimum cross over. He relayed
that 2014 was an example, which lead to a circumstance
where the department's forecasts were off due to having to
pay large refunds. The department began looking for a
statutory fix and developed the current language in the
bill.
Representative Wilson asked if he knew how the bill would
affect through-put. Mr. Alper could not answer the
question. There were several decisions that a company made
about investments and production. He was unaware of how
substantial of an impact the bill would have. He argued
that the $112 million was a relatively mild example. One of
the advantages of having a monthly tax structure was to
benefit from a price spike. He provided an example where
the state would have $50 per barrel oil for an entire year.
However, in the summer if a war broke out and oil
transportation was disrupted, the price of oil might spike
to $150 per barrel for 3 months and return to $50. He
suggested that in the example, with a monthly tax, the
state would benefit. The state would be getting a 35
percent tax for 3 months. For the other 9 months, when the
price of oil was at $50 per barrel, there would be a
significant amount of unused $8 per barrel credit. At
annual true-up the state would be receiving the 4 percent
minimum tax during the spike years. He estimated a
potential loss of foregone revenue of about $300 million.
Representative Wilson asked if the department consulted
with the oil companies about the legislation. Mr. Alper
relayed that the division heard from tax payers all of the
time. He noted talking to them about mundane information.
He suggested that what was being discussed was a technical
concern originating from the Tax Division. The division had
brought the issue to the attention of the bill sponsors
from previous legislation.
9:30:28 AM
Representative Guttenberg commented that the issue of
migrating credits was a policy call. He asked about other
unintended consequences based on the modeling. He asked if
the department had looked at the potential scenarios. Mr.
Alper indicated that it was the largest unforeseen
consequence the department was digesting from SB 21
[Legislation passed in 2013 - Short Title: Oil and Gas
Production Tax]. The other issue was resolved with a bill
that passed the prior year. It had to do with the
interaction of the gross value reduction with the net
operating loss. Essentially, if a company lost $20 million
but also earned a GVR which was subtracted, the state could
be paying a credit based on a $50 million to a company that
only lost $20 million. The credit would become 100 percent
of their loss. It happened a couple of times and was
corrected in the bill that passed in the previous year. He
continued that there were regulatory issues regarding the
sequencing of credits that the department was continuing to
work through. He admitted there was still some statutory
fixes were needed, but the committee was currently
addressing the main issue.
Representative Guttenberg asked, in a case where the
calculation was more that 100 percent, if the state had
ever paid a company more than 100 percent of their costs or
losses. Mr. Alper answered that the state had paid tax
credits equal to or in excess of 100 percent of a company's
loss on a couple of occasions. The state had issued
certificates that were paid based on prior law. He asserted
that it would not be happening in the future because of the
correction made in HB 247 [Legislation passed in 2016 -
Short Title: Tax; Credits; Interest; Refunds; Oil and Gas].
Vice-Chair Gara considered the proposed changes as minimal.
He asked about a press release that provided a statement
from Repsol. The press release indicated the company would
be coming to Alaska and investing three-quarters of $1
billion on leases and development and would move forward
with projects that the state deemed economic. The company
did so without asking for any tax relief under Alaska's
Clear and Equitable Share (ACES), a stiff tax system. He
asked Mr. Alper if he recalled the press release. He
elaborated that the press release mentioned the geology and
stability in Alaska which made the state an attractive
place to do business. He asked if geology and a state's
stability were important factors in deciding whether to
invest. Mr. Alper recalled the press releases but did not
remember their precise timing. He thought it was a large
open debate. He agreed that Alaska had great rocks and
people preferred a friendly tax regime. He did not know how
the decision-making worked, but he believed the initial
commitment from Repsol to come to Alaska was prior to the
passage of SB 21.
Co-Chair Seaton asked about the migrating credit issue. He
asked if the issue had been addressed in HB 247 in the
prior year. Mr. Alper responded affirmatively. He reported
that the version of HB 247 that passed the House included
language that would have resolved the issue.
Co-Chair Seaton asked if the language in the bill was the
same. Mr. Alper relayed that the language was slightly
different. There was a technical problem with the version
that came out of the House. He believed the language in the
finance committee's version was better. He thought the
current language in the bill was closer to what was in the
governor's original bill. He suggested the language was in
a couple of places. It was in the use of credits and in the
definition of the monthly estimated payments section. He
did not want to comment definitively that the bill did
exactly what it was intended to do.
9:36:20 AM
Representative Pruitt appreciated Mr. Alper's example. He
thought there were two challenges with the $50 price; the
dearth of supply and the oversupply in the market. He
surmised that if a war broke out, the oversupply in the
market, while there might be a spike in price, would temper
growth. He thought the likelihood of a short timeframe was
low, a longer timeframe might be possible with a war. He
thought 2014 was the most extreme example he would expect
to see at a drop of $50 or $60. He wondered about
volatility in a normal year in the $50 to $70 range.
Mr. Alper responded that if volatility stayed in the $50 to
$70 range, the state would not see a substantial impact. If
$75 was the crossover for the average tax payer between the
minimum tax and the gross tax and there were a few months
with the price in the $65 range and a few months at the $85
range, the state would see something less than $112
million. It depended on how extreme the difference was. It
had to do with how much per barrel credit was unusable. In
the low-price months, it depended on how far below the
cross over a company got before it lost or was unable to
use a large portion of its per barrel credits. He suggested
that at the crossover at $75 a company was using exactly $8
of its per barrel credits. At $74 they might be using a
little over $7. At $50 or less companies would start using
zero, where 35 percent of their net without any per barrel
credit started equaling 4 percent of their gross. It
happened right around $5 above their break-even point - $46
or $47 per barrel. How close companies got and how high
above the minimum tax would determine the size of the
number. It would be less than $50 million in the $20
example.
Representative Pruitt asked about the change made in the
House Resources Committee to the sliding scale. He wondered
if the change had an impact on what was presently being
discussed. Mr. Alper replied that it was an annual tax.
Under current law, the calculation of the per barrel credit
was a monthly determination. He explained that the change
made to the per barrel credit in the House Resources
Committee changed the numbers. It was done differently in
the original bill versus the committee substitute. Both of
them were changes to the amount. He reviewed the changes.
In the current version all of the brackets were moved $20
to the left. The $8 credit happened below $60 per barrel
rather than below $80. The $7 credit happened below $70
instead of $90. It changed the places at which companies
earned different values. However, it did not change the way
the credits were used except for the migrating issue. It
did not make the tax more monthly except with migrating
credits.
9:41:14 AM
Representative Pruitt wondered if it was a migration. He
asked if it was still an annual tax. Mr. Alper responded
that it was still an annual tax. The particular credit was
earned monthly and was used monthly for the determination
of estimated tax. To the extent the state was turning it
into a monthly calculation, it was hardening the monthly
estimated tax. The amount of per barrel credit used for the
total of the 12 monthly taxes could not be more than the
per barrel credit used in the actual original 12 monthly
taxes. In other words, a company could not use more per
barrel credit annually than they would have been able to
use in their monthly estimated tax.
Mr. Alper advanced to slide 46. He relayed that the largest
change in the legislation was that the state was
eliminating direct state cash support for North Slope
activities. It was a dramatic shift from what the state had
done for the previous 10 years. He explained that in
Section 9, in the NOL statute describing how a company
earned an operating loss credit, it eliminated the 35
percent operating loss credit earned on the North Slope.
Sections 9 [11] and 11 [18] talked about how credits were
cashable, transferable, and saleable to other companies. It
carved out the North Slope NOL from the definitions around
who could do various thing with the credits earned. The
North Slope benefit and the benefit, itself, was elsewhere
in the bill, which he would be explaining. Since the North
Slope benefit would no longer be a credit, it would no
longer be transferable and had to be held by the company.
There was still a structure for cashable credits. The cash
fund would still exist, and other things would be eligible
for cash, just not as many of them. He relayed that the 4
items that would be eligible for cash was listed on the
slide:
Remaining credits eligible for repurchase:
1. Qualified Capital Expenditure and Well Lease
Expenditure credits (only in Middle Earth after 2017)
2. Exploration credits (only in Middle Earth after 2016)
3. LNG Storage and Refinery Infrastructure credits
(corporate income tax credits that aren't earned by
oil producers)
4. (new dry hole credit added in Sec. 17)
Representative Wilson asked how long the LNG storage
credits would remain. She wondered if they had a cap. Mr.
Alper was aware that it was capped at $15 million, the same
as the Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA)
credit. He did not know whether it had a specific subset.
The state kept anticipating the cap would occur in the
following year but kept rolling it for a year at a time.
9:46:20 AM
Representative Wilson remembered the LNG storage credits
but could not recall whether there was a sunset. Mr. Alper
confirmed he would get an answer for her.
Vice-Chair Gara wondered about the refinery credit from a
few years prior. He mentioned there was a little innocent
royalty sales contract and all of a sudden, a refinery
credit was added to it. The company that wanted the
refinery credit was Tesoro. They had stated they did not
need the refinery credit, but other companies wanted it. It
ended up passing and 3 companies qualified for it, 2 owned
by Arctic Slope Regional Corporation (ASRC) and 1 by
Tesoro. He suggested that the state was not privy to some
of the credits due to confidentiality. Some credits were
deducted from company profits and some were cashable for
companies that did not have profits. He asked if Mr. Alper
could share how much has been deducted from company
profits. He asked if the amount was up to $10 million per
refinery.
Mr. Alper answered that there was no way to aggregate the
information because there were less than three
transactions. He was aware the state had not paid any
credits simply because of the timing. There was no cash in
the fund presently. The first applications would not have
arrived until the prior fall. The credit took effect
January 2015 and the bill had passed in 2014. He spoke of
an inherent delay. There was at least 1 claim for a
refundable credit. However, the state was not able to pay
it because of limited funds.
Vice-Chair Gara was trying to get as much information
without infringing on confidentiality. He asked if the
legislature could know how much had been deducted by
refineries that made a profit. He continued to ask about
the applications that had been made for a certain amount of
money for cash credits and about the amounts being
requested. Mr. Alper did not believe the information could
be provided because of the limited number of payers. The
department would parse together whatever was possible.
Representative Wilson responded that Tesoro had not taken
any of the credits. She had verified the information with
Tesoro. She also mentioned that Petro Star had not taken
any cashable credits but had applied for their asphalt
project and another project. They were the only 2 companies
eligible with Flint Hills turning into a tank farm.
Vice-Chair Gara commented that companies might not have
received any cash credits, but he still wanted to know
whether they had deducted a certain amount from profits. He
continued his line of questioning. He wondered about a
potential cost to the state of $30 million per year for 5
years totaling $150 million. Mr. Alper responded in the
affirmative. He clarified that 1 year had gone by and one
of the companies had taken themselves out of the running,
which would reduce the maximum footprint of the tax. He was
aware of the Petro Star asphalt issue. He could not specify
how much they did or did not claim in a tax credit for that
specific project. He had just been handed some information.
He relayed that work had to be done before January 1, 2020
in relation to the LNG storage credit. The credit would
equal $15 million or 50 percent of the activity, whichever
is lower.
9:50:32 AM
Representative Pruitt referred to the Middle Earth credits
sun setting in 2022. He asked for an estimate of the
cashable credits. Mr. Alper answered that the credits
against liability were forecasted at zero because there was
no forecasted production. No one had any revenue to offset
for Middle Earth. The hope was for someone to find
commercial quantity oil or gas that they would be able to
produce and sell for a profit or, in some cases, used in
local utilities. The amount the department estimated was
about $20 million. In the department's forecast, Middle
Earth and Cook Inlet were merged because there were so few
transactions that the department could not separately
report due to tax payer confidentiality. He reported a
hearing in the Fall of 2015. The Senate Resources chair had
conducted a series of outreach meetings on tax credits in
the previous interim, one of which covered Middle Earth
credits. At that particular hearing Mr. Alper, in response
to a question, indicated he could not be specific because
of confidentiality agreements. However, a gentleman from
Doyon stood up and answered that the credits were mostly
Doyon's. Doyon had received about $60 million in state cash
credit support over several years.
Representative Pruitt listed the credits eligible for
repurchase that would continue to exist with the passage of
the bill. He mentioned $20 million, the LNG storage at $15
million, and the refinery credit. He was unclear about the
number of years remaining for the refinery credit. Mr.
Alper responded that the credit would be used through 2022.
Representative Pruitt asked if it was $10 million per year.
Mr. Alper responded, "Yes." Representative Pruitt indicated
that the state was creating a new dry hole. Mr. Alper added
that, barring anything unusual with the dry hole credit,
the total credit spend would be less than $50 million.
Representative Pruitt asked if Mr. Alper meant $50 million
per year. Mr. Alper responded affirmatively.
9:53:38 AM
Mr. Alper continued to slide 47. He addressed the per
barrel credit. The current credit was a sliding scale of $8
per barrel with the well head or gross value below $80; $7
below $90; $6 below $100; and going to a zero credit when
the well head value exceeded $150. It was subtracted as
part of the standard calculation for the net tax for SB 21.
The amendment would change the section of the bill. It
would keep the same stepdown language but changed the steps
to where $8 would be below $60; $7 below $70; $6 below $80;
and shifting most of the tiers to a lower threshold point
by $20 with a larger step at the end at the higher price
point. He suggested that it was important to recognize that
it was rare companies received the whole $8 benefit because
of the interaction of the minimum tax. In practice, there
was fairly little of the credit that could be used at
prices below about $70. The real change was the effective
subtraction once companies were above the minimum tax
cutoff. He indicated that it was a reduction of $2 per
barrel in credit benefit. Once the price of oil reached
above $80, $90, and $100 it amounted to about a tax
increase of about $300 million. It was $2 per barrel that
would not be subtracted from tax by the typical tax payer.
The impact at lower prices would be fairly modest.
Mr. Alper continued that as far as the language, it was an
awkward structure that the credit jumped in dollar
increments. He supposed that if a company made $109.99 and
went to $110 in gross value, they would be losing $1 in
value when they gained a penny in oil price. He opined that
it would be nice if the formula was smoother. He thought it
could be done with a statutory straight-line formula and
create the same net affect. However, it was an issue that
had not been resolved during the SB 21 deliberation. The
bill also created a $3 drop at $110, dropping it to zero,
instead of a $1 change, with a one penny increase in price,
it became a $3 change. He indicated that the graph on slide
48 illustrated his point.
Representative Guttenberg asked Mr. Alper to explain the
rationale for the $8 credit. Mr. Alper discussed the $8
credit compared to the $5 credit and to the zero credit.
First, he would go through the legislative history of SB
21. As originally proposed by the previous governor's
administration, there was a 25 percent flat tax. The idea
behind the flat tax was to create a progressive curve in
which the effective tax was higher at high prices and lower
at low prices. The Senate proposed a 35 percent tax with a
$5 per barrel credit. At expected prices of $100 or $110
per barrel, the tax was revenue neutral with a little more
money at high prices and a little less at low prices.
Incentivizing production was only a talking point. He did
not know whether the per barrel credit specifically
incentivized production, as most of the barrels were
already in production. He continued that going from $5 to a
sliding curve was a late amendment that was offered in the
House Resources Committee. The intent was to add slightly
more progressivity. In exchange, there would be a larger
benefit at the low end. The $6, $7, and $8 found its way
into the formula that created a much lower tax at oil
prices below $100 or $90 per barrel. Originally, it was a
correction to the progressivity calculation. He was unsure
of the rational behind moving the per barrel credit from $5
to $8.
9:58:35 AM
Mr. Alper moved to the graph on slide 48. The blue line
showed existing law. He explained that the Alaska North
Slope (ANS) price was roughly $10 higher than the well head
price. The graph showed the usable rate of per barrel
credits at different prices. He reviewed the chart from
right to left. At $160 per barrel the usable rate was zero.
At $150 per barrel it was $1, and the ladder continued to
step upwards. At around $90 per barrel a company earned the
full $8 credit. He continued that at $70, when the minimum
tax got in the way, the use of the credit fell
dramatically, and companies were not able to use it. He had
mentioned this drop when he discussed the migrating credit
earlier in the meeting. Companies lost the ability to claim
the entire $8 as prices got lower. The ability to use the
per barrel credit fell to zero at around $50 per barrel.
Mr. Alper continued that the amendments in Section 14
replaced the blue line with the dotted red line. He
explained that everything was $20 over or $2 less. There
was still the issue of not being able to use the credits
below $70. The real impact was in the range between $80-
110. He highlighted that at a gross value of $110 the
credit dropped from $3 to zero. The assumption was made
that above $110 per barrel companies did not need a per
barrel incentive and the 35 percent tax was adequate for
the state. He noted a very large drop of $3 per barrel
which equated to approximately $450 million at $120 per
barrel price point.
Representative Grenn asked Mr. Alper to place some
sideboards on the word smoother. Mr. Alper responded that
the formula in statute currently stated that if the gross
value was more than $80 and less than $90 it was "X." If
the gross value was more than $90 and less than $100 it was
"Y." He suggested that a formula could be created that
would result in a straight diagonal line that would reflect
the same curve. He noted an amendment offered on the House
Floor by Representative Tarr during the debate of SB 21 in
2013 that did the same thing.
Vice-Chair Gara thought the change really did not go into
effect at $65 to $70 per barrel. Mr. Alper responded that
once prices got low and the per barrel credit essentially
became unusable because of the minimum tax getting in the
way, changes to the number did not matter that much. An
affect could not be seen until getting over the minimum tax
crossover in the $70 range.
Vice-Chair Gara asked if the same was true with the new
bill. Mr. Alper responded affirmatively. Although it was a
different per barrel credit, the minimum tax crossover was
the same. The slight gap between the red and the blue lines
on the left side of the chart reflected the 5 percent
versus 4 percent minimum tax change. Vice-Chair Gara asked
when the department was forecasting $70 per barrel oil. Mr.
Alper thought it was about 4 or 5 years into the future.
Co-Chair Seaton interjected that the Senate's version of SB
21 had a flat $5 per barrel credit. It was seen as
progressive because the $5 flat credit was a much smaller
portion of the price as the price per barrel climbed to the
range of $160-$200. It was supposed to be a progressive
element but did not have much of an effect until the price
increased to much higher levels. It started stepping down
from $5 in dollar increments. He pointed to the blue line.
He noted the last-minute change in the committee
substitute. No one knew where the stair step above $5 came
from. The change above $5 was very late in coming. Mr.
Alper thanked Co-Chair Seaton for the information. Co-Chair
Seaton continued to provide some history on SB 21. Mr.
Alper appreciated the information.
10:04:46 AM
Mr. Alper moved to slide 49. He explained that the slide
showed the change to the minimum tax and the change to the
per barrel credit in total state revenue. The flatter lines
represented the minimum tax curve. The steeper lines were
the net tax curve which dropped to zero. The tax that the
state paid was the crossover between the two lines.
Currently, Alaska's revenue could be seen as the blue line
meeting the dark blue line. At $50 or $55 revenue would be
well below $500 million. At $75 per barrel revenue steeply
increased to where the state was making $2 billion to $2.5
billion. The change to the minimum tax was the shift from
the blue line to the red [orange] line. The shift in the
per barrel credit was the shift in the dark blue line to
the yellow line. The state would be paying the orange to
yellow line which would be reflected in the tax increase of
about $50 million in the $50 to $75 range. There would be a
larger tax increase above $75 represented by the gap in the
two steeper lines on the chart.
Mr. Alper turned to slide 50 and addressed Sections 15 and
17 of the legislation regarding the dry hole credit. The
language was new and entailed that there was an exploration
credit that was cashable for companies prepared to declare
failure. Companies would report the work they had done,
declare they would not go into production, pay their
vendors, and return their leases to the state. He agreed
with the chairman that if companies wanted to give their
data to the state it would be helpful. Companies would not
be able to use the related expenditures for another credit.
He had a couple of technical concerns. First, he conveyed
that as the bill was written the benefit would apply in
Cook Inlet. However, all Cook Inlet credits were eliminated
by the legislature in the prior year. He just wanted to
make the committee aware of the potential of adding another
credit benefit in Cook Inlet. He suggested that it could
also be carved out of statutory language. His second
concern was related to a company getting a fraction of
their lease expenditures paid back at a discount if they
were prepared to declare a failure. It would be linked to
the idea of carried forward lease expenditures. It would be
a separate credit and tied to the exploration language with
a different set of criteria and rules for allowable
expenditures. It potentially created a double dip problem.
He provided an example of double dipping.
10:08:55 AM
Mr. Alper moved to slide 51 and addressed cash limits in
Section 19 of the legislation. The section talked about the
ability to earn cash from the tax credit fund. It used to
not have restrictions other than the 50,000 barrels per day
number. In the previous year, the legislature added the 70
million per company per year restriction with the haircut
provision on the second $35 million. He noted that the bill
reduced that from $70 million to $35 million and repealed
the section later in the bill that provided for the 25
percent haircut on the amount above $35 million. They were
obviously linked with each other. The per company per year
cash limit became $35 million and created a flat
ineligibility for cash if production was below 15,000
rather than 50,000 barrels per day. It was a provision from
the House version of HB 247 that went over to the other
body in the prior spring. He relayed that although those
were the changes in Section 19, there was a broader issue.
Much of this was more or less superfluous to the other
changes made in the bill because the state was no longer
offering cashable net operating loss credits on the North
Slope. All of the sections that talked about limits and
what companies could receive cash would only apply to those
few cashable credits. The amendments to Section 19 would
only be restricting the issuing of cash credits for Middle
Earth activities. Currently, no one was claiming $35
million per year or more. The amendment might not have any
material impact in the near future.
Co-Chair Seaton asked if the restriction would not apply to
the currently issued certificates if companies wanted to
redeem them for cash. Mr. Alper replied in the affirmative.
The limits did not apply to things existing before the
effective date. Similarly, the $70 million in current law
did not apply to the $500 million in certificates issued
before January 1, 2017. He also noted that the other limit
with the resident hire percentage for HB 247 did not apply
to the $500 million of in-hand certificates from before
January 1.
Representative Pruitt had a question about the change in
cashable credits from 50,000 to 15,000. He wondered about
the number of eligible credits at 50,000 and at 15,000. Mr.
Alper relayed that the majority of the companies that had
received cash credits had zero production which would not
change. He reported that four companies were above the
50,000 taxable barrel level. He was unsure of the number of
companies that fell within the range. He mentioned
companies such as Eni and Caelus that were in the range.
There were also companies such as Anadarko and Chevron who
had junior minority interests in some of the larger legacy
fields. They could fall into the range. He did not know if
any of the companies were above or below 15,000 barrels per
day. He thought, for the most part, they were below 15,000.
10:13:08 AM
Representative Wilson mentioned having a lot of discussion
regarding the range between 15,000 and 50,000. It was her
understanding only one company would be affected. She
expressed her concern about targeting one particular
company.
Mr. Alper spoke on slide 52. He relayed that there had only
been one company that had received more than $200 million
cash credits in a single year. There had been 5
circumstances where a company received between $100 million
and $200 million in a year, and 11 instances where a
company received between 450 million and $100 million. He
highlighted a current issue which was that of the $500
million pending and awaiting cash, there were 3 different
companies with more than $100 million worth of certificates
in hand. They were not limited per the new $70 million cap.
Should there be a large appropriation in the current year
to pay off the old balance, those companies would not be
restricted, and the state would be able to pay the $100
million or more to those three entities.
Mr. Alper continued to slide 53 to explain the gross value
at the point of production not being able to go below zero.
He relayed that the gross value was the market price minus
transportation costs. Generally, transportation costs were
not supposed to exceed the value of the oil. If they did,
the negative value could migrate into the other tax
calculation and be used to offset taxable profits from
other production from the producer. It had been possible in
early 2016 when the price of oil dropped to $30 per barrel
and below. He relayed that the average price of
transportation was $10, but there was a wide range of costs
depending on the specific circumstances of the location of
the oil and where it was going. If oil were to go below $20
per barrel, it could impact more properties.
Mr. Alper advanced to slide 54 that showed the chart of
tariffs for the major North Slope units. He noted the box
around Point Thomson. Point Thomson was a new and expensive
project with low production presently. The regulatory
tariff on the Point Thomson pipeline, which spanned 22
miles from its production site to the nearest connection to
infrastructure, was $17.56. Point Thomson's total tariff
was $26.54 to get product to Valdez in addition to a $3
marine transport cost. He relayed that it cost nearly $30
to get Point Thomson oil to market. If the price of oil was
below $30, the production would have a negative gross value
that could find its way into the tax calculation. The
change made in Section 23 of the bill would indicate that
for tax purposes, it would be considered zero. Companies
would not be able to use a negative number specifically
from the gross value calculation to be used elsewhere in
the tax calculation.
Mr. Alper turned to slide 55 regarding carry forwards:
This is the major change to how losses are treated on
the North Slope, and incorporates advice from LB&A
consultant Ruggiero
• Current law- company earns a credit based on a
percentage of a loss
Losses become a 35% credit, eligible for cash
• HB111, 50% of lease expenditures carry forward
to a future year to offset taxes
· Since carry-forward balances can offset taxes,
this is equivalent to a 17.5% NOL rate (50% of
35%)
· Adds an "uplift" (Sec. 26) where carry-forward
balances can earn interest for seven years
Mr. Alper indicated that Section 25 housed the largest
change. He indicated that the section outlined how to take
something that was previously a loss and turn it into a
carry forward. Under current law, a company earned a credit
based on a percentage of their loss, a 35 percent credit.
The credit was tied in many ways to the 35 percent
statutory tax calculation. The way the bill changed it was
to take 50 percent of the loss (excess lease expenditures)
and carry them into the following year. Presuming there was
production and value in the following year, it would offset
the following year's value. The equivalent would be as if
it were a 17.5 percent NOL credit rate. The reason for that
was because if a company lost $1 and carried forward $.50
and offset a 35 percent tax with it, the company would
receive 50 percent of 35 percent of a tax benefit, or a NOL
rate of 17.5 percent. An amount would get added to
compensate for time and uplift. Essentially, the state
would be paying interest on carry forward losses. The
uplift would be such that for up to 7 years a company could
earn interest on their loss from their initial year until
they were able to use it in the future. If the company were
to wait more than 7 years to use it, there would be no
specific sunset on the value. However, the state would stop
paying interest.
Mr. Alper advanced to slide 56 which showed the carry
forward calculation. He reviewed an example. He relayed
that the following section of the bill addressed the
uplift.
Mr. Alper turned to slide 57. The slide talked about why
the 35 percent NOL rate might be slightly off. It had to do
with amendments to SB 21. He elaborated that when the
change was made from a 25 percent tax with zero credits to
a 35 percent tax with a per barrel credit, it was perceived
to be revenue neutral. The chart showed the revenue from a
single barrel of oil under SB 21 in its original form and
as it was amended. A barrel of oil priced at $100 with $40
in costs, net $60 of taxable net. At the 25 percent tax
rate, the tax equaled $15. At a tax rate of 35 percent with
a $6 per barrel credit it would also equal $15. The revenue
was the same as far as the state was concerned. The
question was, when the amendment was made, did the NOL
credit rate get increased from 25 percent to 35 percent. He
thought it was a reasonable question. He noted that the
House version of HB 247 reduced the NOL credit rate to 25
percent over several following years.
Vice-Chair Gara asked Mr. Alper to return to slide 56. It
was easier for him to understand the effective tax rate and
how much the state was giving away in per barrel credits.
The per barrel credit had always been confusing to him. In
looking at slide 56, it appeared that even with the change
in the bill, at expected prices, the deduction rate was a
higher percentage than the tax rate a company paid. In a
world where most people received a deduction equal to the
tax rate, not higher, they would still be allowed a higher
deduction rate percentage than a company paid as its tax
rate. He wondered if was understanding the slide correctly.
Mr. Alper would rather wait until he reached slide 58 to
respond. The slide graphically showed effective tax rates.
He commented that the attempt to reduce the NOL rate was an
attempt to make the credit rate about equal to the
effective tax rate. Whereas, at 35 percent it was currently
higher at all price points than the effective tax rate.
10:22:17 AM
Mr. Alper continued speaking to slide 57. He relayed that
the slide showed the side-by-side calculation. He
highlighted the NOL credit rate in yellow. He asked why the
credit rate increased when the effective taxes stayed the
same.
Mr. Alper turned to slide 58 to answer his question. He
reported that the solid blue line reflected the effective
tax rate of Alaska's Clear and Equitable Share (ACES) - the
tax plus the progressivity minus the capital credit at a
2018 spending rate. He highlighted the steep progressivity
with ACES which yielded a very high effective net tax rate
at higher prices. The net operating loss rate, the credit
earned by North Slope companies losing money, was 25
percent represented by the dotted blue line on the chart.
There was a point at higher prices which the effective tax
rate was above the credit rate, and there was a point at
lower prices below about $85 which the effective tax rate
was below the NOL rate. It was somewhere in the middle.
Mr. Alper continued that the red solid line was the
effective tax rate under SB 21. It was the number Vice-
Chair Gara had referred to. The effective tax rate as a
percentage of profits went down and tailed up again at
lower prices because of the hard floor in SB 21. Once a
company went below the minimum tax and companies were still
paying 4 percent, the 4 percent could become a very large
percentage of their profits. The minimum tax was the upward
tail of the red line on the chart. Mr. Alper continued that
the dotted red line was the NOL rate for SB 21, which was
above the effective tax rate on the entire graph. The red
line was not reached until oil reached $160 per barrel. The
thought was that a lower number should be the appropriate
NOL credit rate. He highlighted the green line representing
the effective NOL rate of the committee substitute from the
House Resources Committee - the 17.5 percent reflecting 50
percent not uplifted of a company's carry forwards. He
noted the dark green line which represented the effective
tax rate for HB 111. He pointed to the shift to the left of
the per barrel credit on the slightly higher minimum tax on
the left side to the tail. The effective tax rate would be
below the NOL rate between $60 and $80 and above the NOL
rate at higher and lower prices.
Mr. Alper moved to slide 59. He did not see much difference
between a NOL credit or a carry forward. By making it a
carry forward, it automatically became non-transferable.
The bill was written to create carry forwards which was
more comparable to what other jurisdictions did that
allowed companies to reclaim their costs once they went
into production.
Mr. Alper scrolled to slide 60. He noted some concerns with
Section 25. The way the 50 percent provision was written
might further reduce the amount another 50 percent every
year. For instance, if a company had $100 million in the
current year and $50 million in the following year, it
might become $25 million in year 3. The language might
require a technical fix. The carry forwards also appeared
to be available statewide. It went back to the Cook Inlet
question whether it was the committee's intent to expand
the benefit and recapture for tax purposes to Cook Inlet.
There was a question of how to apply carry forwards when a
minimum tax was in place. For example, if a company had $1
billion in carry forwards and came into production and
began earning $200 million per year, the question would be
whether they would offset the entire $200 million to zero
for 5 years and still pay the minimum tax. He suggested
other ways to handle the minimum tax as well. He thought
the issue needed clarification in the bill. He noted that
the department had done modeling in one way whereas, Mr.
Ruggerio had modeled it another way. There also might be a
need for conforming language regarding limiting deductions
for calendar years.
10:28:45 AM
Mr. Alper discussed slide 61. He relayed that another
possible concern was that the carry forwards were not
supposed to be usable until the company got into
production. It was possible that a company could invest $2
billion into a project then decide it was no longer
workable. The company could then sell their entire Alaska
subsidiary to a major producer at a great discount. The
company would be buying $2 billion worth of carry forward
lease expenditures which could then be used to offset their
production tax value from Prudhoe Bay and Kuparuk. He
thought some sort of ring fencing mechanism might be needed
to make sure the carry forward expenditures were tied to
the project or property rather than other values.
HB 111 was HEARD and HELD in committee for further
consideration.
Co-Chair Seaton indicated that the meeting would have to
stop due to the House Floor session beginning. He indicated
that the committee would pick up with Section 26 of the
bill at 1:30 pm and would be hearing industry testimony.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 111 3.22.17 Rep. Gara Repsol Press Release Updated.pdf |
HFIN 3/22/2017 9:00:00 AM |
HB 111 |
| HB 111 DOR Response Letter to House Finance Committee - 4.7.17.pdf |
HFIN 3/22/2017 9:00:00 AM |
HB 111 |