Legislature(2015 - 2016)BUTROVICH 205
04/11/2016 03:30 PM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| SB130 | |
| Continuation of the Second Presentation: Additional Modeling and Scenario Analysis by Dor | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| += | SB 130 | TELECONFERENCED | |
| += | HB 216 | TELECONFERENCED | |
| + | HCR 17 | TELECONFERENCED | |
| + | TELECONFERENCED |
SB 130-TAX;CREDITS;INTEREST;REFUNDS;O & G
[Contains discussion of the companion bill HB 247.]
3:31:38 PM
CHAIR GIESSEL announced consideration of SB 130 and advised that
the Department of Revenue would continue the Second
Presentation: "Additional Modeling and Scenario Analysis" dated
April 4, 2016, starting on slide 17.
3:31:55 PM
SENATOR MICCICHE joined the committee.
3:32:01 PM
RANDALL HOFFBECK, Commissioner, Department of Revenue (DOR),
introduced himself.
^Continuation of the Second Presentation: Additional Modeling
and Scenario Analysis by DOR
3:32:25 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
Anchorage, Alaska, introduced himself and explained that he went
back to slide 16, because it refreshes the conversation they are
in. Going forward the next several changes would be on the
subject of what they mean when they "strengthen" or "harden" the
floor on the minimum tax.
He explained that the carry forward NOLs present three different
policy questions (slide 16). The first about the major producers
that can't get cash for their NOLs as opposed to the small
producers who can. They have discovered that those NOLs could be
carried forward into the next year and be used to offset the
minimum tax, effectively bringing tax payments down to zero.
Preventing that from happening is one component of hardening the
floor where the producers pay the full minimum tax and then
carry forward those credits into a subsequent year where there
would be enough tax liability to offset them.
The second question deals with gross value reduction (GVR) for
new oil. On those fields the issue is not the NOLs, but the per
taxable barrel credit for legacy fields, what is currently
hardened at the floor. That number cannot go below the 4 percent
level. However, on the new oil fields the $5/barrel credit can
go below the floor, and companies could effectively pay zero
using those. SB 130 "hardens" the floor, as well, against that
condition.
The final question is a much smaller issue, especially because
these credits are sunsetting: should the small producer credit
and exploration credits be usable to reduce payments for any
producer below the 4-percent floor.
3:33:41 PM
SENATOR STOLTZE joined the committee.
3:33:59 PM
SENATOR STEDMAN asked how much the small producer credit and the
exploration credit alternative was in 2016 and 2017, so people
at home can grasp the magnitude of what they are talking about.
MR. ALPER explained in the universe of $40/oil, the gross value
of is $30/barrel, presuming $10 for transportation. The
department's rule of thumb number is that there are about 160
million taxable barrels produced per year from the North Slope,
so calculation is 500,000 barrels/day times the year, minus the
royalty barrels. So, 160 million barrels times $30 equals $4.8
billion, which is the gross value at the point of production. A
4 percent gross tax on that is $200 million. So, the total
scope of what they are talking about peaks out at about $200
million. Within their forecast about $150 million will be lost
to the NOL credits being used to go below the floor.
The small producer and exploration credits are a very small,
$10-15 million, and similarly the new oil part probably is about
$25 million.
3:36:14 PM
Preventing the companies from applying the NOL against the
minimum tax is about their total lease expenditures exceeding
their gross value at the point of production. That means they
have negative income, or a loss, as defined in the Alaska
production tax statutes. That will be different in general from
what companies might show to their own stockholders, because of
the way the state treats capital expenditures (it uses different
accounting nuances). Often capital expenditures are treated on a
cash-flow based, retained-earnings based calculation versus
federal filings.
MR. ALPER explained that the NOL is calculated on a calendar tax
year and the idea is to ensure that any NOLs that aren't used to
reduce the taxes below the minimum tax would be carried forward.
So effectively, the state would be paying the credit not in the
first year, but in whatever year the price of oil goes up
subsequently, so that there is enough taxes to reduce it, but
still stay above the 4 percent floor.
3:37:56 PM
MR. ALPER presented slides 18-21 showing how the production tax
works at $100/oil, $70/oil and $40/oil. The $100/oil is in some
ways what the modeling looked like when they were last talking
seriously about oil taxes with $10 for transportation cost and
$90 gross value. The state receives about $35/oil in lease
expenditures (operating and capital), which works out to a
production tax value of $55 (what the tax calculation is based
on), a 35 percent tax results in $19.25, less the $6 per-barrel
credit. That means the state actually receives $13.25. But here
a comparison is made to the 4-percent minimum tax, the floor,
which results in $3.60, and since the state receives the "higher
of," the actual tax it receives is $13.25 (on a gross of $90).
That is multiplied by the 160,000 million. That would mean
production tax revenue in a year of $100/oil would be around
$2.1 billion.
3:38:48 PM
CHAIR GIESSEL recognized Senator Bishop in the audience.
MR. ALPER said at $70/barrel (slide 19), suddenly the minimum
tax becomes a relevant part of the calculation. The
transportation and lease expenditures are the same ($35) and
result in a $60 gross value and that leaves a $25 net. Applying
a 35-percent tax that net results in a tax of $8.75. The per-
barrel credit applied here is the maximum level of $8.00 and
results in a net payment of $0.75 per barrel. So, what takes
precedence (in the "higher of" situation) is the minimum tax (4
percent of that $60 gross), which results in $2.40 or
approximately $380 million per year in production tax revenue -
still in the realm of positive numbers.
At $40/oil, Mr. Alper explained, companies start suffering
operating losses (slide 20). So if it costs $45 to produce and
transport it to market, that results in a negative $5/barrel.
This results in an aggregate number of $800 million per year in
NOLs for the North Slope producers. Meanwhile the tax
calculation effectively generates a negative number (-$1.75) and
the minimum tax (4 percent of the $30 gross) results in $1.20.
So, the "higher of" is $1.20 and that times the volume comes out
to $190 million (roughly the $200 million he said in response to
Senator Stedman's question).
3:40:40 PM
Meanwhile, there is a $280 million carried forward loss into the
second year. So, slide 21 shows what happens in a second
consecutive year of low prices. The same calculation happens and
results in $190 million in tax liability. Only now the $280
million in carried forward NOLs from year one gets used to
offset that $190 million tax bill making the actual tax to the
state zero. Another $90 million more remains to be carried
forward, plus another $280 million earned in year 2 leading to
$370 million carried forward into year three. And as long as
prices stay low like that, "these NOL credits sort of stack up
on us," Mr. Alper explained. The DOR's forecast shows about $750
million in stacked-up NOLs in 2018/9 before the price recovers
sufficiently to where the companies start buying them down
again.
CHAIR GIESSEL asked if this assumes that a company that just
suffered $800 million in operating losses will continue to do
the same thing and expect different results in year two even
though none of the variables have changed.
MR. ALPER answered yes; the department doesn't forecast short
term changes in behavior in their modeling. They get updates
from companies twice a year and that gets built into their
modeling going forward. To a certain extent, companies are
reducing their expenditures through the laying down of rigs, but
the labor that it takes to pump the existing oil is going to
continue to be spent. However, companies will start to constrain
their costs and the department expects that a loss will be lower
in a second consecutive year.
SENATOR COSTELLO asked at what year does the department forecast
the price will be $70/barrel or above.
MR. ALPER answered that the chart she was referring to goes out
as far as the spring forecast for just 2025 when it is in the
high $60s. Using the normal inflationary trend, he guessed it
would go to $70 in 2026.
SENATOR WIELECHOWSKI said SB 130 does not address the $8/per
barrel credit in any way and asked how much the state is
allowing to be deducted at $70/barrel through the per barrel
credit.
MR. ALPER answered that the tax is officially calculated by the
companies that use the per-barrel credit until the tax bumps up
against the minimum tax. So, on slide 19, the answer would
$6.35. So, they would use $6.35 to bring the taxes down to the
$2.40 minimum tax level. Then they would lose the rest of that
credit.
3:44:24 PM
SENATOR WIELECHOWSKI asked if the state did not have any per-
barrel tax credit, how much more would it be getting at $6.45
per barrel in the $70/oil scenario.
MR. ALPER answered the $8.75 in tax times the production volume
would result in little bit less than $1.5 billion in revenue. A
more appropriate comparison would be the flat $5/barrel credit
in the original version of SB 21. In that scenario, at $70/oil,
the state would see $3.75 as the net and the minimum tax
wouldn't be triggered at the $70 level. That would lead to about
a $600 million in revenue or $200 million more than in the
example before them.
3:45:28 PM
SENATOR WIELECHOWSKI asked if the state was allowing about $1.5
billion to be deducted at $70/oil with a per-barrel credit of
$8.
MR. ALPER answered that the $1.5 billion was with no per-barrel
credit and $400 million in revenue. So, the difference is closer
to $1.1 billion.
SENATOR STEDMAN said another way of looking at it might be the
marginal difference between the $5 and the $8 sliding scale that
holds one in the minimum tax for another $10 extra in price
range.
MR. ALPER said that is a fair statement and that having that
higher and steeper per barrel credit tends to make that
crossover a higher price point.
SENATOR MICCICHE asked for the actual crossover point.
MR. ALPER answered that the current forecast has the crossover
at $78/barrel.
SENATOR MICCICHE answered that they had not modeled it within
the current forecast. They were modeling it in 2013 based on
their assumptions at the time, but he didn't have that in front
of him now.
3:47:24 PM
MR. ALPER said slide 22 sums up everything he just said and that
the members' questions had done a good job of going into how the
numbers move around. The idea in slide 22 is that at the end of
the second year there are $370 million in carried forward NOL
credits.
MR. ALPER said the second part of strengthening the tax has to
do with the gross value reduction (GVR) that new oil is eligible
for and the $5/barrel credit. A simple graph on slides 23 & 24
showed how that tax calculation works for legacy fields versus
GVR-eligible new oil fields at $80/oil, because that's a point
where there is a distinctive difference between the two and at
$60/oil. They used a cost of $46, which resulted in a net value
of $34 (at $80/oil).
3:48:50 PM
For legacy oil, the 35 percent tax rate would be applied to that
$34, which results in $11.90, minus the $8 tax. So, $3.90
becomes the actual tax. The minimum tax in that scenario of
$2.80 is not triggered. The crossover point is somewhere a
little bit below $80/barrel (within a dollar).
For the GVR-eligible field in this scenario, the $34 is adjusted
by subtracting 20 percent of the gross value at the point of
production. Gross is the well-head value after transport ($70)
and 20 percent of that is $14. So, the $14 is subtracted from
the $34 net to equal a taxable value of $20. The 35 percent tax
rate is the same but it's applied to the smaller number ($20
rather $34) and the tax becomes $7, and then the $5-flat per-
barrel credit (for GVR eligible fields) leads to a tax rate of
$2. The $2 is below the minimum tax. However, in this
circumstance, the GVR-eligible field would actually pay the
$2/barrel tax and not the $2.80 minimum tax.
This legislation proposes that GVR-eligible oil should also be
subject to the minimum tax and pay the $2.80 rather than the $2
rate. The GVR remains the same; the $5 credit remains there, but
in this circumstance the last $.80 of that $5 would be lost,
similar to $1 and change in the $70 example he walked through
for Senator Wielechowski.
3:50:10 PM
SENATOR COSTELLO asked if he had been able to retroactively
model how this would affect the state's bottom line, since it is
on the books.
MR. ALPER answered that the minimum tax didn't become a factor
until the last part of 2014 and they hadn't precisely modeled it
looking backwards, but he could say with some confidence it's
about a $25-million line item.
SENATOR WIELECHOWSKI asked the effective tax rate for legacy oil
and GVR eligible oil on this slide at $80.
MR. ALPER answered since the effective tax rate generally is a
share of net profits (cash flow), the $3.90 tax on the legacy
oil would be in the neighborhood of 12 percent and the $2 GVR-
eligible oil would in the 6-7 percent range.
3:51:28 PM
The same conversation at $60 oil reveals that legacy oil leads
to a negative calculation when the per-barrel credit goes all
the way to zero. So, the limiting factor under current law is
the 4 percent minimum tax. With $60 oil, 4 percent of the $50
gross becomes $2/barrel. The GVR-eligible producer does the same
calculation and can get as far as zero. The tax before the $5-
credit is only $1.40. So $1.40 out of the $5 would be used; the
other $3.60 would be lost. The company would pay zero. The bill
proposed that that oil would also pay the $2-minimum tax.
3:52:30 PM
MR. ALPER started explaining section 17(c) of SB 130 on
migrating credits. It means that a per-barrel credit earned in
one month could potentially be used to offset taxes from another
month under certain circumstances. This condition is not built
into the fiscal note modeling as having any value, because it's
very specific to volatility. It only happens in years where some
months fall under the minimum tax calculation and years where in
some months the price of oil supports the higher tax.
MR. ALPER said a classic example of that happened in 2014. He
explained that the sliding scale credits were originally brought
into SB 21 as a form of progressivity or reverse progressivity,
because it is progressivity through subtraction rather than
addition. But the idea was that the per-barrel credit itself is
very much of a monthly calculation. It can, under current law,
go up and down by the month.
3:53:58 PM
Slide 26 (labeled: section 17(c): Strengthen the Minimum Tax,
"Credits "lost" to the minimum tax before annual true-up) graphs
what 2014 looked like in actuality, Mr. Alper said. The total
production tax for January, based on 35 percent of the net, was
about $280 million. But the amount that the state actually
received was close to $200 million (green bar), because the per-
barrel credit of whatever the number was that month (probably
around $45/barrel) reduced the payments. Below that, the red bar
is where 4 percent of the gross would have been. If it were a
minimum tax month, the state would have received the red number;
but from January through October the state received the green
bar height number ($200 million).
He explained that the price of oil fell dramatically through the
summer of 2014 and by October the state was just barely above
the minimum tax. In November and December the tax went below the
minimum. In November and December the state received roughly $30
to $40 million per month, the amount under the red bar.
The shaded dotted areas above that (still on slide 26) represent
the per-barrel credits that were unusable, because the whole $8
couldn't be used before they bumped up against the minimum tax
in that month. In November they were able to use roughly $7 out
of the $8; in December they were able to use $2 out of the $8.
But when the annual true up was done for the entire tax year,
slide 27 shows how the dotted areas were able to effectively
offset taxes that were accrued in the month of January to reduce
the payment in the dotted area below the $200 million all the
way to a bit below the $100 million line. So that $112 million
worth of credits that were usable in a monthly calculation were
usable in an annual calculation to reduce the total payment. Mr.
Alper said this hit them as a surprise. Until the claims for
refunds came in the annual true up in the last week of March
2015, the department thought it had $100 million more than they
actually did, and had to pay large refunds to the major
producers.
MR. ALPER said section 17(c) of the bill, while technically and
complexly written, is simply intended to make the per-barrel of
credit itself a strict monthly calculation and not to be used to
offset taxes from a different month.
CHAIR GIESSEL asked if the department is asking the taxpayer to
accurately submit monthly tax returns.
MR. ALPER answered no. Currently taxpayers are expected to do an
estimated tax deposit based on the calculation for that month.
Because they are actually paying the amount based on the monthly
calculation already, it's based on an estimate of their lease
expenditures divided by 12 for the year. Doing an expense
calculation by the month would be far too onerous. The producers
know how much oil they sold and what the price was.
He explained that the per-barrel credits unclaimable in one
month should be limited to that month. That particular credit
which is calculated and earned on a monthly basis should also be
used on a monthly basis and it's strictly constrained to the per
taxable barrel credit.
3:57:46 PM
SENATOR COSTELLO asked if this is what takes the state six years
to audit.
MR. ALPER answered no; this is all worked out within the tax
year. It could be auditable like anything else, but this is a
situation that comes up at the tax true up period in March of
the year following the end of the tax year.
SENATOR COSTELLO asked how often the state has to reimburse a
company.
MR. ALPER answered that this is a specific provision of SB 21,
so it wasn't relevant before 2014. It was very relevant
specifically in 2014 when there was that level of volatility. In
2015, which was just completed, every month in 2015 was below
the minimum tax, and the state was in the red in the context of
this chart. So, there was no ability to migrate, to offset taxes
with used per barrel credits. The only time it would have
occurred was in 2014 and they hope to protect the state's
interest in statute in the event of a future year of high
volatility.
SENATOR MICCICHE commented that the only year one sees that
extreme volatility is when there is extreme price variation with
part of the year above the minimum tax.
MR. ALPER agreed.
SENATOR STEDMAN asked if he had calculated this in reverse,
where the state comes off the minimum tax and goes into several
months of extreme volatility upward.
MR. ALPER answered yes; it works the same in reverse.
Effectively, the way the tax true up is done is in the
aggregate. The value for the year is added up along with the
per-barrel credits and 4 percent of the whole year's total
becomes the minimum tax. So, that is where the per-barrel
credits could be used, because they are still above the year 4
percent instead of the month 4 percent.
SENATOR MICCICHE said it looks like the most volatile year would
have prices teetering at the $78 level. Is that right?
MR. ALPER answered no. For instance, October in the graph before
them is one of those months when the price of oil was down in
the $70s. There isn't much "headroom" above the minimum tax, so
the most that the state could lose is the difference between the
minimum tax and the calculated tax after the use of the per
barrel credit. If there were a bunch of months of $150 oil and a
bunch of months of $30 oil, the very large per-barrel credits
could reduce state production tax collection to the minimum tax.
4:02:41 PM
The narrative on slide 28 mostly says greater price volatility
means that the credit recovery could take a greater share of the
production tax. Effectively, the minimum tax only protects the
full year's revenue, because credits that cannot be used within
a year can be recovered at year's end the way the law is
currently written. Slides 29 and 30 show a more extreme version
where the price of oil declines from $90 down to $50 earlier in
the year. In this particular scenario the sum total of all of
those dotted lines that begin in June to offset all of the green
bars add up to $233 million, a little bit on the high end of
what the state is expecting with a lot of volatility. Slide 30
shows $233 million in credits being applied to what otherwise
would have been an $836-million revenue year, dropping it down
$603 million. That is the migrating credits story, the hardest
one to tell. It could reduce the state's taxes by close to 30
percent. It reduces the effective tax rate in that scenario from
about 14.5 percent to 10 percent. Part of the rationale of any
sort of monthly tax calculation is that the state should benefit
from months with higher prices, and this phenomenon allows it to
receive less revenue on the upside if it's within the same year
that has low price months. That is why they are seeking to embed
this section in the bill.
4:04:20 PM
MR. ALPER said section 18 is a totally different concept that
has to do with the interaction between the gross value reduction
(GVR) for new and a net operating loss (NOL). One doesn't
intuitively think of those two things as being related, because
to get the gross value reduction it means you are a producer
(you have production and sales) and you shouldn't be operating
at a loss. There are multiple scenarios where a new producer
could be operating at a loss - a new field, for instance. But at
today's low prices, their costs do not meet their prices.
The second situation would be if a company were involved in
continuing to invest - drilling wells or working on a new
project - they could, even at higher prices, bring themselves
into an operating loss for the field.
The understanding behind SB 21 was to try to build a flat level
of state support at all price points in all circumstances on the
North Slope, and the number that came out of the final version
of the bill was 35 percent. So, the operating loss credit should
be 35 percent of the operating loss. What is happening here is:
in the earlier slide he talked about the GVR in the context of
the minimum tax, but the GVR is a subtraction mechanism:
subtract a number from your taxable value and pay taxes on the
difference. If the taxable value is in essence a negative
number, because you are at a loss, and you subtract from it, you
create a larger negative number - a synthetically large
operating loss - and 35 percent of that number becomes a number
that is much greater than 35 percent of the actual loss, itself;
in some case, more than 100 percent of the loss. The difference
in the scenario on slide 33 means about $7.6 million to the
state (through a larger than 35 percent NOL credit).
4:06:37 PM
MR. ALPER apologized for the complicated slide 33 and explained
that current law works down the left-hand column, a low price
typical cost scenario ($40 oil), the $46 costs; the company is
losing $6/barrel. Based on that loss, a 35 percent operating
loss credit would normally result in a credit of $2.10/barrel,
However, the GVR calculation is 20 percent of the gross, which
is $30, which is another $6 subtracted from the negative $6
getting to negative $12 (circled in red on left column); 35
percent of that number leads to a $4.20 credit. So, effectively,
the company is getting paid an operating loss credit by the
state that represents 70 percent of their losses rather than 35
percent.
He explained that the technical change in section 18 of the bill
simply says, "In event of a loss, the GVR gets added back in for
the calculation of an operating loss credit." This means that $6
calculation would be foregone in a loss circumstance, the
negative $6 would represent the actual loss. The negative cash
flow would be what be receiving the NOL credit at $2.10 (35
percent of the loss).
4:08:01 PM
MR. ALPER said that was the intent and Mr. Mayer with enalytica
had said this was an unforeseen circumstance and recommended
retaining this provision. If slide 33 is talking about a single
producer with a 10,000 barrel-a-day field, and that gets
multiplied out for the year, it's the difference between a $15
million and $7.5 million NOL credit or about $7.5 million in
savings to the state.
SENATOR STEDMAN asked which fields fit this scenario and where
Point Thomson lies in it.
MR. ALPER answered that the three qualifications for the GVR
are: you have to be unitized subsequent to 2003, and the two
well-known producing fields that fall in that category are
Oooguruk (Caelus) and Nikiatchuq (primarily ENI). They would
classically fall into this sort of calculation. Should they have
a loss, Mr. Foley from Caelus, when speaking to various versions
of this legislation, has said that this change would impact his
company. So, he can talk a little bit about it within the bounds
of confidentiality because Mr. Foley already had. There are no
other fields, yet, although any new fields that start up soon -
for example, the Mustang field - would fall under this
definition. Point Thomson will come in as GVR-eligible under the
idea of a new participating area. Although that unit goes back
to the early 70s, they haven't filed for a participating area
(essentially, a pool) until after the settlement. So, well after
the effective date of the bill. So, Point Thomson will get the
GVR.
There are extensions to existing fields, if producers meet
certain criteria and if they are prepared to go through certain
hurdles of metering and the like. A couple of examples like CD5
and the Southwest Kuparuk could plausibly qualify, but he
couldn't say for sure that they actually did go through the
hoops required to get the GVR in those extensions.
SENATOR STEDMAN said it looks like Point Thomson would qualify
for the 30 percent GVR. He assumed under that same pricing
scenario, the credits in the new areas along with the 30 percent
GVR, instead of being in the 70 percent range, would be somewhat
higher than that. He asked Mr. Alper to explain that. And then
he asked what other jurisdictions fall back at that rate of 70
percent.
MR. ALPER clarified that he had asked that question of then DNR
Commissioner Balash who brought out a lease chart of the Point
Thomson area indicating that only a handful of the individual
leases are above the 12.5 percent level. The requirement to get
the higher level GVR is that every single lease has to be higher
than the 12.5 percent. So, Point Thomson would come in at the 20
percent GVR, not the 30 percent.
He explained that the scenario on slide 33 is based on something
that could happen in the future, after the effective date of the
bill. If something happened in 2014/15 there is a 45 percent
NOL. Using the same scenario, the state would pay the difference
between 45 percent and 90 percent of a company's losses.
Depending on the rate of that loss, it could go to well over 100
percent in certain circumstances.
4:12:16 PM
SENATOR STEDMAN asked what other states beside Texas and North
Dakota reimburse on losses.
MR. ALPER answered to his knowledge those states don't reimburse
on losses. They have relatively flat gross tax rates and
companies pay a percentage of the gross. That means that without
the credits, at low prices companies are losing money and they
are also paying a relatively small tax to the state. "That's
pretty much the end of the story."
SENATOR STEDMAN remarked, "Except for the royalty owner."
MR. ALPER responded that everyone pays royalty and in those
other states, the royalty, in most cases, goes to the private
land owner, but in Alaska, the state enjoys most of it.
4:13:15 PM
He said slide 35 makes the same calculation at a high price
($80/oil)/high cost scenario for a company that is spending
$80/barrel building the next oil field - not because he is
trying to lose money on this field, but because he is trying to
get future production on line in a new field. In that
circumstance, the producer with $80/oil, $80/lease expenditures,
and $10/transportation costs is losing $10/barrel. If it was a
straight 35-percent NOL credit, the proposed change is that they
would get a $3.50 NOL credit. However, if the 20-percent GVR is
applied to that -$10 (net value before GVR), that would result
in a $14 adjustment (based on 20 percent of $70 well head
value). So the adjusted negative value would be a -$24, and 35
percent of that is $8.40. Then the state would be paying
effectively an 84 percent NOL credit to that producer.
A 45-percent NOL credit would result in more than 100 percent of
an NOL credit. The savings to the state in this model is the
difference between a $30 million credit and a $12 million
credit, or about $18 million.
CHAIR GIESSEL asked if the NOL on the North Slope right now is
at 45 percent until July 1.
MR. ALPER answered that it went to 35 percent on January 1,
2016. He explained that many of the credits can be moved around
within a year, but the NOLs are very much tied to the calendar
year or the auditors get very upset.
SENATOR STEDMAN remarked that Senator Wielechowski had asked for
the history of the floor for some context to the floor
discussion.
MR. ALPER said he would get that. He added that the floor didn't
have a lot of teeth until SB 21 came in and hardened it
specifically to the per-taxable barrel credit.
4:17:04 PM
He said sections 26 and 27 are a little bit different in that
they don't talk about restrictions on the credits, themselves.
These are restrictions on the ability to turn those credits into
cash. They are within "028," the section of statute that
controls the tax credit fund, itself, where money is put to
repurchase credits. Four restrictions were added in SB 130 to
the state's repurchase of credits. The first one says that if
you are a very large company and have greater than $10 billion
in annual revenue, then you are no longer eligible to get cash
for your credits, the idea being these companies are generally
better capitalized and have more robust balance sheets. They can
hold the credits on their own books until such time as they have
production and will use it to offset their future taxes.
MR. ALPER said there is no magic to the number of $10 billion.
Any number of oil companies fall in above that line, but roughly
speaking, that's the state's all-in spending if you count
federal money, the Permanent Fund, capital budget, and the
General fund. The thought is if the company is bigger than the
state, it doesn't need to pay them cash for their credits.
The one change that has received a little more attention and
will impact more companies is the $25-million per-company per-
year limitation. If a company is earning a large amount of
credits, the state will repurchase $25 million and the rest of
the credits will be rolled forward effectively into the
following year. If a project keeps building credits their
payment would be based on a "first in/first out" basis where the
oldest ones would get paid out at the rate of $25 million per
year. That number was plucked from the original credit
repurchase language that was in the PPT bill (HB 3001 in 2006),
which created the idea for the first time of re-purchasable
credits and then put in that $25 million cap. That cap was
subsequently removed in the ACES bill a year or so later.
4:19:13 PM
The third restriction is the cash for the Alaska-hire provision.
The concept is if the state owes a company $10 million in
credits, the DOR would look to the Department of Labor and
Workforce Development (DOLWD) statistic of their instate hire
percentage and their subcontractors in the prior calendar year.
If it was 80 percent, the state would purchase $8 million out of
that $10 million and the other $2 million would hold their value
and be rolled forward for use in a future year against their
taxes.
Finally, they put in a 10-year sunset. If the credits are
unusable they will expire 10 years after the date they were
issued, which is where the "first in/first out" mechanism
becomes important to make sure that the older ones get used up
first.
4:20:08 PM
SENATOR COSTELLO asked if he saw a difference between describing
the credits as "unused" versus "unusable," because it's not
within a company's power to use a credit until the price of oil
goes above $70 or they are also in line and may never get to the
front of the line.
MR. ALPER answered he wouldn't say they were in line; it has
nothing to do with their relationship with other companies. The
$25 million per company cap would be for that company and then
that company would be able to receive $25 million the next year.
But it's fair to say some of those credits would be lost for
being unusable, because they were not able to get them cashed
out in time should the price not be high enough once they are in
production to apply their tax liability against.
SENATOR COSTELLO said it seems that the state has a hand in
that, for example, when the governor vetoed some of the money
for paying credits from last year. If the state is not going to
be cashing them out or they expire, that could have a
significant impact going both ways.
MR. ALPER agreed that was a good point. One of the weaknesses of
the governor's veto, administratively, was when there is not
enough money the structure is "first in/first out." Putting some
sort of limitation would create some ability to prorate the
money if there was a limited amount of money rather than saying
just because you got your credits processed through the DOR
staff before someone else did, you're going to get paid but
someone else is going to have to wait until next year. There is
a little bit of arbitrariness in a cutoff without some mechanism
that more equitably shares the impact of that cutoff, and that's
the sort of thing they are looking to impose here.
4:22:58 PM
SENATOR MICCICHE asked if he thought the Alaska-hire provision
would pass constitutional muster.
MR. ALPER replied that it is controversial and will certainly be
challenged. It doesn't matter in how it will be adjudicated. The
department's feeling is that because they aren't taking value
per se from someone, just the timing of the ability to enjoy
that value, that no one is going to lose their credits. They are
just going to be earning them in a later year. It might be more
likely to survive constitutional scrutiny than some other
attempts at Alaska hire. Miss Gramling is the assistant attorney
general handling this issue and she would know more.
CHAIR GIESSEL noted that Miss Gramling was not on line.
4:24:29 PM
SENATOR WIELECHOWSKI asked for data on the percentage of Alaska
versus non-Alaskans who are getting laid off in the oil
industry.
MR. ALPER said he hadn't seen any information on how the layoffs
are impacting local versus out-of-state employees.
SENATOR WIELECHOWSKI asked if the $25 million limit was changed
to $100 million in the House.
MR. ALPER answered that the House Resources version had $200
million and the House Finance committee substitute had $100
million.
SENATOR WIELECHOWSKI asked him the policy reasons behind why $25
million is better than $100 or $200 million.
MR. ALPER answered that the department hadn't done the analysis
until they started seeing the larger numbers, and that's when
they went back through their records and calculated the number
of companies that had come in at some of the higher price
points. There has been exactly one transaction in 10 years the
department has been paying tax credits where a single company
made more than $200 million in a year, and he found only five
circumstances where a company made between $100 and $200
million. There were 11 circumstances where a company earned
between $50 and $100 million. So, a total of 17 instances of $50
million or more going to a single company. They did not count
the $25 to $50 million, because there would be a lot of those.
So the impact is quite broad.
The discussion in the House Resources Committee of the $200
million was distinctly limited to the outlier event: Mr.
Armstrong with his very large project on the North Slope could
lead to the state having $600 or $800 million a year in credit
liability during their peak construction years and that would be
in advance of any revenue coming from the oil in that field. The
state figured out a way to protect its interests with the $200
million. It was something of an insurance policy against the
very extreme outlier. The $25 million would be a much broader-
based reduction in payments to a much wider range of companies.
COMMISSIONER HOFFBECK followed up that the broad policy decision
after meeting with the companies was that that the NOL credit
needed to be the key component that they felt needed protection,
but it is also the one that is the most difficult to control.
It's not project specific and there are a lot of different ways
of ending up with an NOL. So, although they were willing to
leave the NOL credit in play, because of the importance to the
various companies, they still needed some way to limit the
state's exposure to it in any given year. That was when the idea
came up of putting the cap back in. It limits the state's
exposure, but creates a longer tail on how long the credits
last.
4:28:09 PM
SENATOR WIELECHOWSKI asked once companies hit a loss and can
write it off on future taxes, is the state providing an
unnecessary incentive to do more things that will accrue losses
to deduct in future years.
MR. ALPER responded that he hoped not. The 35-percent figure is
flat across the board. So, if someone spends an extra million on
a gold plated object on the North Slope, they would only be
getting $350,000 back from the state. This is one of the places
where in some ways the loss of the steep progressivity from the
prior tax regime works in the state's interest. Because there
was in some ways more of an incentive to spend money because you
weren't just getting a reduction in taxes based on a lower
production tax value, but a company could lower its tax rate by
reducing their per-barrel profits going down on the
progressivity slope - essentially, a high marginal tax rate
working in reverse.
SENATOR WIELECHOWSKI said they talked a lot about the idea of
incentivizing production in SB 21, but that's not really the
case, because with NOLs the state is still allowing companies to
write off expenditures. Is that correct?
MR. ALPER answered yes. The NOL was always envisioned as a
payback for someone who is under the development stage to kind
of level the playing field between them and the producer. To a
certain extent they were taken by surprise at dealing with
producers having operating losses. It changed a lot of
assumptions in their calculations in what they are seeing going
forward.
SENATOR STEDMAN digressed to the 30 percent GVR for new fields
and said that nationwide royalty is around 20 percent. Alaska
is at 12.8 and the newer ones are 16.5 percent. He asked if the
30 percent GVR wipes out the "modernistic" royalty rate.
MR. ALPER answered that they modeled some fields and then
modeled them again at the high North Slope royalty and found
that the increment in additional royalty the state would get was
"pretty evenly" offset by the additional reduction in production
tax.
4:32:41 PM
SENATOR COSTELLO commented that prior to SB 21 they were
incentivizing investment and activity versus results. So, she
could see companies looking for well lease expenditures or other
types of tax credits, but to assume a company is trying to
operate at a net operating loss is a curious suggestion. She
asked Mr. Alper if he thinks companies are trying to lose money
under the current system.
MR. ALPER answered, "Most definitely not!" Except for the rare
circumstance, the state is never paying anyone 100 cents on the
dollar. Companies are losing money beyond what the state is
paying them back.
SENATOR COSTELLO said that is what she is hearing, too, and that
companies are trying to operate more efficiently and are having
to lay off people.
4:34:00 PM
MR. ALPER said section 31 is simpler and a little bit obscure as
well. With extended low prices, the state is facing a
circumstance where potentially the gross value at the point of
production could go less than zero either on the field level or
on the slope level. Gross value at the point of production is a
waystation in the tax calculation on the way to production tax
value. So, the way this is written, if that part of the
calculation is negative, it would reset to zero for further
calculations to production tax value, and at $30/barrel it means
there has to be a circumstance of $30 transportation costs. That
is unusual, but it could certainly happen. If prices go below
$20/barrel, he could envision even more circumstances where that
would happen.
Slide 38 displayed the different tax and feeder pipeline tariffs
(all-in tariffs) before adding a rough average of $3.37 for the
marine transport from Valdez to the typical refinery. So, for a
base at Prudhoe Bay the tax tariff is $6.13, but if production
is coming from Kuparuk, a company has to also pay the $0.32
feeder line to get it from Kuparuk to Pump Station 1, and you
are paying $6.45. Something like Endicott has a two-hour feeder
pipeline and gets it up to $8.35. But the outlier in there is
Point Thomson, the newest field that is about to come into
production this year; it has to get to Badami and the operator
has filed a $19.17 tariff for that. This means that the total
tariff to get to Valdez is $28.49, which added to the marine
transport gets one to $31.86 transportation cost. So, if Point
Thomson were to go into production for a year at $30 oil, they
would effectively have a negative value at the wellhead of
$1.86/barrel. So, over the expected production of 10,000
barrels/day, minus the royalty, there would be a negative gross
value of $5.9 million.
So, the provision proposed in SB 130 would be to say for any
given field that wellhead value would have to reset to zero,
meaning that negative $5.9 million wouldn't be allowed to offset
positive gross values in other production from that producer on
the North Slope. The effective tax there is about $2 million (35
percent of that little bit less than $6 million).
CHAIR GIESSEL said Point Thomson is on the threshold of
beginning production of gas liquids and they are operating under
the Point Thomson Settlement Agreement, which requires them to
produce liquids at a rate that they will be losing money (today,
it's $40).
MR. ALPER said yes, that was correct. He mentioned that there is
a technical issue embedded in this section. That is although the
gross value at the point of production is roughly comparable to
what they collect royalty on, it's not a royalty value. So, the
state doesn't run the risk of negative royalties. They do
however, face the circumstance potentially of the private
royalty tax being a negative calculation, which they had never
contemplated and it needs to be fixed in some way. If there is
production from private land - CD5 is an example - that
production should happen to fall through negative gross value at
the point of production, the statute doesn't account for what
might happen if the state is supposed to be collecting 5 percent
of that number in a private royalty tax.
4:38:21 PM
SENATOR STEDMAN said he never thought much about the Point
Thomson tariff, because it was never in their face. They still
have to have operating and capital costs there and asked if Mr.
Alper had any idea of what those are or do they use the average
out of the Revenue Sources Book.
MR. ALPER said presuming something along the lines of the
average cost, maybe a little bit less because they have just
come out of a very capital-heavy initial construction project,
it's fair to say the break even at Point Thomson is close to
$60/barrel. To a certain extent that is ameliorated by the fact
that they own the feeder pipeline that is getting the $19 tariff
(they are somewhat paying themselves).
SENATOR STEDMAN said that puts a fine point on the difficulty
the state has had in moving Point Thomson forward, and the big
price exposure industry had in moving it forward, especially if
they need $60 or $65 to break even. It doesn't help the state in
developing the basin.
4:40:19 PM
He asked under the settlement agreement to develop Point
Thomson, if the state is forcing them to do things they might
not otherwise do outside of that to minimize losses.
MR. ALPER answered that he is not an expert on Point Thomson
engineering, but it's a relatively simple system of only three
wells. They are obligated to produce those wells and compress
and reinject that gas for the next several years. In some ways,
it's a test system to see how the reinjected gas migrates back
through the field to determine the viability of an expanded
cycling process: if the gasline comes in, can they get good
production of liquids for a lot of the year while reinjecting
gas into the ground or will it be more viable to blow it down?
This is a "waystation" towards a much larger policy decision for
the owners of that field. Their settlement has a decision point
in 2018/19 over phase 2 when they are obligated to make a
decision that will lead to some sort of additional investment
for them in three or four years.
SENATOR STEDMAN said let's hope for $80/barrel oil and they are
profitable, so the state can make a little bit, too.
CHAIR GIESSEL said she hoped they become profitable, because
that is the state's gas pipeline.
4:42:35 PM
MR. ALPER went to the last part of the bill, the "deep" section
concerning municipal utility limitations. This was discovered
through paying historic tax credits and finding that is the
literal interpretation of the law. If a company is producing
most of the gas themselves (if they are a utility that owns a
gas field and a great bulk is going to their own turbines) that
use of gas isn't a sale for tax purposes - its' just their own
gas. But if they have a little bit of extra and sell to a third
party, that's a sale. That becomes revenue. For the purpose of
various credits, the question is whether the expenses that
offset that small amount of sale - the way the law is written
that all of the expense could offset that revenue, thus creating
(similar to the GVR NOL section) synthetic NOL (NOLs that don't
reflect the actual profitability of that company). They propose
to say that only the pro-rata share of the costs would be usable
to offset the revenue. The chart on the right side of slide 40
is current law illustrated by using a utility using 20 million
feet per day, burning 18 million feet in their turbine and
selling 2 million feet to someone else. If that gas is worth
$8/mcf, the revenue based on selling 2 million per day over the
course of the year is about $6 million feet.
If their lease expenditure is $3 (on all the gas), that's $21
million worth of lease expenditure. They could share a net
operating loss effectively of $16 million even though they
didn't really lose $16 million, and in Cook Inlet the state
would be paying them a 25 percent NOL credit of $4 million. The
bill proposes to say if you're selling only 10 percent of the
gas and using 90 percent of it yourself, you only get to account
10 percent of your lease expenditures against that revenue for
the purposes of any tax or operating loss. In this case, they
would be shown to be profitable, because only 10 percent of that
$22 million - $2 million - would be deductible. They would show
a $3 million operating profit and would not be receiving an NOL.
It's a relatively simple and technical non-controversial change
that is just trying to fix a literal interpretation of the law.
SENATOR MICCICHE said that is roughly an $8 million difference
in that case. He asked the overall effect statewide of utilities
not being taxed on volumes sold to third parties.
MR. ALPER answered that they are taxed on the volumes sold to
third parties (currently $0.17/mcf in Cook Inlet), and it would
be in the tens or low hundreds of thousands of dollars in
production tax as opposed to the $16 million operating loss that
would lead to the $4 million NOL. So, effectively that 2 mcf/day
times 700 mcf/year times the $0.17 tax is what that company
would be subject to.
SENATOR MICCICHE asked what the overall effect is on the
allowable lease expenditures.
MR. ALPER answered in the single digit millions of dollars.
SENATOR STOLTZE asked what their discussions have been with the
municipalities that have utilities that run on gas. Two come to
mind: the North Slope Borough and the Municipality of Anchorage.
COMMISSIONER HOFFBECK answered that he didn't know if they had
any contact with the North Slope Borough or ML&P.
MR. ALPER answered that the North Slope Borough is a little bit
different in this circumstance, because they are not the same
entity as those who own the gas fields and the production that
supply that. There is an actual transaction that occurs when
they sell their gas.
SENATOR STOLTZE said it seems a little odd that ML&P or the
mayor's office wouldn't have been a little more involved to
protect the interests of their consumers or be part of their
discussion. Have they outreached to them?
MR. ALPER answered they didn't specifically reach out to them,
but they are well aware of this issue. He hadn't heard anything
from them. The department is in contact with them through their
role as taxpayers, and it was in that role that they became
aware of the circumstance. Perhaps their non-responsiveness
indicates their recognition that this might be something that
should be corrected, but he didn't want to speak for them.
SENATOR STOLTZE said he would like to coax a response from the
largest municipality in the state on the impact to their
customer base.
4:49:22 PM
CHAIR GIESSEL said both committees in the other body that heard
this bill invited ML&P and they did not respond and they
declined to present to this committee a few days ago when the
other utilities were there. She is in the process of sending a
letter to the mayor to ask if he had a comment on this, but it
hadn't been executed yet.
SENATOR MICCICHE commented that this looks like it can't be more
than a half to three-quarter million dollar problem on an annual
basis in comparison to the hundreds of millions in chunks of
revenue they are talking about, and looks like a cost that will
be shifted to the ratepayer.
MR. ALPER replied that any tax that a utility would be paying
the state would be minimal and would most likely be offset by
the small producer credit, anyway. The credits they are enjoying
by having all of their lease expenditures, which could be in the
tens of millions of dollars per year to operate that field, are
only being offset by a relatively small amount of sales, then
the state could see losses in the tens of millions of dollars
with 25 percent of that eligible for an NOL credit.
4:51:28 PM
Slide 41 gets into the scenario analysis modeling for this piece
of legislation that came as requests from individual legislators
over the previous interim. In some ways they have copied
stylistically some modeling from PFC Energy and enalytica, the
legislature's consultants. Typically, the DOR has modeled oil
and gas as a North Slope-wide or Cook Inlet-wide model so there
is per-barrel spending on operating and capital, but it doesn't
really capture the nuance of an individual investment where the
capital spending is not evenly spread throughout the lifecycle
of the field. In fact, it's very front loaded. Likewise, the
operating doesn't happen until after they are in production and
it tends to be scaled with the production. And then the
production itself is on a curve that ramps up and ramps down.
Every small field follows the same left curve they see on
Prudhoe Bay.
This life cycle model shows the cash flow over the 30-40 year
life of a project for both the state's production tax and
credits as a standalone item, the all-state revenues (general
fund revenue), and also the producers' cash flow. They applied a
discount rate to all of these using the most recent track record
of the Permanent Fund earnings, which is 6.15 percent, to
represent the time value of money for the state's money in
Alaska, if the alternative is having the money in savings.
4:53:05 PM
The model looks at $30, $60, and $80/oil as well as the fall
forecast scenarios. They also worked in higher and lower price
scenarios due to a request from the House Finance Committee,
which he promised to provide this committee. They also modeled
the status quo versus the sum total of the changes in the
governor's bill.
They looked at new field on the North Slope with 50-million
barrels in the ground. This really means it peaks-out in the 10-
15,000/barrel/day range, comparable to smaller fields like
Oooguruk, the Nikiatchuq, and the Mustangs. They also looked at
a much larger field, the 750-million/barrel in-place field
comparable to the Armstrong field. That was done in three
different iterations using the 12.5 percent royalty, the 20
percent GVR, the higher royalty with the higher GVR (as Senator
Stedman alluded to earlier), and also what happens if half of it
is on private land. They also modeled the Cook Inlet scenario
for a 50-million/barrel field with a big question mark floating
above in 2022 when the tax caps in statute go away. He didn't
feel comfortable inventing a tax regime for Cook Inlet, so they
have a high and a low scenario, caps are extended effectively
with no production tax into the future versus when tax caps go
away, meaning the 35 percent net tax without any per-barrel
credit. However, he said, the real answer probably lies
somewhere between the two sets of modeling runs.
MR. ALPER said the committee substitutes that have passed in the
other body include a Cook Inlet-specific working group to look
at proposing a new regime for the next legislature to revise in
future years.
4:56:06 PM
Finally, slide 43 models gas scenarios of 670 bcf/ Cook Inlet
and Middle Earth gas fields that are roughly analogous to what
BlueCrest is looking to do; it would peak-out at about 50
mcf/day.
CHAIR GIESSEL asked where Furie would fall.
MR. ALPER answered that Furie is a little bit of an unknown.
Their phase 1 is probably around the same size, but from their
claims and from their somewhat aggressive investing in offshore
platforms, they have alluded to having a somewhat larger
resource base. What they talk about is having about 400/bcf. In
some of their earlier reports they talked about having trillions
of feet in place. Everyone is hopeful, but no one really knows
until they start deviating further out from their central point
to see how big the resource becomes.
4:57:21 PM
He said all the slides use the structure graphic. The upper left
hand corner is the production tax and tax credit alone scenario.
(Slide 44) This is credits the state is paying the producer
based on whatever it is they might be earning. In the case of a
North Slope field, it is almost entirely NOLs. The production
tax received is the blue curve in revenues starting after
construction is finished.
MR. ALPER explained when he talks about 50-million/barrels of
oil in place, there is an assumption of capex - maybe $12-
$18/barrel - that becomes the aggregate times the number of
barrels produced. So, a $12/barrel capex scenario for 50 million
barrels means $600 million is going to be spent, and most of it
will be spent in the first two years, but it get the 35 percent
NOL credit over several years. The state's negative cash flow
peaks out at around $50 million per year at the highest level of
construction.
The total state general fund cash flow (including the oil money
that goes to the Permanent Fund) is in the upper right-hand
corner. The production tax is represented by the green and
royalty is indicated by blue. In most years, royalty is the
state's largest revenue source. The purple line is the state
corporate income tax and a "small wedge" that isn't quite
visible at this level of resolution is the state's share of the
property tax. He said on the North Slope a large percentage of
the property tax actually accrues to the North Slope Borough and
that didn't show up on this graph. The producers' cash flow was
graphed on the lower left; the green bars represent a positive
after-tax cash flow after having been partially reimbursed by
the credits, once they are in production.
Finally, the lower right has some of the sum total data from the
colored graphs separated into the three chunks: the top one is
the production tax. In this scenario - $60 oil for a small
stand-alone oil field on the North Slope - the state spends $162
million on credits and receives $183 million in production
taxes, a positive revenue of $21 million. But if a time value
of money is assigned (net present value) to that calculation,
indicating that the state would be negative $37 million on the
production tax, alone, on that field.
Meanwhile, the second "chunk" is the total state cash flow where
the losses are a little smaller (negative $121 million). The
difference between that and the negative $162 million is there
are some years where the state is still paying out credits when
production has started and paying a little bit of royalty
revenue. In this "very stylized new North Slope field" the state
gains a value of $136 million. The same calculation is done for
the producers. The same discount rate was used, but the
producers look for a higher return on investment than 6 percent.
If that were the case, the so-called hurdle rate is where they
would be seeing a smaller number if they were to apply a 10 or
12 percent discount rate. This is the status quo scenario.
5:02:30 PM
MR. ALPER said he had three different scenarios in this
presentation and he would be happy to meet with any member
individually to discuss this "stuff" at length.
5:02:38 PM
He said these slides refer to HB 247 and he apologized for not
updating them to SB 130. The most visually different thing on
the tax credit side (in the upper left) is suddenly the negative
numbers get cut off at $25 million per year. However, as those
credits are earned for more years into the future the "tax
credit spend" gets shifted forward and creates some distortions
in the companies' cash flow (in the lower left). So, they really
need to look at the net effect changes.
The state's production tax discounted value, at $45/46 oil, goes
from a negative $37 [million] to a negative $10 [million], while
the credit outlay goes from a negative $162 [million] to
negative $101 [million]. Meanwhile, the total discounted value
of all the state's taxes goes from $136 million to $163 million.
Of course, as the state is gaining value from the companies,
their discounted cash flow goes from $112 million to $93
million. Delaying payment of some of the credits creates value
to the state through the time value of that money.
MR. ALPER said those numbers are relatively small if one can
consider $163 million small. The numbers get much larger when
looking at a large field. They modeled this at $80/oil with the
expectation that it's unlikely that someone will make what quite
literally is a $10 billion sanctioning investment to build out a
field of this size without an expectation of a higher oil price.
5:04:31 PM
He looked at a 750-million/barrel field at $80/oil. The most
jarring thing with a front-loaded field and that level of
expenditure is that the state's credit outlay is $2.8 billion
before it sees production taxes off that field. At the highest
point, the state is paying $800 million per year and for the top
three years about $550 million per year. That is the data set
that led the House Resources Committee to put in a $200-million
cap, because that is when the credits are really outside the
state's capacity no matter what else is going on - although that
would be a single partner. He explained that any of the caps in
the various versions of the legislation haven't accounted for
partnerships. If there are four partners, each earning a $25
million cap that would actually be $100 million, which would
change these numbers dramatically.
5:05:42 PM
In this field the state gets almost $9 billion in production tax
against the $3 billion in credit. With the time value of money,
the state makes $869 million. The state makes over $1 billion a
year for a few years at the peak of this project, an
extraordinarily good thing if it can get built. With a
discounted value of $3.5 billion and a relatively robust value
for the producer based on all of their assumptions (which by
their very nature are wrong), the company would get $2 billion
from this project.
5:06:21 PM
What Mr. Alper learned when he overlaid the $25-million per-year
cap is that this probably created too large a distortion for
this field. The state's cash-out went from $2.8 billion to only
$100 million; the state about doubled its discounted production
tax value from less than $900 million to $1.7 billion, and its
all-in cash went from $3.5 billion to $4.3 billion. Meanwhile
the company lost about one-third of the value from this field
going down from $2.2 billion discounted to about $1.4 billion
(slide 47). It's unlikely that someone is going to do this alone
with the governor's bill and four partners and a $100-million-a-
year cap, and the answer would fall somewhere between his two
examples.
5:07:29 PM
Being pressed for time, Mr. Alper jumped past the Cook Inlet
scenario that is similar to the North Slope small field
scenario, as far as how the numbers move. The Cook Inlet was
modeled for both the Cook Inlet tax cap expired and also the
Cook Inlet tax caps extended (not in the bill), but he wanted to
highlight that the larger presentations have summary tables at
the back. He put all of the summary tables in this presentation
so they are easily available. Slide 50 looks at the North Slope
oil scenarios and slide 51 looks at the non-standard royalty
scenarios (high and private royalty), the Cook Inlet oil
scenarios were on slide 52, and slide 53 had the various gas
scenarios for both Cook Inlet and Middle Earth (that has its own
statutory tax caps).
CHAIR GIESSEL thanked him for his presentation and recessed the
meeting to 7:00 p.m. to continue work on SB 130.
7:01:31 PM
CHAIR GIESSEL reconvened the Senate Resources Committee meeting
at 7:01 p.m. Present at the call to order were Senators Stedman,
Coghill, Costello, Wielechowski and Chair Giessel.
SENATOR COSTELLO moved the work draft CSSB 130(RES), version 29-
GS2609\W, as the working document.
CHAIR GIESSEL objected for explanation purposes.
7:02:36 PM
AKIS GIALOPSOS, staff to Senator Giessel and the Senate
Resources Committee, Alaska State Legislature, Juneau, Alaska,
explained the changes in the proposed work draft \W and
contrasted those to the changes in existing work order \A.
SENATOR MICCICHE joined the committee.
SENATOR STOLTZE joined the committee.
MR. GIALOPSOS said the changes were as follows:
1. The title is changed to reflect subsequent changes in the
committee substitute, and to conform to legislative drafting
protocol.
2. Section. 6 of the previous version A of the bill, dealing
with confidentiality requirements (in the event that the
qualified capital expenditure and well lease expenditure credits
in the A version were removed, but the NOL credit had remained)
is removed.
3. Language on page 2, line 31 to page 3, line 25 amends the
previous Section. 7 of version A by changing the interest rate
to 7 percent above the Federal Reserve rate. However, rather
than the full six years of accruing a compounded quarterly rate,
the interest will only accrue for only three years, and no
interest after year three. However, the statute of limitations
would be for the full six years.
4. Section. 8 of the previous version A of the bill, dealing
with confidentiality requirements, is removed.
5. Language on page 3, line 26, to page 4, line 28, amends the
previous Sections. 9, 10, and 11 of version A of the bill, by
incorporating a new definition of outstanding liability to the
state that is created in a later section.
6. Section. 12 of the previous version A of the bill, hardening
the floor at 5 percent, is removed.
7:05:00 PM
7. Page 4, line 29 to page 5, line 19, adds a new Section. 10,
repealing the calculation for the Cook Inlet tax cap, as well as
the subsection for the tax calculation for gas produced
elsewhere in the state for use in-state.
8. Page 5, line 20 to page 7, line 4, adds a new Section. 11,
conforming to Section 10.
7:05:34 PM
9. Page 7, lines 5-10, adds a new Section. 12, making oil and
gas produced in the Cook Inlet sedimentary basin after January
1, 2018, exempt from any production tax, and prevents an
explorer or producer in the basin from acquiring credits.
10. Page 7, line 11 through page 15, line 1, amends the previous
Section. 13 in the A version of the bill by removing references
to hardening the gross minimum floor, and conforming to the new
Section. 10.
7:05:46 PM
11. Page 15, lines 2-23, repeals the previous Section. 14 in the
A version of the bill, dealing with interest calculations, and
conforming to the new Section. 6 on interest calculations
(compounding interest only year one through three).
12. Page 15, lines 24 through page 17, line 10, conforms
Sections. 15, 16 of the bill to the new Section. 6 on interest
calculations and further conforming to those changes.
7:06:27 PM
13. Section. 17 of the previous version A of the bill, dealing
with recalculating the per-barrel credit on a monthly rather
than a yearly basis, is removed.
14. Page 17, lines 11-30, adds a new Section. 17 and reduces the
Qualified Capital Expenditure Credit to 10 percent as of January
1, 2017.
15. Page 17, line 31, through page 18, line 21, adds a new
Section. 18, eliminating the Qualified Capital Expenditure
Credit for the Cook Inlet sedimentary basin as of January 1,
2018.
16. Page 18, line 22, through page 19, line 17, amends the prior
Section. 18 of the A version of the bill, by eliminating the
provision that expired net operating loss credits after 10
years, and adds new language that lowers the Net Operating Loss
Credit for non-North Slope activity to 15 percent as of January
1, 2017. The provision that prevented the Gross Value Reduction
from enhancing a Net Operating Loss remains in the Committee
Substitute.
7:07:24 PM
17. Page 19, line 18, through page 20, line 15, adds a new
Section. 20 by conforming to Section. 19 of the Committee
Substitute, eliminating the Net Operating Loss Credit for the
Cook Inlet sedimentary basin as of January 1, 2018.
18. Page 20, line 16, through page 21, line 2, removes the
language in the previous Section. 20 of the A version of the
bill, related to the expiration of Net Operating Loss Credits
after 10 years.
7:07:51 PM
19. Page 21, lines 3-14, conforms to renumber subsections
earlier in the bill.
20. Section. 22 of the previous version A of the bill, dealing
with confidentiality requirements, was removed.
21. Sections. 23, 24, and 25 of the previous version A of the
bill, provisions that hardened the minimum tax floor, were
removed.
22. Page 21, line 15, through page 22, line 7, adds a new
Section. 23, lowering the Well Lease Expenditure Credit to 20
percent by January 1, 2017.
7:08:29 PM
23. Page 22, line 8, through page 23, line 3, adds a new
Section. 24, conforming to Section. 23 and eliminating the Well
Lease Expenditure Credit for the Cook Inlet sedimentary basin by
January 1, 2018.
24. Page 23, line 4, through page 24, line 11, adds a new
Section. 25 that grandfathers exploration activity that has
spudded but not completed in the Frontier Basins (referring to
statutes ending in 025).
25. Page 24, line 12, through page 25, line 5, amends the
previous Section. 26 of the A version of the bill by removing
the limitation on companies to receive credits if their global
revenues are in excess of $10 billion/year. It raises the per-
company annual refund credit from $25 million to $85 million,
and adds language to prevent a company from splitting into
subsidiaries in order to claim more than the per-company annual
refund limit.
7:09:33 PM
26. Page 25, lines 6-20, amends the previous Section. 27 of the
A version of the bill, related to Alaska resident hire. Rather
than tying the percentage of cashable credits to a company based
upon the rate of Alaska resident hire, the Department of Revenue
would be required to promulgate regulations, giving priority for
payment from the tax credit fund for companies whose employees,
and contractors, have a resident hire rate in excess of 75
percent.
27. Page 25, line 21, through page 26, line 5, amends the
previous Section. 27 of the A version of the bill, related to a
definition of an outstanding liability to the state. The current
definition now defines that only the same amount of a liability
to the state for oil and gas-related activity can be used to
reserve a credit refund.
7:10:18 PM
28. Page 26, line 8, conforms to the elimination of the Net
Operating Loss Credit in the Cook Inlet sedimentary basin; is
essentially the same language, renumbered, as the previous
Section. 28 of the A version of the bill.
29. The previous Section. 31 of the A version of the bill,
preventing the Gross Value at the Point of Production, from
going below 0, is removed.
30. Page 27, line 31, through page 30, line 14, adds a new
Section. 32 to conform to the elimination of the Cook Inlet tax
cap calculation, and the calculation for the tax on gas produced
elsewhere in state for use in-state.
7:10:58 PM
31. Page 30, line 15, through page 31, line 34, adds a new
Section. 33, conforming to Section. 10 and 33 of the bill.
32. Page 31, lines 5, through page 32, line 18, adds new
Sections. 34 and 35, putting a lifespan on oil or gas qualifying
for the Gross Value Reduction (new oil), to five years after the
production of commercial quantities. For oil or gas that
qualifies for the Gross Value Reduction that is in production as
of January 1, 2017, the Gross Value Reduction expires on January
1, 2021.
33. Page 36, lines 16-24, adds a new Section. 39 to conform to
the changes in Section. 10 of the bill.
7:11:37 PM
34. Page 37, lines 19-25, amends the previous Section. 37 of the
A version of the bill, related to the limiting of a tax credit
to the municipal entity. The only changes were conforming
changes to the legislative drafting manual.
35. The previous Section. 39 of the A version of the bill, the
prior definition of outstanding liability to the state, is
removed.
7:12:05 PM
36. Page 38, line 19, through page 39, line 27, adds a new
Section. 44, requiring a taxpayer seeking a refundable tax
credit, to post a surety bond in the amount of $250,000. The
bond would serve as financial relief to political subdivisions
and local contractors in Alaska in the event the taxpayer
entered into bankruptcy.
37. Page 39, lines 28, through page 40, line 2, conforms the
Sections. 45, 46, and 47, related to repealing statutes earlier
in the bill.
38. Page 40, lines 3-6, adds a new Section. 48, makes Sections.
7-9, 26 and 28 effective January 1, 2017.
39. Page 40, line 7, through page 42, line 9, adds new Sections.
49, 50, 51, and 52 placing transition language for the Qualified
Capital Expenditure Credit and the Well Lease Expenditure
Credit; the Net Operating Loss Credit and filing of a tax
credit.
40. Page 43, line 3, adds a new Section. 55, making Sections. 25
and 53 effective immediately.
41. Page 43, lines 4-5, adds a new Section. 56, making Sections.
10-16, 18, 20, 24, 32, 33, 39, 46, 51 and 52 effective January
1, 2018.
42. Page 43, lines 6-7, adds a new Section. 57, making Sections.
21, 22, 29-31, 36-38, 40, 41, 43, 47, 49, and 50 effective
January 1, 2022.
43. Page 43, lines 8-9, adds a new Section. 58, providing that,
except for Sections. 55-57, the Act takes effect January 1,
2017.
CHAIR GIESSEL opened committee discussion and invited Senator
Costello to talk about the interest rate.
7:14:14 PM
SENATOR COSTELLO said the average time it takes states to adjust
the interest rate for an audit is about three to four years, but
in Alaska it takes six years. So the CS goes back to 7 percent
compounded quarterly for the first three years and that is
followed by three years of no interest rate. The intent is to
have the interest rate be less punitive, but at the same time
not incentivize the department to take so long, because it is
not in anybody's best interest to have this take six years.
CHAIR GIESSEL asked her to also comment on how long it takes for
the new oil to become mature.
SENATOR COSTELLO responded that the first provision is fairer to
the companies and takes into account the effect of new oil on
the state's treasury and caps new oil at five years, much like a
child who passes the infancy stage. So, they said that five
years after commercial operations have started, the oil no
longer qualifies for the new oil credits.
CHAIR GIESSEL said Middle Earth is part of Senator Coghill's
district and they have heard from those producers that they are
just getting started, and asked him to comment on the changes in
the CS related to that.
7:17:06 PM
SENATOR COGHILL said it looks like they are grandfathered in
except that new language was added saying expenditures for wells
and exploration that had to be shown to be "spudded in" by July,
2016. There were no changes to the 023 credits, so "it's
workable."
CHAIR GIESSEL remarked that that area is working on energy
security for the Interior. She asked Senator Stoltze to explain
the new approach to the Alaska hire provision.
7:17:52 PM
SENATOR STOLTZE said that most Alaskans agree with the governor
in the laudable goal of trying to have resident preferences and
this bill provides "about as good a defendable chance" as any.
He liked that fact that a company is being judged on their
previous year's employment performance. It's a more honest
approach. Alaska hire is worth "pushing it as far as we can."
CHAIR GIESSEL invited Senator Micciche to comment about the
surety bond requirement for companies that go bankrupt,
something that happened a couple of times in his district on the
Kenai.
7:19:34 PM
SENATOR MICCICHE said it was a key issue during the Senate Oil
and Gas Working group discussions. Some larger companies that
were service providers as well as Mom and Pops will never
recover a penny from a couple of the companies that "bailed" and
dissolved. He explained that the surety bond is proposed for
$250,000 and it guarantees that first to be paid would be state
and political subdivisions that have an outstanding tax bill or
some other liability. Then the most important are identified as
persons furnishing labor, material, or renting or supplying
equipment to the applicant.
He told a story about how a very small Mom and Pop on the Kenai
Peninsula that was just simply servicing septic tanks was left
holding the bag for thousands of dollars that they couldn't
afford. This would clarify that small Alaska companies should
come first and be protected when a company can't live up to its
financial obligations. This is a reasonable approach that allows
a cash deposit if a company chooses not to take out a bond. It
is required until a company goes into production and then the
company can be relieved by the commissioner or the surety.
CHAIR GIESSEL said that Cook Inlet credits were deleted as of
2018, a significant step, with a step down in 2017 when the well
lease expenditure credits will drop down to 20 percent,
qualified capital expenditures will drop down to 10 percent, and
a well down to 10 percent. Then in January, 2018, all credits
are removed from the Inlet. Also, going forward, they agree to
have no tax structure in Cook Inlet.
She said the chart that enalytica provided to both bodies was
"pretty jaw dropping." She said that the North Slope companies
received $200 million in credits in 2015, and Cook Inlet
received $400 million in credits and there was virtually nothing
in any kind of revenue to the state. The approach here is to get
government's fingers out of the Cook Inlet and let the free
market work.
Why 2018? Chair Giessel said there are four reasons. Number one,
they are in the process of giving Agrium a "go-ahead" to restart
the fertilizer plant in Cook Inlet with corporate tax relief
that will be equal to the royalty for the gas that they will be
using. They will need about 80/mcf/day, which makes it an anchor
tenant. This de-constrains the market in Cook Inlet.
Second reason: Donlin Creek's pipeline EIS will be completed
around 2018. Here is another user of 10-30/mcf gas out of Cook
Inlet. Third, Hilcorp has a consent decree from the RCA that
will expire in 2018 freeing up a free market paradigm for the
pricing of natural gas. And, fourth, by 2018 they will know
whether AKLNG is going forward or not.
7:24:32 PM
Another change in the CS was made by eliminating the work group
that has been proposed by the House. The reason is that
establishing a working group going forward is like labeling a
"draft" on anything they do this year. The idea here is to rip
the Band-Aid off and take care of Cook Inlet and take care of
Middle Earth, do some changes on the credits for the North Slope
that they believe will still allow companies to go forward, but
will also help address Director Alper's chart, which shows the
state in unpaid credit card debt that continues to grow each
year.
7:26:00 PM
SENATOR WIELECHOWSKI asked when other members got this CS; he
just got it at 5:50 p.m.
CHAIR GIESSEL said it was not distributed before then.
SENATOR WIELECHOWSKI said there were quite a few changes and
asked if the administration could testify.
SENATOR MICCICHE asked what the chair's plan is for a consultant
review of the bill's effects.
CHAIR GIESSEL answered that Janak Mayer was listening on line
and the Department of Revenue and the governor had been briefed
on this an hour and a half ago. She also thanked Representatives
Mark Neuman and Tammie Wilson for being here. She also mentioned
that working group members Senators Wielechowski, Stoltze,
Micciche were there and thanked them. She invited the
administration forward.
7:27:52 PM
COMMISSIONER HOFFBECK said as an overview, the department is
largely in agreement with many areas of SB 130, and agrees that
this is significant legislation in terms of Cook Inlet. Allowing
the Middle Earth credits to stay in place longer is something
they recognized also in their bill, because it is an area that
is in its infancy and needs a little bit more time to get going.
There were no changes to the Governor's bill on NOLs for North
Slope. However, it changes the cash flow credit cap, which the
governor had capped at $25 million. The earlier versions went to
$200 million and $100 million. Now it's at $85 million, which
they will model tomorrow. Their biggest concern was that leaving
the NOLs in place left the state exposed to paying large sums in
credits and some kind of control was needed for the state's
annual outlay.
SB 130 did not adopt the 5 percent hard floor, one area they
don't see exactly the same. But the Governor said this is all in
pencil recognizing that this bill has a lot of savings and the
answer is in the total numbers, not necessarily in any
individual provision.
COMMISSIONER HOFFBECK said they would have liked more
confidential information disclosure, because when dealing with
NOL credits is a little harder than well lease expenditures or
qualified capital expenditures that are a little more project-
focused and might be a little easier to report.
7:31:23 PM
The GVR sunset at five years is another very significant
provision that wasn't in the Governor's bill. It was discussed
and that is seen as a very significant difference.
The interest of 7 percent for three years and no interest after
that: their goal is to audit within three years and they don't
have a lot of heartburn with giving themselves a little more
incentive to get to the three-year audit window. They also
recognize how onerous six years of high interest rates can be on
an adjustment and this provision provides a balance. They
appreciated the fact that the provision allowing for credits to
be applied against outstanding liabilities was left in place.
7:32:41 PM
COMMISSIONER HOFFBECK said they see some leakage of value in
changing the annual true-up to monthly, but that is something
that only applies in years of significant volatility and they
understand the concern.
They support Alaska hire, but had not thought about using it as
a mechanism for cuing a company to the front of the credit
program. They thought that incentive was a good way of dealing
with it if there is ever a shortage in the money available to
pay the credits.
He said that SB 130 takes out the municipal loophole with the
surety bond, and that is also a good idea. Eliminating the
working group is consistent with the Governor's treatment of
Cook Inlet. They agree that the working group inserted
uncertainty into the process. People want to know what they are
working with and want a decision to be made.
The sliding scale a little different, but again, the
Commissioner said it needs to be modeled within the totality of
the numbers. He said they could have the model done by mid-day
tomorrow.
CHAIR GIESSEL said that would great and thanked him.
7:35:38 PM
SENATOR MICCICHE asked the logic behind picking $25 million for
the credit cap since this bill caps it at $85 million.
COMMISSIONER HOFFBECK answered that it was an "anchor number"
that had been used in past legislation. They used it as a
starting point recognizing that it would be a point of
discussion. They also talked about inflation proofing, which
would have brought it up into the $40-million range.
7:36:39 PM
CHAIR GIESSEL said the $85 million is close to what the 028
fund, at $73 million, is this year.
SENATOR COSTELLO commented that the Governor has stated that
transparency is important and asked if she assumes correctly
that companies can provide information related to their business
and receive some assistance.
COMMISSIONER HOFFBECK answered that is envisioned in SB 130. If
they come forward and ask for additional cashable support, it
would be in an open process, and therefore, there would be
little bit more knowledge of it. The transparency issues helps
the legislature and the public more, because the department sees
all the numbers and knows what is going on, but they can't share
those numbers to help people understand the thought process and
why they are moving forward. But the public has every right to
know why the state is "writing big checks."
7:38:46 PM
SENATOR MICCICHE said 2014 was a perfect storm situation for the
annual versus monthly true-up, and he asked if they recognize
that their example has a fairly low probability of becoming a
typical trend in oil prices and if that is a significant issue
for the state.
COMMISSIONER HOFFBECK answered that it could be. Right now it
looks like oil prices are going to be constrained between $35
and $65. At $35, people start laying down their equipment,
because they are losing money. So, you see a reduction in supply
as fields decline. Once the supply/demand becomes unbalanced,
prices will start to climb. When they hit the $65 price point, a
lot of oil can be brought on line relatively quickly. So, they
think it's going to bounce around in that range for quite a
while, and when it's in that range it won't be a huge issue. But
because there is only about a 3 percent oversupply currently
being produced, there is a chance that a spike in price could
happen temporarily. Certainly, this bill is consistent with the
fact that the state has an annual production tax, and it,
therefore, is a policy decision.
MR. ALPER added that looking back through the modern era and
Alaska as a net profits tax regime, he could imagine an impact
if a similar tax regime were in place in the later months of
2008 and the early months of 2009 when the price of oil dipped
from the high $140s down to $30-something and then came back up
to the $60s through the 2009 legislative session. Everyone could
all hope for volatility on the upside next year.
SENATOR WIELECHOWSKI asked for a sense of how much more or less
SB 130 will generate for the state compared to the governor's
bill.
MR. ALPER replied that he would try to be evasive until tomorrow
after the modeling has been done. In a general sense, all of the
fiscal notes that the chart format is using are a mixture of
revenues items and savings from expenditures on credits. The CS
before the committee, with the absence of the floor hardening
provisions, definitely wouldn't see as much on the revenue side,
but with the more aggressive Cook Inlet ramp-down they would
probably see more on the savings of credit spending, especially
in the permanent savings of credits.
The more aggressive tax caps in the governor's bill have a
bigger short-term impact without question, but to a certain
extent, some of that rolls forward into future years where they
might see a smaller or even a negative impact as companies are
getting the second, third and fourth chunk of their $25 million
cap a year. That would have a flatter impact than the $85
million limit. He guessed it's going to be a larger fiscal note
than the House Finance CS, but somewhat smaller than the
governor's original bill.
SENATOR WIELECHOWSKI asked if the House's fiscal note is $900
million.
MR. ALPER answered about $150 million.
SENATOR WIELECHOWSKI said the fiscal note says "leaves same" on
the Senate version of the North Slope NOLs.
COMMISSIONER HOFFBECK answered that means the same as the
governor's bill.
7:44:27 PM
SENATOR WIELECHOWSKI asked him to explain what the explanatory
paper says about the sliding scale. The Governor's bill says no
change in scale - can't take below 5 percent, and SB 130 says no
change in scale - 4 percent status quo.
MR. ALPER explained the one part of SB 21 that truly hardened
the floor referred to the sliding-scale, per-barrel credit for
legacy oil from zero to $8. That calculation cannot bring a tax
below 4 percent, and that is solid. This is where the state's
revenue came from in 2015 and that it is still getting. The
Governor's bill proposed saying other credits - the operating
loss credit, the $5/barrel credit, small producer credit, et
cetera also - could not go below the floor. That is the part
that was removed from the CS. The Governor also proposed
bringing all of that to 5 percent. So, the sliding-scale credit
continues to be hardened to 4 percent as in current law, and
it's not being increased to 5 percent as in the governor's
proposal.
CHAIR GIESSEL clarified that she drew up the quick reference
document he was referring to.
SENATOR WIELECHOWSKI said he would just wait for the
department's analysis tomorrow.
SENATOR MICCICHE said it looks like at $40/barrel the state
saves about $28 million in hardening the floor from 4 to 5
percent until the price goes over the minimum range at $75. He
asked Mr. Alper if he agreed that the reduction in Cook Inlet
credit dramatically offsets hardening the floor.
MR. ALPER answered that the chart Senator Micciche was referring
to talked about the specific impact of increasing the floor from
4 to 5 percent. That was sort of the second phase of the minimum
tax change, the first phase being hardening the other credits to
the 4 percent level and that change brought in about another $50
million in addition to the $50 million in the original bill
(according to the fall forecast). But by the time the spring
forecast came out, the North Slope major producers applied for
much larger NOL credits, and the fiscal impact of the hardening
became close to a $150 million line item (with that chart, it
boosted the revenue to about $200 million). That is the full
revenue impact of the floor hardening and increasing provision
that is not in the CS.
SENATOR MICCICHE asked a question about how the value of
hardening the Cook Inlet credits versus eliminating them would
compare to keeping the 4 percent floor.
MR. ALPER responded that the Cook Inlet credits in the
enalytica's chart were $404 million in 2015 and that number is
scheduled to step down a little bit just because of a reduction
in activity in the Cook Inlet. Whatever that number is reduced
by is what they will be saving. Hardening the floor means that
NOLs aren't being used to go below the floor and they will
eventually be paid to the company through reduced taxes in a
future year. Other than the time value there is "something of a
net zero in that hardening," but that increases as the stack of
NOL credits get carried forward.
CHAIR GIESSEL removed her objection to adopting the CS and
finding no other objections, announced that CSSB 130(RES), 29-
GS2609\W, was before the committee. She then invited Mr. Mayer
to comment on the CS, which was posted on BASIS an hour and a
half ago.
7:49:59 PM
JANAK MAYER, enalytica, Legislative Consultant, Washington,
D.C., said he liked the way the chair framed the Cook Inlet
versus North Slope credit/revenue picture in the context of
enalytica's slide. He said they tried to highlight consistently
that for FY15 they are talking $2.2 billion in total restricted
and un-restricted revenues. Compare that to [$324 million] in
credits. Cook Inlet is a very different ratio with less than
$100 million in revenues and more than $400 million in credits
for FY15.
Other types of credits: the North Slope has two credit areas
left. One is the trailing expenditure things like exploration
credit, the small producer credit, the dollar per-barrel credit,
and the NOL credit, a mechanism of deducting expenses when there
isn't sufficient revenue to deduct it in a current year. All net
profit taxes have the ability to deduct expenses in an
appropriate year, in most cases as a carry forward against a
future liability. In all situations, the amount of the NOLs
isn't changed by any of the proposals before them. Whether the
credits can be used to go below the floor or when the credit can
be taken are simply about the timing of payments, not about the
actual amounts of the payments.
7:54:51 PM
MR. ALPER said having priorities makes a lot of sense. What is
proposed in Cook Inlet goes beyond the Governor's bill or some
of the House proposals. What they have said consistently on Cook
Inlet is that with ongoing drilling one doesn't have all the
expenses of new facility developments; simple ongoing drilling
in the mature fields is economic in a wide range of
circumstances. Enalytica has said economics are most difficult
when they are constrained by a new development with substantial
facilities, since those are additional capital expenditures.
Those could be economic if one has a substantial resource and
demand, but without that, they are very difficult.
The obvious concern with this approach is the timing. If one
simply cuts off all of the credits except the net operating loss
effective July 2016, companies have already committed to major
work programs. So, that suddenly puts them in jeopardy and
potentially prevents the work from going ahead. Pushing that
date out would allow ramping down a little more slowly and could
resolve that problem.
MR. MAYER said the small independent producers are stopping now;
in particular, Furie at Kitchen Lights started production last
year and now has had a small amount of gas production. BlueCrest
is making substantial progress towards their oil project; one
wants to see companies like that able to continue the work they
are doing through next year and able to get to the point where
they have recovered some substantial portion of their initial
investment and can at least be cash-flow-sustaining moving
forward. Hopefully Cook Inlet can get to the point of broad free
market principles going forward from 2018 rather than continuing
to rely on government intervention.
7:58:47 PM
He said stopping the massive outlay of credits is okay as long
as that can be seen as genuine and durable and there is every
reason to think that could be quite a favorable environment for
investment - in particular for ongoing reinvestment in the
mature fields. The biggest barrier to that at the moment is the
much uncertainty as to what the future fiscal regime looks like.
One could address that by making it very clear that this is
absolutely the future of the regime and it's not going to
change.
On the North Slope the question of old versus new oil: at the
moment the 4 percent floor is essentially hard all the way down
until the point that a company stops being eligible for a net
operating loss (NOL). That is a substantial change from the
situation under ACES and before where most of the production tax
revenue for the last year or two has come from. Once a company
reaches the point of being eligible for NOL credits, that by
definition is levying a tax on a producer with nothing but a
loss. In that sense, one should be very careful about proceeding
with floor hardening in terms of it coming at a time when
companies are most strapped for cash or when cash is actually
negative and going out the door. Trying to extract more on that
front seems like not necessarily an ideal policy move.
MR. MAYER advised because one can carry expenses forward, the
impact of the floor hardening is a question of timing and not of
absolute amounts. One needs to keep in mind what the dynamic of
pushing those payments out into future years looks like in a
time when eventually oil prices do rise and how that plays into
how the system works. At the moment it's relatively easy for the
Alaska public to understand that the state's fiscal situation is
highly constrained because of low oil prices. It's one thing to
understand that, but it's another for prices to start to rise
and to find that the state is still financially constrained, not
because of oil prices, but because of the hangover, a
substantial hangover potentially, of having to pay deferred
credits. Hardening the floor simply means that there is this
trailing tail of NOL credits that can be carried forward
potentially into many years. Not hardening the floor means not
putting more pain on the companies that are cash-flow negative
at the moment. But it also recognizes essentially that liability
to the state now rather than pushing it off into future years.
8:03:12 PM
On the question of the cashable NOL amounts, Mr. Mayer said they
have said that the $25-million cap has a substantial impact on
companies that are eligible for the cashable NOL credit who are
currently developing. In many cases, that could mean one is
making a $1.3 billion capital investment. For that sort of
project, one might only need $300 or $400 million of initial
capitalization combined with cashable NOL credits to make it
work before it came self-sustaining from the cash flow
perspective.
A $25-million cap substantially changes that picture. It could
take a $350-million project and turn it into a $500 million
project in many cases. For companies currently undertaking this
activity, that is a major impact. The impact, for instance, of
the $100-million cap is much less in most cases, at the moment
not binding on most companies and simply will protect against a
future major development that could lead to major credit
outflows for the state. An $85-million cap might start to have
some effect on some current companies, but it avoids many of the
worst effects of a $25-million cap.
8:05:17 PM
Finally, Mr. Mayer talked about the impact of moving the gross
value reduction (GVR) to five years. When SB 21 question of
should this time be limited for the life of a new project was
discussed. One could structure that benefit in a range of ways,
but one of the key things to understand is that for many new
developments, there are several years of substantial ongoing
drilling and reinvestment that takes place before a project can
sustain that initial production plateau for five years and
become a taxpayer. While there is substantial merit around the
question of extending the GVR indefinitely or not, he could do
some modeling, but it may well be the case that for many new
developments a five-year limit actually means that the GVR
itself, has very little impact at all either on economics or on
the total amount of tax that the project pays.
The question then is for existing GVR project owners and
investors the substantial change in the tax system and in those
circumstances the GVR is actually delivering the benefit it was
designed to do - in terms of making the economics of a new field
on the North Slope more attractive.
8:07:34 PM
CHAIR GIESSEL asked when his analysis would be available.
MR. MAYER answered tomorrow afternoon.
[SB 130 was held in committee.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| CSHB 216(RES) - Sponsor Statement.pdf |
SRES 4/11/2016 3:30:00 PM |
HB 216 |
| CSHB 216(RES) - Legislation Ver. N.pdf |
SRES 4/11/2016 3:30:00 PM |
HB 216 |
| CSHB 216(RES) - Sectional Analysis.pdf |
SRES 4/11/2016 3:30:00 PM |
HB 216 |
| CSHB 216(RES) - Fiscal Note - DNR-MLW-3-14-2016.pdf |
SRES 4/11/2016 3:30:00 PM |
HB 216 |
| CSHB 216(RES) - Summary of Changes (Ver. W to N).pdf |
SRES 4/11/2016 3:30:00 PM |
HB 216 |
| HCR17 Sponsor Statement 2-1-2016.pdf |
SRES 4/11/2016 3:30:00 PM |
HCR 17 |
| CSHCR17 Summary of Changes 3-15-2016.pdf |
SRES 4/11/2016 3:30:00 PM |
HCR 17 |
| HCR17-LEG-COU-03-15-16.pdf |
SRES 4/11/2016 3:30:00 PM |
HCR 17 |
| HCR17-Final Version E.PDF |
SRES 4/11/2016 3:30:00 PM |
HCR 17 |
| CSSB130-Explanation of Changes-Version W.pdf |
SRES 4/11/2016 3:30:00 PM |
SB 130 |
| CSSB130-Version W.pdf |
SRES 4/11/2016 3:30:00 PM |
SB 130 |