Legislature(2015 - 2016)BARNES 124
03/21/2016 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB247 | |
| HB286 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| *+ | HB 286 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 247-TAX;CREDITS;INTEREST;REFUNDS;O & G
1:05:58 PM
CO-CHAIR NAGEAK announced that the first order of business is
HOUSE BILL NO. 247, "An Act relating to confidential information
status and public record status of information in the possession
of the Department of Revenue; relating to interest applicable to
delinquent tax; relating to disclosure of oil and gas production
tax credit information; relating to refunds for the gas storage
facility tax credit, the liquefied natural gas storage facility
tax credit, and the qualified in-state oil refinery
infrastructure expenditures tax credit; relating to the minimum
tax for certain oil and gas production; relating to the minimum
tax calculation for monthly installment payments of estimated
tax; relating to interest on monthly installment payments of
estimated tax; relating to limitations for the application of
tax credits; relating to oil and gas production tax credits for
certain losses and expenditures; relating to limitations for
nontransferable oil and gas production tax credits based on oil
production and the alternative tax credit for oil and gas
exploration; relating to purchase of tax credit certificates
from the oil and gas tax credit fund; relating to a minimum for
gross value at the point of production; relating to lease
expenditures and tax credits for municipal entities; adding a
definition for "qualified capital expenditure"; adding a
definition for "outstanding liability to the state"; repealing
oil and gas exploration incentive credits; repealing the
limitation on the application of credits against tax liability
for lease expenditures incurred before January 1, 2011;
repealing provisions related to the monthly installment payments
for estimated tax for oil and gas produced before January 1,
2014; repealing the oil and gas production tax credit for
qualified capital expenditures and certain well expenditures;
repealing the calculation for certain lease expenditures
applicable before January 1, 2011; making conforming amendments;
and providing for an effective date."
[Before the committee was the proposed committee substitute (CS)
for HB 247, Version 29-GH2609\P, Shutts, 3/18/16, adopted as the
working document on 3/19/16.]
1:06:29 PM
CO-CHAIR NAGEAK stated that the Department of Revenue will
provide the committee with a presentation on Version P.
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
on behalf of the governor, provided a PowerPoint presentation
entitled, "Oil and Gas Tax Credit Reform, Initial Reaction to CS
HB 247(RES)\P." He began by thanking the committee for the
opportunity to respond to Version P, the proposed committee
substitute for HB 247. He explained that slides 2-3, "History
of Oil and Gas Production Tax Credits," lay the groundwork on
[the reason for HB 247]. The state's program of refunding tax
credits began to grow in roughly 2010, he said, although the
state has refunded tax credits since fiscal year (FY) 2007.
Drawing attention to the chart labeled, "Refunded Tax Credits by
Region," he pointed out that the trend over the last two or
three years has been from being a very North Slope centered
expenditure to a very non-North Slope, predominantly Cook Inlet,
centered expenditure. For 2015, the last complete year, the
expenditure on refunded tax credits was $628 million, of which a
little over $400 million was for outside the North Slope.
MR. ALPER moved to slide 3, recounting that last year the
governor line-item vetoed the tax credit appropriation language
limiting the spend for the current year to $500 million. Of
that $500 million, about $473 million has actually been spent.
Of that $473 million, [58] percent was non-North Slope, so the
trend is continuing from last year - about $200 million was from
North Slope and $273 million was from Cook Inlet and the
Interior. The payout in credits was predominantly on credits
that were earned based on activity that took place in calendar
year 2014. The department is anticipating $700 million in total
demand, but those will generally not be issued until this summer
and will be paid in the next fiscal year. The gap of $200
million between the $500 million authorized and the $700 million
expected is built into DOR's forecast number for FY 2017.
1:09:10 PM
MR. ALPER displayed slide 4, "Major Bill Themes," and noted that
the governor's bill as originally brought before the committee
had several larger themes of what the administration was trying
to do and why. One theme was to reduce the state's annual cash
outlay, something that is very important in a cash-constrained
environment. Another theme was to protect the net operating
loss [credits] because those level the playing field by
providing a benefit to the entities trying to establish
themselves in the oil patch as opposed to the incumbent
producers. Another theme was to put limits on repurchasing so
that single companies do not get very large amounts. The other
themes were to: strengthen the minimum tax so that the state's
minimum revenue in these low price environments would be
protected in some way; seek more open and transparent activity
so names and numbers could be talked about better; and honor and
pay the credits earned to date through any transition period.
MR. ALPER showed slide 5, "Major Bill Concepts in Governor's
Proposal," and stated he will discuss the six major concepts in
the governor's original proposal, how those concepts evolved,
and how they have been amended in Version P. Those concepts
are: the exploration credits; the Cook Inlet drilling credits;
the repurchase limits; the removal of exceptions/loopholes; the
strengthening of the minimum tax; and other smaller provisions.
1:10:27 PM
MR. ALPER presented slide 6, "Summary of Major Bill Provisions,
Exploration Credits," and examined the exploration credits. For
the most part, Version P keeps intact what the administration
was looking to do. For the North Slope and Cook Inlet, the
alternative credit for exploration under AS 43.55.025(a) expires
on July 1, 2016; for Middle Earth this credit expires in 2022.
The original bill allowed these to expire, as does Version P.
The "super credits," the jack-up rig credit in Cook Inlet and
the frontier basin credit in the Interior expire this July.
These credits are allowed to expire under both the original bill
and Version P. A provision in the original bill preemptively
repealed several unused, dormant, exploration credit programs
[in AS 38.05.180(i) and AS 41.09] in order to clear the decks of
those and to clarify that it is not the intention to have stand-
alone exploration credit programs on the books. This provision
was retained in Version P.
MR. ALPER continued examining exploration credits on slide 6,
explaining that the original bill included a specific Department
of Natural Resources (DNR) data sharing requirement [from AS
43.55.023(b)]. The department worked with the committee to try
to revise that and make it work, but in the end the committee
chose to not keep this provision in Version P, primarily because
there is a data sharing requirement under AS 43.55.023(a)(2),
the capital credit for exploration that does provide the data to
DNR. Since that credit is going to remain on the books another
data sharing provision does not need to be explicitly added in
the bill's language. Responding to Representative Josephson, he
clarified that Version P maintains the 20 percent [qualified
capital expenditure] credit; AS 43.55.023(a)(2) allows that
credit to be paid for exploration expenses and that spending
includes a link to the language in the exploration credit that
says seismic and other data must be shared with DNR, data which
DNR can eventually release to the public.
1:12:37 PM
MR. ALPER brought attention to slide 7, "Summary of Major Bill
Provisions, Cook Inlet Drilling Credits," and said that the more
material change in Version P was made to the Cook Inlet drilling
credit section of the bill. The governor's original proposal
looked to repeal completely the 20 percent [qualified capital
expenditure (QCE)] credit [AS 43.55.023(a)] and the 40 percent
[well lease expenditure (WLE)] credit [AS 43.55.023(l)]
effective July 1, 2016. The decision in Version P was to phase
out the WLE [credit] over 2017 and 2018 and to keep the QCE
credit in place until 2022. He said 2022 is a forward looking
year tied to the plan for a broader Cook Inlet tax reform bill.
The governor's original bill looked to maintain the 25 percent
[net operating loss (NOL)] credit, while Version P reduces it
from 25 percent to 10 percent [beginning in 2017].
MR. ALPER continued on slide 7 and outlined the impact of the
changes in the aggregate of Version P. The governor's bill, he
said, was looking to reduce the total support for spending in
Cook Inlet to 25 percent beginning in FY 2017. Version P
reduces that total support to 30 percent beginning midway
through FY 2018, a delay of 18 months in the full implementation
versus what the governor's bill proposed. By preserving the 20
percent capital credit and reducing the loss credit, Version P
changes somewhat the actual companies that will be receiving the
credit support, specifically the companies outside the North
Slope that are producing oil and gas and that if profitable are
held harmless under the Cook Inlet tax caps that go back to the
production profits tax (PPT) bill of 2006. Under Version P,
those companies that may be profitable and not paying
substantial taxes would be able to receive the 20 percent
capital credit, whereas in the governor's original bill those
companies would not get any credit support. Version P also adds
language setting up a legislative working group to get to
planning towards the broader Cook Inlet tax reform that needs to
be on the books by 2022.
1:14:50 PM
MR. ALPER addressed slide 8, "Summary of Major Bill Provisions,
Repurchase Limits." He noted that these are statewide changes,
although predominantly understood North Slope projects. The
governor's original bill proposed a per company per year cap of
$25 million, meaning if a company earned credits in excess of
that number those would have to be carried forward into the next
year or held onto until that company had a tax liability.
Version P has a $200 million per company per year cap. The
governor's original bill also looked at three other provisions:
to exempt any payment at all for very large companies with an
excess of $10 billion of annual revenue; to provide an Alaska
resident hire provision; and to provide a 10-year sunset on
carried-forward credits where those credits could be lost
outright. Version P eliminated those three provisions.
MR. ALPER said the impact of the $200 million per company per
year cap is to protect the state in the event of a very large
outlier project, such as proposed by Mr. Armstrong [of Armstrong
Oil & Gas Inc., owner of the Pikka Unit]. For example, DOR's
modeling of a comparable project shows that the state's credit
liability in advance of getting substantial revenue could reach
as much as $800 million per year. He clarified that Version P,
as currently written, does not consider the possibility that if
Mr. Armstrong were to proceed with this project and bring in
three partners, each of the four partners could receive that
$200 million cap and the state would potentially have an $800
million liability.
1:16:27 PM
REPRESENTATIVE JOSEPHSON posed a hypothetical scenario in which
Armstrong Oil & Gas Inc. has two partners and asked whether the
state's liability would become $2.4 billion or would remain $800
million.
MR. ALPER replied that the modeling done by Tax Division staff
looked at the economics of the overall project life cycle. A
large project like that had about $9 billion in capital
expenditure associated with it, so the lifetime total amount of
credits was about $3 billion over several years. The peak year
of credits, regardless of the number of partners, was $800
million. The $200 million cap if it were a single company would
change that project somewhat. If the project owner came in with
multiple partners it would be less of a change, meaning that
three partners or four partners could earn $600 or $800 million
collectively and only the difference between that number and
$800 million would be carried forward into the next year.
1:17:29 PM
REPRESENTATIVE SEATON asked what the state's exposure would be
in a scenario of 750 million barrels of shale oil with multiple
players within a unitized area.
MR. ALPER responded that the North Slope taxpayers pay tax as a
company based on the company's total North Slope operation. The
state does not have any sort of ring fencing from unit to unit.
Regardless of how many partners there were, each could earn up
to the $200 million cap. The governor's original bill was
structured the same way as Version P, only the limit in the
original bill was $25 million instead of $200 million. With a
35 percent net operating loss credit, which is the primary North
Slope credit, a company would need to have $471 million a year
in operating loss at 35 percent to earn the full $200 million.
So, multiple partners in a shale development earning at that
level would be a very large project.
1:19:09 PM
MR. ALPER resumed his presentation, turning to slide 9, "Summary
of Major Bill Provisions, Repurchase Limits (cont'd), Historic
Notes on large annual credits." He explained that a look was
taken at DOR's historic record from 2007 through the current
fiscal year to get a sense for how many of these large payments
there have been over time. There has been only one instance of
a company in a single year earning more than $200 million a year
in tax credits. There have been five instances where one
company received between $100 and $200 million in a year. And,
there have been eleven times where a company has received
between $50 and $100 million [in one year]. Those sixteen
transactions are the difference between what the governor's
original bill was suggesting. There is an even larger number
between $25 and $50 million, he added, but there was not enough
time to do that much research.
1:19:59 PM
REPRESENTATIVE HERRON, in regard to repurchase limits, posed a
scenario of four partners. He asked whether all partners would
automatically get the credits or whether a process must be
followed such that some partners would get more than others.
MR. ALPER replied that the answer depends on who the partners
are and the ratio of their expenditures. Four equal partners,
each spending $571 million per year, could each max out at the
[$200 million] level. It is an operating loss credit and to
qualify all those expenditures would have to qualify; certain
types of activities do not qualify for credit. If some of those
credits had a smaller participation, a company's credit would be
capped at 35 percent of its actual spend. If a partner in
question was a major producer that is ineligible to get cash
because of the existing limit in statute where a company with
more than 50,000 barrels a day in production cannot get cash
credits, that producer would have to use its credits to offset
its tax liability. If the producer had a tax liability, the
producer could wipe it down to zero. But, if the producer does
not have a tax liability, the producer would have to roll it
forward into the next fiscal year.
REPRESENTATIVE HERRON, regarding the historic instances, asked
whether Mr. Alper has a ballpark figure of how many companies
have received $49 million and below.
MR. ALPER answered that that would be hard to do. Including the
current fiscal year, he said, a touch less than $3.5 billion in
checks for credits have been written. "Looking at the numbers
before us," he continued, "this represents about a billion and a
half dollars, I'm guessing; so, another $2 billion in smaller
credits in smaller numbers."
REPRESENTATIVE HERRON inquired whether that is spread over 20,
30, 40, or 50 companies.
MR. ALPER replied it is probably a much larger number. There
are some very small numbers, there are some very small junior
partners in large fields who happen to own a little acreage who
are getting a tiny share of it. There is a very large number of
transactions in a year. There is a concentration in a few big
ones, but there is a lot of line items.
1:22:20 PM
REPRESENTATIVE JOSEPHSON addressed the previously mentioned
hypothetical project of 750 million barrels, a large Pikka-sized
project, with $800 million theoretically if there was or was not
a number of partners. He asked whether the $500-$600 [million]
in repurchasables would be in addition to the $800 million, such
that the state's exposure with what Mr. Armstrong contemplates
would be $1.4 billion at least in FY 2017.
MR. ALPER responded that DOR currently has no such projects in
its forecast. If, say, DOR is forecasting $600 million in a
given year and then a company comes in and says it is going to
spend $2 billion next year, then, yes, DOR would have to adjust
the forecast by 35 percent of that in addition to what it is
already forecasting.
1:23:23 PM
MR. ALPER returned to his presentation, noting that the historic
instances outlined on slide 9 are for both the North Slope and
Cook Inlet, although the larger numbers are concentrated in the
larger North Slope projects that have occurred.
MR. ALPER moved to slide 10, "Remove Exceptions/Loopholes," and
thanked the co-chairs as well as committee staff for working
with DOR and allowing DOR to make its case on this. For the
most part, he said, these issues were left intact in the
committee substitute. Under Version P, a company cannot use the
gross value reduction (GVR), the new oil tax reduction, to
increase the size of a net operating loss credit. As was shown
by the legislature's consultant, Mr. Mayer of enalytica, this
could lead to instances of companies getting very large credits,
in some cases greater than 100 percent of their loss. The other
provision kept in Version P is the municipal utility exception
where if a municipal utility is selling a portion of its gas to
a third party, the utility only gets to deduct a pro-rata share
of its lease expenditures against that sale for the purpose of
calculating any credits.
MR. ALPER displayed slide 11, "Strengthen Minimum Tax," and
pointed out that several subsections in the original bill looked
to strengthen or increase the size of the minimum tax floor.
Provisions that would have impacted the legacy/major producers,
included: the idea that a [net operating loss] credit in an
extended low price scenario cannot be used to reduce payments
below the [4 percent] floor; the idea that at true-up companies
cannot use per-taxable-barrel credits earned in one month
against taxes accrued in another month; and the idea of
increasing the minimum tax from 4 percent to 5 percent.
Provisions that would have impacted new oil producers included:
extending the minimum tax to GVR-eligible new oil, which
currently can go as low as zero; disallowing the small producer
credit from reducing tax payments below the floor; and
increasing the minimum tax from 4 percent to 5 percent.
However, he said, all of the aforementioned provisions impacting
the minimum tax are removed in Version P.
1:26:09 PM
MR. ALPER reviewed slide 12, "Summary of Major Bill Provisions,
Other Provisions." Regarding interest rates, he thanked the
committee for keeping in Version P the provision for compound
interest. He said DOR strongly believes that the simple
interest resulting from a late amendment to Senate Bill 21
[passed in 2013, Twenty-Eighth Alaska State Legislature] was an
inadvertent change. The department thinks compound interest is
a more appropriate way to treat this. However, he continued,
Version P maintains the current statutory interest rate of 3
percent above the federal discount rate, currently that is 4
percent interest. The original bill proposed 7 percent over the
federal rate. Prior to the reforms of Senate Bill 21, the rate
was 11 percent above the federal rate. In regard to
confidentiality and transparency, he noted that the original
version of HB 247 proposed making public the names of those
companies receiving credits and how much each company received,
but that section is removed in Version P. Another provision in
the original bill was that transportation costs cannot reduce
gross value at the point of production below zero, and this
section is removed in Version P. However, Version P does
preserve the authority to use a tax credit certificate to pay
off another obligation to the state. Currently if a company
owes taxes, DOR can withhold credit certificates to help pay
those taxes, but DOR was looking to expand that to other
liabilities such as royalty obligations that might be unpaid.
While Version P substantially rewrites and restructures this
provision, the net effect is roughly the same - DOR will have
the authority to make sure that state agencies are kept whole.
1:27:42 PM
REPRESENTATIVE TARR observed that in Version P, Section 7 is
about the natural gas storage facility credit, Section 8 is
about liquefied natural gas storage facility credit, and Section
9 is the in-state oil refinery infrastructure expenditure
credit. Noting these were not included in the original version
of HB 247, she requested Mr. Alper to discuss these provisions
and how they apply to the outstanding liability of the state.
MR. ALPER answered that Sections 7, 8, and 9 of Version P are
purely conforming changes; similar references were made to these
credits in Sections 9, 10, and 11 of the governor's original
bill. These three credits are earned inside the corporate
income tax statutes, AS 43.20, but are unique in that among the
corporate income tax statutes they are cashable, they can be
repurchased using money in the tax credit fund, AS 43.55.028.
Restrictive language needed to be added in those three sections
to say the state does not want to pay those if a company owes
other obligations to the state. Although it has been rewritten
dramatically by the legislative drafters, the net effect is the
same. What is seen is new language that says "Subject to the
requirements in AS 43.55.028(e)." He offered his belief that
the committee will see an amendment eventually that changes that
to (j). Version P, Section 17, subsection .028(j) is new
language that talks about the mechanism by which the state can
ensure that it does not pay out tax credits in cash if a company
owes another obligation to the state.
1:29:45 PM
REPRESENTATIVE JOSEPHSON drew attention to the last statement on
slide 12 regarding the other provisions of Version P, "Preserves
authority to use Credit certificates to satisfy obligations to
the state before repurchase." He recalled Mr. Alper's inference
that this could be lived with. He said the basic distinction he
sees is that under the governor's original bill the state would
make no payment whatsoever until other obligations were
satisfied, but under Version P only the difference would be
paid, not the full amount. Although he could see industry
saying that [the original version] was too coercive, he said he
views [Version P] as a serious distinction.
MR. ALPER clarified that it was never the administration's
intent to hold back the whole credit. The discussion among
committee staff and himself was that the way the administration
wrote it might be interpretable that way, but that was not the
administration's intent. The desire is only to pay off any
obligation that is actually owed to the state agency and still
pay the company the remainder of the credit. Much of what is
seen in Version P clarifies what the administration's original
intent was. Version P adds another restriction in Section 17
which requires a company to authorize DOR to pay the obligation
on the company's behalf, with the alternative, he supposed,
being that DOR is effectively an escrow account by holding the
money on behalf of both the company and the state agency to
which the company owed money, but DOR would be unable to pay the
state agency without the company giving DOR affirmative
permission to do so.
1:31:37 PM
MR. ALPER continued his presentation, noting that slides 13-18
provide example scenarios of how the changes in Version P would
impact different types of producers and developers in different
parts of the state. He explained that these example scenarios
are updates to similar slides that he provided in his original
presentation in February. Regarding slide 13, "Bill CS Impact:
Example Scenarios, North Slope Major Producer," he stated that
for the North Slope major producer there is no change at any
price as to how such producers would be impacted by the changes
in Version P versus current statute.
MR. ALPER showed slide 14, "Bill CS Impact: Example Scenarios,
North Slope New or Smaller Producer," and explained that at
higher oil prices there would be no change for new or smaller
producers. However, for a new producer with an operating loss,
either because prices are very low or because the new producer
is still building out its field and operating at a loss even
though it is producing and selling oil, the provision where the
size of the NOL credit cannot be increased through the gross
value reduction will have a material impact on those new and
smaller producers.
REPRESENTATIVE JOSEPHSON inquired whether he is correct in
recalling that the governor's original bill projected that this
feature might save the state $12 or $13 million.
MR. ALPER replied that that may have been what he said a month
ago and sounds about right. However, based upon more recent
information that number is a bit larger, because with the prices
as low as they are more companies are going to be impacted.
1:33:17 PM
MR. ALPER resumed his presentation and brought attention to
slide 15, "Bill CS Impact: Example Scenarios, North Slope New
Project Developer." In this scenario, he said, the project
developer would not have any change, with the exception of the
very large project limited by the $200 million per company per
year cap. That $200 million a year reflects 35 percent of about
$570 million [a year] in capital spending for a single company
to reach the $200 million limit. So, short of that threshold
there is no change in Version P from current law, but above that
threshold an outlier project like the Armstrong project would
start bumping up against the $200 million cap.
MR. ALPER looked to slide 16, "Bill CS impact: Example
Scenarios, Cook Inlet Existing Producer," noting that Cook
Inlet's current statutory tax caps sunset in 2022 and Version P
maintains this. Under current law the state's credit support is
45-65 percent through the [qualified capital expenditure] and
[well lease expenditure] credits, and existing producers are not
eligible for the [net operating loss] credit. Version P would
reduce the state's support to 20-30 percent in 2017, and then to
20 percent beginning in 2018 and through the sunset of the
credits. The [qualified capital expenditure] credit is repealed
in 2022 and Version P has lots of language that conforms to some
statutory changes being made six years from now in anticipation
of another change, a new tax regime that the legislature will
develop sometime between now and then. Version P includes a new
section that requires a [legislative] working group, a process
with a report to the legislature sometime in the first session
of the Thirtieth Alaska State Legislature in the early part of
2017. The report will have recommendations on different tax
regimes for Cook Inlet as well as for the other non-North Slope
areas of the state. In 2022, without any change, Cook Inlet
will revert to a very high tax of 35 percent net profits tax
with only a 10 percent net operating loss credit and no per-
barrel or capital credits. This underlying tax system in Cook
Inlet is quite high, he advised, and therefore probably unstable
and that is why there is a need to find some way to replace it.
The key thing and major change in Cook Inlet is that Version P
continues support for capital spending at the 20 percent level
while the governor's original bill would have replaced that
number with zero.
1:35:53 PM
MR. ALPER addressed slide 17, "Bill CS Impact: Example
Scenarios, Cook Inlet New Field Developer," explaining that this
developer would be building something but would not currently
have sales. In 2017 that company would receive about 35 percent
credit support, whereas presently that company receives 50-55
percent. Currently there is the blend of the 20 and 40 percent
plus the 25 percent net operating loss. Version P reduces that
to a blend of 20 and 30 percent plus the 10 percent net
operating loss, for an aggregate of about 35 percent. That
would only be for one year. Beginning in 2018, the reduction of
the [well lease expenditure] credit to 20 percent, or
alternatively its repeal, is an immaterial dollar value
difference. The reduction of the [net operating loss] credit
will result in a 30 percent credit support, the state will be
paying for 30 percent of the cost of an ongoing development in
Cook Inlet between the 20 percent [qualified capital
expenditure] credit and the 10 percent [net operating loss]
credit. Very large projects would theoretically be limited by
the $200 million per company per year cap. However, with a 10
percent [net operating loss] credit it would be very, very hard
to reach these kind of numbers, it would take extremely large
investments by a single company to approach the $200 million per
company per year cap in Cook Inlet.
MR. ALPER drew attention to slide 18, "Bill CS Impact: Example
Scenarios, Interior / Frontier Area Explorer." The Frontier
Area super credits will sunset July 2016, he said, while the
exploration credits are extended through 2022. Extending the
exploration credits means that qualified expenditures will
continue to be paid at 50 percent, roughly 40 percent through
the exploration and 10 percent through the operating loss.
Addressing the first bullet, he explained that once out of the
exploration phase and into the development phase, a company's 20
percent capital credit and 10 percent [net operating loss]
credit would result in about a 30 percent credit support, lining
up with the Cook Inlet numbers beginning in 2018.
1:37:59 PM
MR. ALPER explained that slide 19, "To-date Cost of Sunsetting
Credits," provides an aggregate sense of the dollar values of
the credits that are intended to be sunset, that without any
legislative action are going to be disappearing over the next
several years. Regarding the various exploration credits since
2007 until sunset, the state has refunded/paid out about $270
million in credits on the North Slope, and companies have used
about $190 million to offset their tax liability. Off the North
Slope in Cook Inlet and the Interior, the state has refunded
about $160 million and nothing has been used against liability
because typically the Cook Inlet explorers are not taxpayers and
even if they were there is very limited tax liability against
which to offset their taxes, their credits. Regarding the small
producer credit, he explained that a single company can earn up
to $12 million per year of this credit, and there are multiple
companies that are able to claim it. Currently about $50
million a year is used on the North Slope and over the lifetime
of the credit through 2016, there will be smaller numbers in the
years as the credit trickles out. The state has given out $340
million in credits against liability on the North Slope and off
the North Slope the state has given out about $60 million. He
pointed out that small producer credits cannot be refunded, they
can only be used to offset a tax liability. In sum total for
these sunsetting credits, the state has either paid or foregone
revenue of slightly over $1 billion between their start and now.
1:39:40 PM
MR. ALPER reviewed slide 20, "Revenue Impact, Changes in CS,
Preliminary Analysis of Bill Changes ($millions), (based on Fall
2015 Forecast)." He said the chart on this slide tries to
summarize the fiscal impact of Version P. He advised that a
fiscal note is forthcoming that takes this information and
extends it into the future. Also forthcoming will be a more
detailed fiscal note that DOR is working on to break out many of
the subcomponents of the bill. He explained that this chart is
based on the fall 2015 forecast. The [2016] spring forecast was
released in preliminary form this morning, he continued, but DOR
has not yet internalized those numbers into this chart. Under
Version P the expected reduction in state spending is $400
million in FY 2017, $325 million in FY 2018, and $200 million in
FY 2019. In FY 2019 the drop-off is tied primarily to unknowns,
not knowing what kind of money companies are going to be
spending and therefore DOR cannot project credits. Under
Version P the expected increase in revenue is $50-$100 million
per year. "By eliminating the floor minimum tax changes," he
said, "those numbers are reduced to zero ..."
REPRESENTATIVE OLSON, regarding the forthcoming fiscal notes,
pointed out that the committee's next meeting is tonight. He
presumed Mr. Alper is not meaning tonight.
MR. ALPER responded that he redrafted both of the fiscal notes,
they are completed and in the review process, and need to go to
through the governor's office. The Department of Revenue issued
two fiscal notes, one tied to the bill itself and the increases
in revenue in the detailed description of the bill, and the
other tied to the fund cap, to the money that is going into the
tax credit fund and the reduction in annual money coming out of
it. He said the hope is that the committee will have the fiscal
notes today or tomorrow morning.
1:41:32 PM
MR. ALPER, at Representative Seaton's request, repeated his
review of slide 20. The governor's original bill envisioned
three sets of changes, he said. On the revenue side was the
minimum tax changes - the hardening [of the floor] and the
increase from 4 percent to 5 percent. The original bill foresaw
$100 million in the near-term years and $50 million in the outer
years. [In Version P] those numbers are reduced to zero because
the minimum tax is left intact. On the side of reductions in
spending there is the North Slope category and the non-North
Slope category. There are two distinctions in the credits. The
first is the credits that are eliminated or reduced; the law is
actually changed to say that a certain credit is not going to
exist anymore, or the number is being changed, or a loophole is
being closed and people are not going to get that money anymore.
The second is the credits that are deferred; the companies are
going to continue to earn the credits, generally speaking the
certificate credits, but because of the caps that would be
added, most importantly the $25 million cap, the companies are
not going to get all of that money and must instead roll it
forward into a future year. By putting in the $200 million cap,
the so-called deferred category is zeroed out, there are not
going to be any credits deferred in our forecast the way DOR has
it structured. Should something large happen, in other words
should something like the Pikka project be sanctioned and large
amounts of money start to be spent, DOR would modify the
forecast and then there would be a fiscal impact to the changes
in Version P based on the $200 million cap. Because of the
numbers that DOR has in its forecast, the changes in Version P
eliminate the savings from deferred credits, which then brings
things to the credits eliminated or reduced. For the North
Slope the main difference is the GVR/NOL thing, which is left
intact; in FY 2017 and FY 2018 the number is essentially the
same, that number is reduced at the number DOR forecast it.
Because of the delay in the effective date, FY 2017 ends up
being half of a year. For the Cook Inlet the changes are
related to the change in the credits: the well lease
expenditure credit is eliminated over an 18-month period rather
than immediately, the [qualified capital expenditure] credit is
maintained, and the [net operating loss] credit is reduced. The
effect of those changes is going to have a smaller fiscal impact
for three reasons: because the numbers are smaller; because the
numbers are delayed; and because support is maintained for
producers who would not otherwise be getting any credit support
under the structure of the governor's bill. The best
preliminary estimates, which will evolve over time, are that the
fiscal impact of Version P will be a reduction in the state's
credit outlay of roughly $50 million or $60 million per year.
1:45:15 PM
REPRESENTATIVE JOSEPHSON understood that Version P would largely
keep the state where it is currently, although this would be
less so in Cook Inlet in the out years. He asked what the other
oil and gas producing states that are suffering the exact same
oil and gas recession are doing with their credit packages.
MR. ALPER answered he is not aware of comparable credit packages
in the U.S. Alaska is the only state in the U.S. that taxes on
net profits and Alaska has a more sophisticated tax regime, a
more sophisticated incentive regime. He offered his belief that
North Dakota's gross tax does get reduced at low prices because
it is structured as a tax and a surtax. He added that the
Competitiveness Review Board has put out a good report that
highlights those things. He said he would not say things are
being kept intact; Version P definitely making changes, they are
simply not as aggressive as was originally proposed by the
administration.
REPRESENTATIVE SEATON asked whether he is correct in observing
on slide 20 that for Cook Inlet/Middle Earth in FY 2017 the
difference between the governor's original bill and Version P is
$130 million.
MR. ALPER replied, "To the best we could determine in the
limited time available, yes." Continuing, he said FY 2017 is a
bit deceptive because the governor's original bill had an
effective date of July 1 [2016], the beginning of FY 2017; but
Version P does not bring in any changes at all until January 1,
[2017], which is halfway through FY 2017. Also, [in Version P]
the [well lease expenditure] credit in FY 2017 is only reduced
from 40 percent to 30 percent, which is quite a material number
in Cook Inlet. Thus, a couple of things conspire to drag down
the number specifically in FY 2017 as a percentage of the total.
1:47:38 PM
MR. ALPER reviewed slides 21-22, "Implementation Cost,
Transition." Addressing slide 21, he noted that the governor's
original bill was written with an effective date of July 1,
2016. In Version P the predominant effective date is January 1,
2017, with the full repeal or the full reduction to 20 percent
of the [well lease expenditure] credit not until 2018, which is
about an 18-month delay. Version P retains the fiscal note
initially proposed in the governor's original bill, which adds a
fund capitalization of $926,575,000. That is not a random
number, he explained, it is the number that when added to the
number in the operating budget comes up with an even $1 billion,
which is the number the administration looked to for funding a
transition from the current system into the new system. That is
more than enough money to cover any anticipated expending in FY
2017, but [DOR] expects the legislature will need to appropriate
more money before getting to the end of FY 2018 and then beyond.
[The impact of Version P] on the transition is that the money is
still there, but will not go as far and so more money will be
needed to maintain the program because the program and the
state's liability would be larger in years to come.
REPRESENTATIVE SEATON understood the initial fund capitalization
was included because the credit amounts were being dramatically
reduced, but in Version P that is not going to happen or is not
going to happen for a deferred time. Noting that Version P
retains the fund capitalization, he inquired where that money
will come from.
MR. ALPER responded that his original understanding was that an
appropriation would be made from the constitutional budget
reserve (CBR) to endow this transition fund, and that that would
be part of the larger package of implementing the governor's
entire fiscal plan.
RANDALL HOFFBECK, Commissioner, Department of Revenue (DOR),
confirmed that the original intent in the governor's bill was an
appropriation from the CBR to endow the fund.
1:50:24 PM
REPRESENTATIVE SEATON asked where the authorization for a CBR
vote or an intent for a CBR vote is located in Version P.
MR. ALPER replied the fiscal note for fund capitalization was
written by DOR, but in some ways was on behalf of the Office of
Management & Budget (OMB). He understood that, like any fiscal
note, it would be attached to the operating budget and become
part of the final vote on the conference committee substitute of
the operating budget. It would be a separate line item and a
separate vote with the final passage of the operating budget.
REPRESENTATIVE SEATON said he has not before seen fiscal notes
just freely following that are not required or do not have
statutory authority, and the fiscal note is instituting the
statutory requirement proposed in the bill. He asked whether it
is in here or whether this is just a proposal to put $1 billion
someplace without any statutory requirement and could this
fiscal note then go by itself without any bill to attach it to.
MR. ALPER answered he has seen in the past the conditional
language in budgets and fiscal note sections, or that this
appropriation is contingent on the legislature passing a bill
that is equivalent to "HB so and so." He envisioned that that
is how it would end up being structured by whoever writes those
fiscal notes into the final version of the operating budget.
But, he continued, there is no explicit reference to the
spending in HB 247, there is no reference to the actual
appropriation in the bill language.
REPRESENTATIVE SEATON remarked that it seems very problematic to
start down the road of putting appropriations into a bill that
does not include any statutory authority in the bill to do that.
MR. ALPER responded that, broadly answering this question, the
intent of HB 247 as originally proposed was to reduce the
state's annual cash outlay to the neighborhood of $50-$100
million a year. That number in many ways lines up with the 15
percent in the language in statute that creates the [oil and
gas] tax credit fund, so it would be sort of self-sustaining,
and then this $1 billion was intended to be the transition, the
money that would get the state over the hump between the old
plan and the new. Version P is somewhat different, it is a
different paradigm and may impact how this transition fund is
treated or how it is kept in budgets moving forward. He said he
does not have a complete answer.
1:53:33 PM
MR. ALPER recommenced his presentation. Displaying slide 22,
"Implementation Cost," he explained that employees of the Tax
Division who work day to day with the tax credit program, with
the production taxes, will to have to change their work
somewhat. The [Tax Revenue Management System (TRMS)] and the
[Revenue Online (ROL)] will have to be reprogrammed because
there are different calculations, different formulas, online tax
paying forms, and so forth. The department has not yet received
a solid estimate [from the software developer] and an estimate
may not come until it is better seen what the bill is going to
look like. However, DOR has put a placeholder capital cost of
$1.5 million into the fiscal note to pay the contractor to
reprogram the system; no cost is anticipated for the department
itself to administer the program because it will be done with
existing resources and existing staff. There will also be a
fairly robust regulatory process to implement the changes in
this or any version of the bill. The Department of Revenue has
a couple of other large oil and gas regulatory projects on the
back burner waiting for the completion of this legislative
session and DOR anticipates doing all of them at the same
starting this summer.
1:54:44 PM
The committee took a brief at-ease.
1:55:55 PM
REPRESENTATIVE JOSEPHSON returned to slide 7 and noted that the
last bullet states, "By preserving 'capital' and reducing 'loss'
credits, increases payments to producers (who pay zero taxes)."
He surmised this means it is status quo and that the producers
are not getting more under Version P, but are getting what they
got at least until the middle of 2017.
MR. ALPER answered that the use of the word "increases" in this
bullet is meaning an increase from the governor's original bill.
It is actually a decrease from what is currently being paid
because in some cases the producers in question are getting the
40 percent [well lease expenditure] credit in combination with
the 20 percent [qualified capital expenditure] credit. [Under
Version P] producers would, by the beginning of 2018, only be
getting the 20 percent [qualified capital expenditure] credit.
1:56:52 PM
REPRESENTATIVE SEATON noted that the governor's original
proposal would implement a change date of the state's fiscal
year, while Version P would implement a change date in January,
which is a tax year for the companies. Regarding well lease
expenditures, he inquired whether there is any reason why that
cannot be implemented mid-year of a cycle, since those are
different than the tax rate or the tax liability because the
credits are based on when the money is expended and so would be
independent of such things as the company's tax rate or
operating loss.
MR. ALPER confirmed that Representative Seaton is correct. For
the credits that are tied to spending - the capital, well lease
expenditure, and exploration credits - as long as the receipt,
the activity, the spending takes place before the cutoff date,
DOR can very easily parse out that set of expenditures and write
a credit; the department does not need to be tied to a calendar
year or a tax year. With the exploration credits being sunset
on July 1, [2016], companies will be coming to DOR with a
project and DOR is only going to be paying them on the spending
that took place prior to July 1. The credit that gets awkward
if it is changed in the middle of the year is the operating loss
because that is tied to an overall year's profit and loss, and
so this would become a very difficult accounting exercise.
1:59:02 PM
CO-CHAIR NAGEAK advised that the co-chairs are considering
hearing some of the members' amendments to HB 247 tonight,
depending upon how many amendments are received by the deadline
of 5:00 p.m. tonight. He asked whether members have any
comments on whether to start amendment consideration tonight
versus waiting until tomorrow.
REPRESENTATIVE TARR stated it would be difficult to respond to
the amendments because members have not yet seen them and
therefore it would be nice to have the evening to review them.
CO-CHAIR NAGEAK agreed to wait until tomorrow to start the
consideration of amendments.
CO-CHAIR NAGEAK, responding to Representative Seaton, said the
co-chairs would like to receive the proposed amendments in both
electronic and hard copy formats.
[HB 247 was held over.]