Legislature(2021 - 2022)SENATE FINANCE 532
04/20/2022 01:00 PM Senate FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB81 | |
| HB102 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | HB 81 | TELECONFERENCED | |
| *+ | HB 102 | TELECONFERENCED | |
| + | TELECONFERENCED |
SENATE FINANCE COMMITTEE
April 20, 2022
1:07 p.m.
1:07:51 PM
CALL TO ORDER
Co-Chair Bishop called the Senate Finance Committee meeting
to order at 1:07 p.m.
MEMBERS PRESENT
Senator Click Bishop, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Lyman Hoffman
Senator Donny Olson
Senator Natasha von Imhof
Senator Bill Wielechowski
MEMBERS ABSENT
Senator David Wilson
ALSO PRESENT
Scott Jordan, Director, Division of Risk Management,
Department of Administration; Paloma Harbour, Fiscal
Management Practices Analyst, Office of Management and
Budget, Office of the Governor.
PRESENT VIA TELECONFERENCE
Ryan Fitzpatrick, Commercial Analyst, Division of Oil &
Gas, Alaska Department of Natural Resources; Emily
Feenstra, Assistant Attorney General, Department of Law.
SUMMARY
CSHB 81(RES)am
OIL/GAS LEASE: DNR MODIFY NET PROFIT SHARE
CSHB 81(RES)am was HEARD and HELD in committee
for further consideration.
HB 102 STATE INSUR. CATASTROPHE RESERVE ACCT.
HB 102 was HEARD and HELD in committee for
further consideration.
CS FOR HOUSE BILL NO. 81(RES) am
"An Act relating to the modification of a royalty or
net profit share in an oil and gas or gas only lease."
1:08:38 PM
RYAN FITZPATRICK, COMMERCIAL ANALYST, DIVISION OF OIL &
GAS, ALASKA DEPARTMENT OF NATURAL RESOURCES (via
teleconference), discussed a presentation, "HB 81 NET
PROFIT SHARE and ROYALTY MODIFICATIONS ON OIL & GAS LEASES"
(copy on file). He turned to slide 2, "Outline":
I. Overview of Net Profit Share Leases
II. Overview of the modification process
III. Why Allow for NPSL Modifications?
IV. Overview of House Bill 81 as amended in the House
V. Appendix
Mr. Fitzpatrick spoke to slide 3, "ROYALTY and NET PROFIT
SHARE," which showed a table that compared different types
of petroleum revenues including royalty, production tax,
net profit share, and profit to the lessee. He explained
that that purpose of the slide was to try and show the
differences between the different revenues. He continued
that royalty and profit share were both derived from the
oil and gas lease contract and were significantly different
from production tax. Royalty and net profit share contract
provisions could only be changed through the consent of
both parties, whereas production tax was on a separate
fiscal system and was changeable at will by the state
acting as a sovereign. He noted that currently royalties
could be modified by the Department of Natural Resources
under an existing statutory scheme in AS 38.05.180 (j). He
reminded that production tax was amendable at-will by the
legislature.
Mr. Fitzpatrick noted that there was currently no statutory
scheme to allow for net profit share lease modifications.
There had been one instance of a modification that occurred
in the mid to late 1990s. He recounted that the lessee had
approached DNR about modification, it was determined the
department did not have the authority, and the modification
had been brought to the legislature in the form of a bill
that was later passed by the legislature. One of the
reasons the bill proposal was advanced was to streamline
the process so that DNR might have the authority to modify
the leases (within the confines of the statute) without
having to come to the legislature each time.
1:13:02 PM
Co-Chair Bishop asked how many modifications of net profit
share had occurred in the previous ten years.
Mr. Fitzpatrick cited that there had been no such
modifications in the previous ten years. He noted that the
case he mentioned was the only instance of a modification
of net profit share leases, however there had been three
decisions that had modified royalties.
Mr. Fitzpatrick highlighted an important difference between
royalties and net profit shares and noted that royalties
began payments at the beginning of commercial production as
a share of the total production from the lease. The net
profit share payment was calculated in a significantly
different manner and took into account the costs of
production. In order for a net profit share payment to be
made, the lease had to generate a profit and the lessee had
to recover initial capital costs. The net profit share
would be a percentage of the net profits generated by the
lease after the recovery of costs and could begin many
years after the lease went into production. He reiterated
that the net profit shares took into account the costs of
production and royalties did not.
1:15:50 PM
Mr. Fitzpatrick referenced slide 4, "NET PROFIT SHARING: A
HYPOTHETICAL EXAMPLE," which showed a hypothetical example
of a breakdown between the costs and revenues generated by
the sale of a barrel of oil. He noted that the example was
not reflective of any particular oil price and used made up
numbers. He drew attention to capital and operating
expenditures, transportation costs, and revenues from the
barrel of oil. There were some taxes not shown on the
diagram. The royalty and production tax that went to the
state was shown, and finally the profit that went to the
lessee.
Mr. Fitzpatrick pointed out that the barrel shown on the
right of the slide showed the same costs and royalty as the
first share of revenue to the state. He pointed out the
production tax and net profit share, which turned out to be
a small reduction to the production tax because the payment
of the net profit share under the lease was a deduction
against the profits on which the tax was paid. Overall, the
state took more revenue from the example on the right
because it received both the net profit share and the
production tax. The final item was the profit to the
lessee, which was less because of the net profit share
percentage.
Co-Chair Stedman referenced the states gross tax before
conversion to net tax, after which there was net profit
share leases embedded into production tax section of profit
oil.
Mr. Fitzpatrick agreed that Co-Chair Stedmans description
was correct. He noted that all of the net profit share
leases currently were issued prior to the conversion of the
production tax from gross tax to a net tax back in 2006.
When the net profit share leases were issued, the
production tax under which the net profit share leases were
operating would not have included any deduction for net
profit share payments as part of the tax calculation. When
the production tax was converted from a gross to a net tax
in 2006, net profit share payments were called out as
another field cost of the lease to be deducted from the
production tax.
1:20:16 PM
Mr. Fitzpatrick turned to slide 5, "26 ACTIVE NET PROFIT
SHARE LEASES," which showed a table with a list of all the
net profit leases outstanding in the state. He reminded
that all the leases were originally issued in the late
1970s and early 1980s. He noted that some leases were
listed as being issued in 2019 or 2007, and the leases were
subdivided portions of a lease that was previously issued.
Mr. Fitzpatrick pointed out the column entitled 'Net profit
share rate,' and made note of the significant variation
from 30 percent to 40 percent for most leases, and up to
almost 80 percent for other leases. He explained that for
the most part the net profit share rate was a fixed
component of lease sales, but there were times that the net
profit share rate was the bid variable. The royalty rates
also reflected that the leases still generated royalties,
with most at 12.5 percent but some with royalty set at 20
percent.
Mr. Fitzpatrick noted that the next several columns on the
table had information about the unit and the source of
production for the leases. An additional column reflected
whether the net profit share leases had recovered all of
the capital costs and were beginning to generate net profit
share payments to the state. He noted that some of the net
profit share leases listed had reached payout, and some had
not. In some cases, the leases had no production allocated
to the lease. In other instances, there could be production
generated from the lease, but it had not recovered the
capital costs allocated to the lease yet. There were
additional columns that provided information on the amount
of the cumulative net profit share payments and royalties
that had been generated from each unit.
He pointed out the last column, which showed the date the
lease generated its first royalty payment. He pointed out
the first payout dates. He observed that there were several
examples on the slide that illustrated that the payout date
was generally much later in time than the start of the
royalty payments.
1:23:56 PM
Co-Chair Stedman understood that Pt. Thomson was unique. He
asked about the Kuparuk lease, which had not reached the
payout stage. He asked if the leases were sitting idle for
as long as 40 years.
Mr. Fitzpatrick stated that the Kuparuk leases were
generating some small amount of production. He pointed out
that the Cumulative Royalty column reflected that the net
profit share leases in the Kuparuk unit had generated $40
million in royalties to the state, which was lower than
some other net profit share leases. Much more of the
production from Kuparuk weas being generated from leases
that were not net profit share leases. He noted that there
was a map of net profit share leases in the appendix of the
presentation. The initial capital investments of the
Kuparuk region, primarily exploration expenses, were
allocated across the leases and became a capital cost of
the leases. Because of the small production, the initial
capital cost had not been recovered.
Co-Chair Stedman understood that the Kuparuk leases had
been taken out in 1983, and Kuparuk had been active for
decades. He understood that capital expenditures were
allocated against the leases, and not just capital expenses
from the 1980s.
Mr. Fitzpatrick affirmed that ongoing capital expenses and
ongoing capital costs were allocated to each of the leases
based on the share of production from the lease. A very
small amount of the capital and operating costs would be
allocated to the leases because only a small fraction of
the production was allocated to the leases. The initial
capital expenditures around exploration were having the
most effect and remained as part of the lease. He continued
that one of the features of net profit share leases was
that capital expenses allocated to the lease generated a
hypothetical amount of interest in the development account.
For accounting purposes, there was a small amount interest
allocated to the capital account based on the prime rate.
The initial capital costs had been generating small but
continual amounts of interest over a number of years, and
very little production allocated to the leases to continue
to pay down the initial capital cost.
1:29:13 PM
Co-Chair Stedman wanted to put the matter in context. He
observed that the last time the leases were used was 1984.
He asked why the leases ceased to be used, and why the
leases were being considered so long after being inactive.
Mr. Fitzpatrick agreed that it had been a number of years
since the leases were issued. He mentioned the North Star
leases, which were not currently net profit share leases
and were not included on the table. Some of the leases had
been issued with net profit share in excess of 90 percent,
which began causing problems with getting some of the units
into development. He explained that if a lease was deemed
to be only moderately prospective, the 90 percent net
profit share rate could be a barrier to development. The
high rate had been the reason for the modification of the
North Star net profit share leases, after DNR had decided
the lease offering was no longer the best alternative for
the state
Senator Wielechowski asked to go to Appendix 15, "Map of
Net Profit Share Leases." He referenced the map and thought
it looked as if there were no net profit share leases in
Prudhoe Bay nor Badami.
Mr. Fitzpatrick answered "yes."
Senator Wielechowski asked if the leases, or any other
existing leases, could be converted into net profit share
leases.
Mr. Fitzpatrick informed that the current statutory scheme
for royalty modification allowed DNR, within certain
limits, to modify the payment mechanisms for individual
leases on a number of different bases. It would be possible
to functionally add the equivalent to a net profit share
component through the modification process, although there
would still have to be a base royalty rate. The process
would have to occur if a lessee applied for a royalty
modification and then ultimately accepted the terms offered
by DNR.
1:33:29 PM
Senator Wielechowski asked if the bill affected the
process. He asked if the owners of Prudhoe Bay could
request a modification to add a net profit share lease and
pay a net profit share of 30 percent.
Mr. Fitzpatrick stated that the bill would not change the
part of the modification scheme that he described.
Senator Wielechowski went back to slide 5. He asked if any
other fields other than those listed on the slide would be
eligible for net profit share leases if the bill were
enacted.
Mr. Fitzpatrick stated that the proposed changes to net
profit share rates would not affect other leases, because
the other leases did not have a net profit share component.
The bill would not affect the current statutory authority
for parties to agree on adding a functional equivalent of
net profit sharing to other leases. The net profit share
modification component of the bill would not impact leases
other than those listed.
Senator Wielechowski asked about Colville River, which had
royalty rate of 12 percent, and a net profit share rate of
30 percent. He asked Mr. Fitzpatrick to walk through a
simple balance sheet of the components. He mentioned a
production tax.
Mr. Fitzpatrick affirmed that Senator Wielechowski was
correct; if barrel of oil was sold, the first thing to
happen would be a deduction for transportation expenses.
Whatever was left of the sale of a barrel after the
deduction would first have the royalty share paid out. What
was left was split between production tax, net profit
shares, and covering the field costs of the lessee and
remaining profit to the lessee.
1:37:09 PM
Mr. Fitzpatrick continued that the next functional step
after the royalty would be the net profit share payment,
after deducting capital costs and operating expenses for
the year. He noted that the Colville River was already in
payout, and there would not be any prior year capital costs
factored in, just whatever costs incurred in the particular
year.
Mr. Fitzpatrick described the lease language that allowed
for a deduction for net profit shares in calculating net
profit shares for production tax. There was a regulation
that calculated the production tax within the net profit
share calculation. Anything that was left was profit to the
lessee.
Senator Wielechowski wondered if Mr. Fitzpatrick could
provide his answer in writing. He asked where deductible
oil tax credit factored into the process. He asked whether
there was still a gross 4 percent tax floor.
Mr. Fitzpatrick did not have the information to address
dollar values. He offered to provide the information at a
later time. He addressed tax credits and how it factored
into the calculation. He explained that in doing the net
profit share payment calculation, the regulations simulated
the production tax payments that might otherwise be paid.
Any tax credits that were in the tax statute were treated
as if they were a deduction from a tax when calculating the
net profit share payment. If the production tax was lowered
because of the payments, the tax deduction in the net
profit share calculation went down, and the lessee would
pay a higher net profit share to the state because the tax
was lower.
1:41:05 PM
Senator Wielechowski reiterated that it would be helpful to
have Mr. Fitzpatricks answer in writing. He asked if it
would be fair to say if there was a net profit share rate
of 30 percent if the company was paying more or less
production taxes than under the current statute.
Mr. Fitzpatrick stated that in the instance of a net profit
share, the company would generate the net profit share
payment as a result of the calculation, because it was then
deducted against the production tax, and the lessee paid a
smaller production tax. The overall effect of the net
profit share rate combined with the production tax was
always larger than the production tax itself.
Senator Wielechowski hypothesized that the state decided to
cut the net profit share down to one percent. He assumed
the company would still be paying as much as under the
current production tax structure if there were no net
profit share at all.
Mr. Fitzpatrick answered in the affirmative and stated that
even if the net profit share rate were reduced to the
minimum that was in the bill or eliminated entirely,
whatever the production tax was reduced to, the lessee was
paying at least as much in production tax as it would have
paid if there had been no net profit share in the lease
originally. He noted that there was a provision in the bill
that limited the modification to a ten percent net profit
share. He summarized that in any instance where there was a
net profit share component that remained, the combination
of the net profit share and production tax would always be
more than the production tax on its own.
Senator von Imhof thought it was important to consider the
big picture rather than the minutiae of the bill. She noted
that HB 81 did not propose to change the modification
process but added oversight. She asked Mr. Fitzpatrick to
confirm her understanding.
Mr. Fitzpatrick agreed and explained that her
interpretation was correct. He continued that the change
proposed in the bill was to add net profit share rates to
the existing modification process.
Senator von Imhof thought she read something about trying
to eke more life out of fields that were not profitable or
producing.
Mr. Fitzpatrick answered affirmatively. He stated that
might be useful to bring a new field intro production or it
could extend the life of an existing field by eking out
more production.
Senator von Imhof thought the choice at hand was
"something" versus "nothing.
Mr. Fitzpatrick agreed that the only proposed to add the
net profit share to the existing scheme.
1:45:45 PM
Senator Wielechowski asked if the bill would allow or make
it easier for the state to lower the net profit share rate
of fields.
Mr. Fitzpatrick stated that the bill would make it easier
to modify the net profit share rate in that the current
process would be to bring the matter to the legislature.
The bill proposed a process with a heightened burden of
proof and significant analysis by DNR. He noted that DNR
had the authority to hire outside consultants at the
applicant's expense to assist in analysis. The bill also
added an oversight component for the state Oil and Gas
Royalty Board for both royalty modification and net profit
share modification decisions.
Senator Wielechowski asked if a company could request a net
profit share reduction, which could result in a loss of
revenue to the state.
Mr. Fitzpatrick answered that the modification scheme that
was currently in place required DNR to only authorize
modifications only if the field did not come into
production or the field was already shut in.
Senator Wielechowski mentioned a previous tax structure
known as the Economic Limit Factor (ELF) and asked if Mr.
Fitzpatrick had been in the state at the time.
Mr. Fitzpatrick stated he was in the state but was not
involved in oil and gas tax at the time.
Senator Wielechowski asked if Mr. Fitzpatrick could discuss
the history of how ELF had worked at Kuparuk, when it
lowered the tax rate from 12.5 percent gross to zero from
1996 to 2003, with an objective of encouraging increased
production. He recalled that production dropped
precipitously as the tax rate was going down to zero.
Mr. Fitzpatrick understood that the production tax rate at
Kuparuk did decline during the ELF years, which was
coincident with the decline of production at the field.
Co-Chair Bishop wanted to note that Senator Wielechowski
had used Point Thomson as an analogy and pointed out that
even with 100 percent tax rate there would be no profit
without production.
1:49:48 PM
Mr. Fitzpatrick considered slide 6, "HISTORY OF ROYALTY
MODIFICATION APPLICATIONS," which showed a table, including
the Northstar modification he had alluded to earlier. He
noted that there had been several modification applications
over the years going back to 1995. He cited that DNR had
not had the authority to modify the net profit share for
Northstar and it had been brought to the legislature. The
legislation that was passed had removed the net profit
share of the leases and increased the royalty from a base
of 20 percent to a sliding scale between 20 percent and 27
percent based on the price of oil and other factors. The
decision was presented by the lessee as necessary to bring
the field into production.
Mr. Fitzpatrick pointed out that there had been several
applications made for royalty modifications to the
department that had been denied or withdrawn. Only three
out of all the modification applications had been approved
and were shown in blue. Of the three modifications, only
two were still active. The third, for the Nuna field, had a
limitation that required an investment decision by a
certain period of time. The lessee ultimately didnt make
the investment decision and the modification lapsed of its
own accord.
Co-Chair Bishop asked if the Nuna modification had an 80
percent Alaska-hire rate as part of the royalty
modification.
Mr. Fitzpatrick believed the Alaska hire provision had been
part of the agreement. He believed the provision that
ultimately caused the modification to rescind was that
Caelus (the lessee) had been required to make an investment
decision in a certain period of time, which it failed to
do.
Co-Chair Stedman commented on the complexity of the state's
tax structure. He asked why the state did not try and
simplify its tax structure to make it more transparent.
Mr. Fitzpatrick was certain there were many discussions
about how to best modify all of the components. He thought
the idea behind the bill proposal was that it would be
easiest to slot the net profit share modification proposal
into the existing royalty modification scheme.
1:54:12 PM
Co-Chair Stedman asked which leases listed on slide 5 had a
hindrance to production. He referenced Co-Chair Bishop's
comment regarding the lack of production.
Mr. Fitzpatrick iterated that one of the modification
criteria for royalty was to extend the life of a field that
might otherwise shut in because it reached the economic end
of field life. He noted that some of the fields listed
might have relatively strong production values and
commented on the oil market. He continued that as units
continued to age and production dropped further, some of
the units could reach the point where the reduced
production no longer covered operating expenses. The
proposal was primarily targeted at those fields as they
began to reach the end of field life because of declining
production.
Co-Chair Bishop referenced slide 6, and the history of
royalty modification applications. He asked if the
modifications all required legislative action.
Mr. Fitzpatrick explained that the current modification for
royalties did not require legislative approval but did
require the department to offer a presentation to the
Legislative Budget and Audit Committee during the public
comment period of the decision. There was an opportunity
for the legislature to receive some of the confidential
information that went into the decision, and to offer
comments during the comment period. He stated that under
the bill, the process would be extended with an additional
oversight requirement of a vote by the royalty board.
1:57:52 PM
Mr. Fitzpatrick displayed slide 7, "WHAT TYPE OF
MODIFICATION IS WARRANTED?":
A. Royalty Modification is capped at certain minimum
royalty rates.
?Five percent for .180(j)(1)(A) or three percent
for .180(j)(1)(B)(C).
B. The proposed NPSL modification also establishes a
minimum net profit share of ten percent.
C. The modification must be based on a sliding scale
mechanism.
?It could vary with the price of oil, volume of
production, per-barrel costs, etc.
?HB 81 allows use of fixed royalty rates for a
modification, but any fixed rate must be coupled
with other modification mechanisms that create an
integrated sliding scale modification.
D. Modifications of royalty or net profit share can be
either lower or higher than the original percentages.
(AS 38.180(j)(3))
?In certain circumstances, this would allow DNR
to recapture foregone royalties or net profit
revenue if oil prices rise, or even to
participate in "upside" price movements if DNR
provides "downside" relief.
Senator Wielechowski asked if DNR had any opinions from the
attorney general, Legislative Legal Services, or any
attorneys that the bill might be unconstitutional under the
power of taxation.
2:01:56 PM
EMILY FEENSTRA, ASSISTANT ATTORNEY GENERAL, DEPARTMENT OF
LAW (via teleconference), relayed that she had reviewed the
bill and had not found any constitutional issues.
Senator Wielechowski asked if net profit share was not
considered to be a tax.
Ms. Feenstra stated that net profit share was considered to
be separate but related to a tax.
Senator Wielechowski recalled a similar issue that a
legislative attorney had found to be unconstitutional. He
asked if the net profit sharing was considered to be a tax,
Ms. Feenstra would find that giving away the ability to
review the process would make it unconstitutional.
Ms. Feenstra agreed to do more research on the topic and
noted that she would be happy to see the information
Senator Wielechowski was referencing about the previous
legal opinion.
Senator Wielechowski asked if Ms. Feenstra would agree that
if the net profit share was considered to be a tax, the
legislature could not give up its right to review it.
Ms. Feenstra believed that Senator Wielechowski was
correct.
Co-Chair Stedman commented that twenty years previously the
Legislative Budget and Audit Committee had reviewed a lease
modification. He could not recall the details. He thought
the committee should review the information.
2:05:04 PM
Mr. Fitzpatrick highlighted slide 8, "DECISION-MAKING
PROCESS":
A. HB81 does not propose to change the modification
process, but adds oversight for the final decision to
grant a modification.
B. A producer applying for a royalty modification must
provide a clear and convincing evidence showing that
they meet the statutory requirements.
?A higher standard of proof than required for
most other DNR applications.
?Applicants required to provide abundant evidence
to justify any request for relief.
C. DNR may require (for .180(j)(1)(A)) or request (for
.180(j)(1)(B)(C)) that producers pay up to $150,000
per application for consulting work to support DNR's
evaluation of the application.
D. Publication of Best Interest Finding and offer
presentation to Legislature (AS 38.05.180(j)(9)-(10)).
E. HB 81 adds an oversight role for the Alaska Royalty
Oil & Gas Development Advisory Board. The Board is
required to approve any modification proposed by the
Commissioner.
F. If granted, modifications are not transferrable
without the authorization of the Commissioner. (AS
38.05.180(j)(5)
2:08:24 PM
Mr. Fitzpatrick looked at slide 9, "WHY ALLOW FOR NPSL
MODIFICATIONS?"
1. Increase Production from Otherwise Stranded
Resources
?Under certain circumstances, even with royalty
modification, it is possible for continuing or
for incremental production from pools which
contain NPSLs to be stranded.
?Modification of royalty and/or net profit share
for pools which would otherwise be stranded could
extend the life of such field and other existing
fields.
2. Flexibility for Royalty Modifications
?NPSL Modifications would give DNR flexibility to
elect targeted reductions and could be a useful
tool in environments of high oil price
volatility.
?NPSL Modifications would enable DNR to increase
net profit shares in scenarios where DNR can
structure potential payback of foregone revenues
in the event of higher prices or production
levels.
3. Streamline Process for NPSL Modifications
?Current process to modify NPSLs is for DNR to
negotiate a modification package and submit
proposal for legislative action.
?Providing for NPSL Modification in statute would
streamline the NPSL modification process, while
allowing for the Legislature to set conditions
and limits on NPSL Modifications.
2:11:35 PM
Mr. Fitzpatrick addressed slide 10, "WHAT HB 81
ACCOMPLISHES":
1. Expand the royalty modification process to include
the modification of net profit shares:
?Commissioner would have the authority to modify
net profit share rates in the same manner as
royalty rates under AS 38.05.180(j).
o Objective is to encourage production of
otherwise stranded resources.
2. Creates an additional qualifying scenario for
modification of NPSLs
?For producing pools, where incremental
production requires incremental capital
expenditures, which, in the absence of
modification, would be uneconomic.
3. Adds Oversight Role for Royalty Board for Royalty
and NPSL Modifications
?The existing Alaska Royalty Oil & Gas
Development Advisory Board would gain an
oversight role in the modification process. The
Board would be required to review proposed
modifications for royalty and/or NPSL, and no
modification could be granted without Board
approval.
4. Resolves an existing potential statutory ambiguity
?Clarifies that test production during
exploration does not disqualify a field or pool
from royalty or NPSL modification based on new
production. This merely codifies existing
interpretation and is not a change in policy.
2:14:26 PM
Co-Chair Bishop asked if item four on the slide would be
codified in statute.
Mr. Fitzpatrick stated that the item would be part of the
bill.
Senator Olson went back to slide 9, and the mention of
increasing production of otherwise stranded resources on
slide 10. He asked if there had been an estimate by the
department to see what additional revenues the state might
realize if the bill were to pass.
Mr. Fitzpatrick stated that the department had prepared an
indeterminate fiscal note, and cited that it was very
difficult to predict which producers or scenarios might
apply for a modification.
Senator Olson understood that the department might not have
exact numbers. He asked whether the change might be
significant or minimal.
Mt. Fitzpatrick did not characterize the potential
additional revenue from the bill as a large revenue
stream. He estimated that the fields in question would be
reaching the end of life with low production, and the net
profit share payment was likely to be low. The goal of the
proposal was to hypothetically eke out some field life,
both for the net profit share component, and potentially
for the royalty component and tax component. He identified
that if the state could modify the net profit share rate
and get some additional production out of a field, all
three revenue streams would be available for an additional
year.
Senator Olson commented that if the bill did go through
there would be minimal effect, and he saw no significant
reason to move the bill forward.
2:17:08 PM
Senator Wielechowski asked if the department had a guidance
document that the commissioner used to determine whether to
or how much to modify royalty agreements.
Mr. Fitzpatrick relayed that the guidance primarily resided
in statute. The statute dictated that the modification be
granted on a basis that it was only what was required to
change the investment decision. In a situation where the
modification of the royalty down to ten percent would bring
a field to production or extend the life of a field, the
statute did not allow the department to modify the royalty
down to five percent. Statute allowed for the smallest
modification that was possible while still flipping the
investment decision.
Senator Wielechowski asked if any other states had a
similar scenario in which it was allowed to reduce royalty
rates or tax rates on public lands.
Mr. Fitzpatrick understood that for tax rates, the state
would act as sovereign and had the right to change tax
rates at any point in time. For the royalty rates, he
understood that the federal government had a royalty
modification process that federal lessees could apply to,
and it operated somewhat like the states modification
mechanism, although there were also significant differences
in how the modifications were applied. He was not aware of
other states that had a net profit share component of oil
and gas leases.
2:19:26 PM
Senator Wielechowski knew there was a statute regarding
royalty rate reduction but asked if there was any kind of
internal document stipulating the net present value or
royalty rate of return. He asked if there was anything the
commissioner had to use as guidance in making the
determinations.
Mr. Fitzpatrick was not aware of any internal documents
that set the requirements. He considered that past royalty
modification decisions had involved a survey of the market
to identify reasonable rates of return. If the modification
of royalty to 10 percent was enough to the net present
value just slightly over zero, the amount was all that
would be authorized.
Mr. Fitzpatrick advanced to slide 11, "HB 81 VS. CSHB
81(RES)AM," which showed a table with a comparison of the
original bill proposed in the House versus the Committee
Substitute (CS) that the committee was considering. He
pointed out that the original bill and the CS both allowed
for modification of net profit shares, and both included
correction for the statutory ambiguity around test
production. The bill had been amended to restrict the new
modification scenario for additional capital expenditures
to net profit share rates only. The 10 percent floor for
net profit shares percentages in a modification scenario
was included in the original bill and the same language was
in the CS.
Mr. Fitzpatrick continued that there were some additional
requirements put in place in the House to require the
lessee to incur the capital expenditures proposed under the
modification. The DNR commissioner would make the
determination that the capital expenditures were necessary
to maximize economic production. The oversight role for the
Royalty Oil and Gas Development Board was also a component
of the original version of the bill. There were some other
conforming changes to the language proposed by Legislative
Legal Services and accepted in the House.
2:23:37 PM
Co-Chair Bishop OPENED public testimony.
2:23:51 PM
Co-Chair Bishop CLOSED public testimony.
2:24:01 PM
AT EASE
2:24:57 PM
RECONVENED
Co-Chair Bishop set HB 81 aside.
CSHB 81(RES)am was HEARD and HELD in committee for further
consideration.
HOUSE BILL NO. 102
"An Act relating to the state insurance catastrophe
reserve account; and providing for an effective date."
2:25:04 PM
Co-Chair Bishop noted that the committee had heard the
companion bill for HB 102 the previous session and had
heard public testimony.
2:25:54 PM
SCOTT JORDAN, DIRECTOR, DIVISION OF RISK MANAGEMENT,
DEPARTMENT OF ADMINISTRATION, discussed the presentation
"House Bill 102 - Alaska Department of Administration -
Division of Risk Management" (copy on file). He showed
slide 2, "Purpose":
The assets of the Catastrophe Reserve Account
(CATFund) may be used to obtain insurance, to
establish reserves for the self-insurance program, and
to satisfy claims or judgments arising under the
program.
? The purpose is to allow the State to self-insure for
property coverage.
? HB102 will save the state $3M in the first year and
$26M over the next 5 years (est.)
? Due to global property insurance markets hardening
we had a 30% increase in insurance costs from FY20
($5.1M) to FY21 ($6.6M) and FY22 was ($7.1M).
? HB102 is a request to change the Catastrophe Reserve
Account (CATFund) limit from $5,000,000 to $50,000,000
unencumbered.
? Currently the limit on catastrophe coverage that can
be purchased is $50,000,000 for an annual premium. We
can save that annual premium by self-insuring
2:28:20 PM
Mr. Jordan showed slide 3, "What other states are doing?":
• Just pay the higher premiums. Some states are
forced to maintain excess coverage due to
benefits paid by FEMA which requires "Obtain and
Maintain" agreements when FEMA pays for a
catastrophic loss.
• Set up Captive Plans-similar to self-insured
plan.
• Increase Self-Insured Retentions (SIR), in some
states $40M to $50M retention.
• Some states are coming off multi-year premium
price guarantees.
Mr. Jordan spoke to slide 4, "Comparison of premiums paid,
property losses paid, recovery (excess insurance) FY95-
2020":
FY95-FY2020 property premiums paid $59,017,386
FY95-FY2020 property losses paid by DRM $26,145,207
FY95-FY2020 recovery from excess insurance $17,942,815
FY2014 Kodiak Launch Facility loss $15,931,131*
FY2007 DOT-Girdwood Fire $ 835,136
FY2000 Court Plaza Bldg $ 1,176,54
*this type of claim is now excluded from coverage
Mr. Jordan noted that there had been about a $1.9 million
return on an $85 million investment in the losses.
2:32:18 PM
Co-Chair Stedman asked if the premiums were calculated
nation-wide, such as in the flood insurance program. He
thought it would be difficult to get through the regulatory
environment.
Mr. Jordan explained that the state's insurance went both
through the domestic market and the London market, which
came up with the rates. There were models through which the
markets could come up with catastrophic loss rates, and
freely admitted the modelling was not correct. He cited
that the state paid about 7.4 cents per $100.
Senator Wielechowski thought Mr. Jordan indicated that the
state was responsible for $50 million in damages and then
would purchase insurance for any amount beyond.
Mr. Jordan stated that the division's intention was to
fully self-insure the program. With the $50 million
increase proposed in the bill, it would allow the state to
have the same funding it currently purchased for
catastrophic losses (earthquake and flood insurance).
Senator Wielechowski mentioned catastrophic earthquakes in
Anchorage and Fairbanks, and wildfire that destroyed state
facilities. He asked about the state's liability.
Mr. Jordan stated there was no liability component when
considering property losses. He explained that if there was
a catastrophic loss, the state would go to the carrier for
the full limit. If the state did a self-insurance program,
it would have access to the fund at full value and would
probably turn to the Federal Emergency Management Agency
(FEMA) to help reimburse the losses.
Senator Wielechowski hypothesized about a catastrophic
incident in the state with enormous loss of hundreds of
millions. He asked how much the state would be responsible
for under the current insurance and if the state would rely
on FEMA if it was self-insured.
Mr. Jordan answered affirmatively. Currently the state's
catastrophic loss coverage from purchased insurance had a
limit of $50 million. The excess carriers would only pay
$50 million. There was a different retention schedule for
catastrophic versus non-catastrophic losses. He continued
that catastrophic losses were only paid by percentage of
value. He continued that the way the insurance was written,
it would take the loss of many buildings to get $50 million
from the insurance company, whereas with the provisions in
the bill, the state would pay the first dollar out the
door.
2:36:44 PM
Senator von Imhof understood that the deductible was the
first 5 percent of the building, but if the state did not
purchase insurance, it would be liable for the entire $50
million.
Mr. Jordan stated that with excess insurance on
catastrophic losses, the state was required to pay 5
percent of a buildings value for a catastrophic loss. Under
the self-insurance scenario, risk management would pay the
first dollar out the door to agencies that had losses out
of the catastrophic loss fund. If there was a $5 million
loss on a $100 million building, it would be paid out of
the fund.
Senator von Imhof asked about if the whole $100 million
building was lost to fire.
Mr. Jordan stated that the fund would pay up to $50
million, and the state would likely turn to FEMA for
support on the additional amount. He reminded that it would
be similar to the current scenario since $50 million was
the most that insurance would pay.
Senator von Imhof referenced the earthquake in November of
2018, and she imagined the losses exceed $50 million across
Southcentral Alaska.
Mr. Jordan stated that the losses to the state did not
exceed $50 million but the losses to all of the state did
exceed $50 million.
Senator von Imhof asked if the state had been able to
collect from FEMA in the scenario.
Mr. Jordan affirmed that there were a few agencies that had
gone to FEMA. He explained that FEMA had a requirement that
the Risk Management Division could not request the funds;
rather, the occupying agency of the building had to do the
request. He mentioned that the Department of Corrections
and the Department of Transportation and Public Facilities
had to go directly to FEMA.
Co-Chair Bishop asked if there had to be a federal disaster
declaration in order to apply to FEMA.
Mr. Jordan knew that Department of Military and Veterans
Affairs stepped in for disasters, but he did not know if
there had to be a disaster declaration.
Co-Chair Bishop asked if Mr. Jordan could respond to the
question in writing.
Mr. Jordan agreed.
Senator Wielechowski asked if the bill would apply to the
University or the Court System.
Mr. Jordan affirmed that the bill would apply to the Court
System, but the University had its own program.
Senator von Imhof asked if the State Insurance Catastrophe
Reserve Account could be swept.
Mr. Jordan did not know the answer. He offered to get the
answer from the Office of Management and Budget.
Senator von Imhof wanted to know if the fund could be swept
and the reasoning behind the fund status.
2:40:25 PM
PALOMA HARBOUR, FISCAL MANAGEMENT PRACTICES ANALYST, OFFICE
OF MANAGEMENT AND BUDGET, OFFICE OF THE GOVERNOR, replied
that the fund was not subject to the sweep because it spent
without further appropriation. Once there was money in the
fund, the actual expenditures from the fund did not require
further appropriation.
Mr. Jordan advanced to slide 5, which showed a bar graph
entitled "10-year History of Property Premiums/Losses,"
which illustrated the property premiums the state had paid
to losses and included FY 12 to FY 22. He pointed out that
in most years premiums far exceeded what had been paid in
losses, with the exception of FY 15 when the Crystal Lake
Hatchery burned down and there was a $4.4 million loss.
He pointed out that in FY 21 there was nearly zero premium
because the previous year the state had been unable to get
insurance because the market had not been able to meet the
states capacity of $7.8 billion worth of property. In FY
22, the state had about a $7.1 million premium. There were
losses in the current year that had not been recorded at
the time the report was run.
Mr. Jordan referenced slide 6, "10-year history of property
premiums/losses," which showed a table and a graph entitled
'10-year History of Property Premiums/Losses.' He pointed
out the blue line showed the state had about $34 million in
losses over the ten-year period. The orange line showed the
property losses.
Mr. Jordan showed slide 7, "Lapse Appropriations Summary":
The State Insurance Catastrophic Reserve Fund, Fund #
3209, (Cat Fund) is part of the General Fund and Other
Non-segregated Investments (GeFONSI). The GeFONSI are
funds that have been pooled together for investment
purposes. The Cat Fund is part of the Non-MOU group,
which allows for the interest earned to be deposited
back into the General Fund.
Mr. Jordan noted that he had a fiscal note he could
address.
2:44:03 PM
AT EASE
2:44:31 PM
RECONVENED
Co-Chair Bishop set an amendment deadline of Friday, April
22nd at 5 oclock.
HB 102 was HEARD and HELD in committee for further
consideration.
Co-Chair Bishop discussed the agenda for the following day.
ADJOURNMENT
2:45:02 PM
The meeting was adjourned at 2:45 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 81 Sponsor Statement 1.28.21.pdf |
HFIN 4/15/2021 9:00:00 AM SFIN 4/20/2022 1:00:00 PM |
HB 81 |
| HB 81am Sectional Analysis Version I.A 2.7.22.pdf |
SFIN 4/20/2022 1:00:00 PM |
HB 81 |
| HB 81am Summary of Change 2.9.22.pdf |
SFIN 4/20/2022 1:00:00 PM |
HB 81 |
| HB 81 Presentation SFIN HB81 NPSL 4.20.22.pdf |
SFIN 4/20/2022 1:00:00 PM |
HB 81 |
| HB102-DOA-DRM SFIN 2022 draft changes per Sen FIN 04182022.pdf |
SFIN 4/20/2022 1:00:00 PM |
HB 102 |
| HB 81 SFIN_HB_81_Committee_Follow-up_5.3.22.pdf |
SFIN 4/20/2022 1:00:00 PM |
HB 81 |