Legislature(2021 - 2022)ADAMS 519
04/15/2021 09:00 AM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB81 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | HB 81 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE FINANCE COMMITTEE
April 15, 2021
9:03 a.m.
9:03:23 AM
CALL TO ORDER
Co-Chair Merrick called the House Finance Committee meeting
to order at 9:03 a.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Kelly Merrick, Co-Chair
Representative Dan Ortiz, Vice-Chair
Representative Ben Carpenter
Representative DeLena Johnson
Representative Andy Josephson
Representative Bart LeBon
Representative Sara Rasmussen
Representative Steve Thompson
Representative Adam Wool
MEMBERS ABSENT
Representative Bryce Edgmon
PRESENT VIA TELECONFERENCE
Ryan Fitzpatrick, Commercial Analyst, Division of Oil and
Gas, Department of Natural Resources; Jhonny Meza,
Commercial Manager, Division of Oil and Gas, Department of
Natural Resources.
SUMMARY
HB 81 OIL/GAS LEASE: DNR MODIFY NET PROFIT SHARE
HB 81 was HEARD and HELD in committee for further
consideration.
Co-Chair Merrick reviewed the agenda for the meeting.
HOUSE BILL NO. 81
"An Act authorizing the commissioner of natural
resources to modify a net profit share lease."
9:04:04 AM
RYAN FITZPATRICK, COMMERCIAL ANALYST, DIVISION OF OIL AND
GAS, DEPARTMENT OF NATURAL RESOURCES (via teleconference),
introduced himself. He thanked members for the opportunity
to present HB 81 which allowed for the modification of net
profit shares on net profit share leases by the Department
of Natural Resources (DNR). He introduced the PowerPoint
presentation: "HB 81 Net Profit Share and Royalty
Modifications on Oil and Gas Leases," (Copy on file).
Mr. Fitzpatrick turned to slide 2. He provided an outline
of the presentation which was broken into different
sections. He would describe net profit share leases and
move into the reasons why DNR believed allowing for the
modification of net profit shares in certain circumstances
was justified. He would also provide the committee with an
overview of the modification process and a preview of the
changes the bill proposed. The same modification process
for royalty modifications currently in statute would be
used for net profit shares. He would walk through the
royalty modification process and explain how that would
transfer to the modification of net profit shares. The
presentation would be an overview of both the current
royalty modification process and how it would apply to net
profit shares if the bill were to advance. Finally, he
would provide the committee with an overview of the changes
that were made in the current committee substitute. He
noted the appendix at the end of the presentation.
Mr. Fitzpatrick advanced to slide 3 showing the first
section on the overview of net profit share leases. He
advanced to slide 4 to discuss the royalty and net profit
share. He explained that a net profit share lease (NPSL)
was an oil and gas lease issued by the State of Alaska that
included a net profit share revenue component. He wanted to
distinguish the traditional royalty revenue component with
the net profit share component, because the net profit
share leases were a rather uncommon type of lease in
Alaska. He explained that a royalty component in an oil and
gas lease provided the state with a share of the gross
production from the lease. The state took its share of
royalty without having to consider the field costs. The
lessee was allowed to deduct certain transportation costs
to get oil from the lease to market. However, the actual
field costs for the development and operation of the lease
were not deducted against royalty. All of the oil and gas
leases offered by the state had a royalty component and
included NPSLs.
Mr. Fitzpatrick continued by explaining that a NPSL had a
royalty component but also had a separate revenue component
called a net profit share. A net profit share was a
percentage of the profits derived from the lease. In order
to calculate how the net profits were generated from the
lease, the net profit share accounted for all of the
development expenses incurred to encourage bringing the
lease into production. They were accounted for in a
development account. From the moment the development
expenses were incurred, the account was credited with
interest at the prime rate plus some additional percentage.
9:09:28 AM
Representative Johnson clarified that when there was a
lease sale a royalty was set and the net profit share was
also set. She wondered what mechanism would trigger going
beyond the original provision of the lease contract and
changing to a net profit share. She asked Mr. Fitzpatrick
for further clarification.
Mr. Fitzpatrick suggested starting at the beginning when a
lease was first issued. He explained that there were two
circumstances in which a lease could be issued with a net
profit share component. Leases that were currently offered
by the State of Alaska were traditionally offered with a
fixed royalty. When the lease was put out for bid, the bid
variable was a bonus bid, a cash bid that a company paid
upfront in order to secure the lease. A net profit share
lease could be issued in two ways. The first way involved a
lease containing a fixed royalty component, a fixed net
profit share component, and a bonus bid. The bonus bid
would be the bid variable.
Mr. Fitzpatrick continued that when a lease was put out to
bid the royalty percentage and the net profit share
percentage were specified. Companies would bid based on the
bonus bid to secure the lease at auction. The second way a
NPSL could be issued was with a fixed royalty component and
a variable net profit share component in which the net
profit share variable was the bid variable. It would have a
fixed royalty, and companies would bid the highest net
profit share rate in order to secure the lease at auction.
In looking at the NPSLs issued by the state, some had 30
percent fixed net profit shares, 40 percent net profit
shares, and some were more exact. In one instance, the
percentage was 92.3 percent - a result of companies bidding
based on the net profit share bid variable.
Mr. Fitzpatrick relayed that once a lease went into
production, the royalty component began payment
immediately. The state took a percentage of production from
the lease without any regard for the costs of development
or the costs of operating the lease. The costs of
transportation to get the oil or gas to market was simply
deducted from the royalty payment. If the state took the
royalty in-kind, alternative transportation arrangements
were made. The royalty payment continued throughout the
production life of the lease.
Mr. Fitzpatrick continued that in the case of the net
profit share component, the payment would not begin until
later into the life of the lease. The development costs for
the lease were credited to a development account which
earned interest while the lease was being developed. Once
the lease went into production, the revenues generated from
the sales of non-royalty oil and gas (the oil and gas
credited to the lessee) were determined and the costs of
operation of the lease were deducted from the amount.
Whatever was left over from that amount (the profits from
the operation) got deducted against the accrued development
costs for the lease (the costs incurred before the lease
entered production).
Mr. Fitzpatrick indicated that once the development account
reached zero, the lease was considered to be in payout. In
other words, all of the development costs had been recouped
by the lessee in addition to the interest that had accrued
during that time. At that point, the net profits generated
from the lease would be shared with the state based on the
net profit share percentage. From the time net profit share
payments began, the state had two revenue streams from the
lease. The royalty component continued the state always
received its royalty share from the production based on
gross production without regard to the expenses. Once the
lease reached payout, the state also received the net
profit share payment from the same lease.
9:15:06 AM
Representative Johnson stated it was her understanding that
the royalty and net profit shares were set at the lease
sale and did not change. She asked for a brief look-back at
the original lease sales versus present lease sales. She
asked if the state was heavy on the royalty side for early
lease sales. She wondered if there were any trends in what
the state required from its lease sales.
Mr. Fitzpatrick responded that historically the state
initially offered oil and gas leases with a fixed royalty
rate. The net profit leases were not offered by the state
until later. The initial oil and gas leases issued by the
state were predominately issued at a 12.5 percent royalty
rate. All of the net profit leases currently in existence
were issued in the late 1970s or early 1980s. During that
period, the net profit shares that were issued had fixed
royalty rates of either 12.5 percent or 20 percent. He had
a slide containing the information later in the
presentation.
Mr. Fitzpatrick continued that the net profit share
component ranged from 30 percent to 93.7 percent. After
some experience with net profit share leases, the state
experienced some difficulties in accounting and in
development. He would discuss the North Star development
later in the presentation. It was determined that it was in
the state's best interest to revert to issuing leases with
fixed royalty rates plus bonus bids. It had been the
state's practice since the early 1980s. Since then, the
state increased the royalty rates for oil and gas leases in
certain circumstances. Whereas the state had initially
offered oil and gas leases at a 12.5 percent royalty rate,
in certain circumstances and for currently offered leases
on the North Slope, the fixed royalty rate was
16.3 percent.
Representative Wool summarized the comments provided by Mr.
Fitzpatrick. He suggested that the net profit share lease
component was added but predominantly discontinued at
present. He asked if he was accurate.
Mr. Fitzpatrick responded that Representative Wool was
mostly accurate. He clarified that the royalty component of
the NPSLs was usually at the same rate or a higher rate
than what had previously been offered. The lowest royalty
rate on a NPSL was 12.5 percent. Some of them ranged to
higher fixed royalty rates in addition to the net profit
share component.
9:19:41 AM
Representative Wool suggested that originally there was a
fixed royalty, then for a while, a royalty plus a net
profit was added creating an additional income stream for
the state. He assumed the royalty would have decreased when
adding a net profit share. The royalty went up along with a
net profit share and was later discontinued. If there was
no profit, the net profit component would be zero. Mr.
Fitzpatrick had stated that the royalty went higher. He
assumed that the state had been in a different negotiating
position at the time.
Mr. Fitzpatrick responded that looking back at the history
of oil and gas production on the North Slope, Prudhoe Bay
came online in the late 1970s and early 1980s. When the
state was issuing oil and gas leases for prospects, there
was an expectation or hope that the prospects would be
similarly large finds. In subsequent developments it was
discovered that some of those finds were nowhere near as
respective as hoped. The North Star prospect was the
example he had illuded to earlier. In the late 1970s there
was an expectation or hope that the prospects would be
large fields able to bare the higher royalty and net profit
share component. Experience showed that it was not the best
way for the state to go about issuing oil and gas leases.
It was discontinued after several years.
Representative Josephson asked if any of the net profit
share leases had a 16.6 percent royalty. Mr. Fitzpatrick
responded that any of the currently issued net profit share
leases had royalties at 12.5 percent or at 20 percent. He
did not believe there were any at 16.6 percent. He had a
slide later that listed all of the net profit share leases
and their percentages.
Representative Josephson referred to slide 3. The last
bullet point said the sharing of net profits occurred once
exploration development costs allocated to lease were
recovered through revenues. He wondered why the state would
discount the net profit lease once the costs were paid off.
He suggested the bill would discount the net profit share
leases.
Mr. Fitzpatrick replied that the purpose of the bill was to
allow the department to reduce the net profit share in
certain defined circumstance. One circumstance was a
modification that would allow a field or pool that was not
currently in production because of it being uneconomical
without a modification to go into production. A net profit
share modification might also be allowed towards the end of
the life of a field. It might also be allowed if the field
had been shut in and a modification would extend the years
of its production. Otherwise, the field would be shut down
due to it being uneconomical. In such a case the state
could choose to grant a modification with the hopes of
keeping the field in production for a few additional years.
If the state chose not to grant the modification, the field
would potentially shut down and the state would not receive
either the royalty or the reduced net profit share lease
revenues.
Representative Josephson wanted the department to show how
everybody would win.
9:25:16 AM
Representative Wool asked about production taxes in
relation to a net profit share and royalties. Mr.
Fitzpatrick responded that he had a slide that might
address his question.
Mr. Fitzpatrick turned to the spreadsheet on slide 5 that
showed the difference between royalty and net profit share.
It also allowed for a description of the difference between
the components and the production tax. He reiterated that
the royalty component was assessed at the lease level. The
beginning of payments started with commercial production.
The payment did not consider the costs of operation or
developments. The net profit share was also assessed at the
lease level based on the net profits. The beginning of
those payments only started when the net profit lease
reached a payout stage. The net profit share leases
considered field costs. Royalty and net profit shares were
calculated differently than production taxes. Production
tax was calculated at the tax payer level and involved
payments that began at the start of production. Payments
were based mostly on estimates. Similar to a net profit
share, production tax took costs of development and
operation into consideration. It did so in a different way
than net profit share leases. There were similarities and
differences between all three of these revenue components.
The profit to the lessee was calculated on the cash flow
from the lease after all of the other payments were
considered.
Mr. Fitzpatrick continued to slide 6 which provided an
example of a net profit share lease. It showed some of the
operative language that was included in this particular
lease. The lease was issued to Amerada Hess Corporation in
1979. The second box on the slide indicated that the lease
was issued where the net profit share component was the bid
variable. The net profit share rate was issued at 93.2
percent. It was one of the leases issued in what was
presently the North Star Unit. It also had a 20 percent
royalty component. As he alluded to before some of the net
profit share leases had the net profit share components and
the royalty rates that were higher than those previously
issued by the state.
9:28:55 AM
Mr. Fitzpatrick advanced to the graphic on slide 7 showing
net profit sharing. The slide would help to explain how
production tax fit into all of the payments and revenue
streams. The slide presented a breakdown of the costs and
revenues from the production of a barrel of oil under two
scenarios. The first scenario was a traditional oil and gas
lease that only included a royalty component. The second
scenario was from a lease that also included a net profit
share component. For simplicity, he noted that he was not
representing oil and gas property tax or corporate income
tax in the diagram because they were assessed at the
property level or the tax payer level. The revenue streams
on the slide went more towards the actual production of the
oil itself. Between the two diagrams, the bottom three
components - the development costs, the capital
expenditures to bring the lease into production, the
operating expenditures, and the transportation costs all
stayed constant between the two examples. They were costs
that were borne for the production of the barrel of oil.
Mr. Fitzpatrick continued that the next component up was
the royalty component. The royalty component stayed the
same between the two leases assuming that the royalty rate
itself was constant between them. There were examples of
fixed royalty rate leases and net profit share leases where
the royalty rate was 12.5 percent. The next item up was
production tax which was paid after royalty. However, he
pointed out that production tax in the second diagram was
slightly smaller than production tax in the first diagram.
The second diagram included the additional net profit share
payment. For the purposes of production tax calculation,
the payment of net profit share was considered a deduction
for the purposes of production tax. The additional payment
reduced the revenue that a tax payer would pay production
tax. In the second diagram the state received the royalty
and a smaller production tax payment. The state also
received the net profit share payment. He pointed out that
the state received a larger share in the second diagram
than in the first diagram.
9:32:05 AM
Representative Wool commented that Mr. Fitzpatrick was
presenting hypothetical scenarios in which random numbers
were used that did not necessarily reflect reality. He
noted that on the previous slide the lease from 1979 had
the highest percentage of 93.2 percent. He suggested that
in the diagram on slide 7 the royalty was the same and the
production tax was less because the net profit share could
be deducted. If the net profit was zero, he wondered if the
production tax would be the same. He thought the diagram
was misleading because the illustration on the right looked
lower than the one on the left. It was slightly shifted
down even though Mr. Fitzpatrick reported that everything
was equal to royalty until the royalty line. If net profit
was zero, he wondered if the net tax would be the same
because it would not be deductible.
Mr. Fitzpatrick responded in the affirmative. He elaborated
that if talking about a net profit share lease where the
lease was not in payout and there was not a net profit
share payment being made, then production tax, all else
equal, should be the same between the two. He explained
that there would not be a profit share payment that would
be deducted in the second diagram. He apologized he had not
noticed the different height of the two barrels. It might
be that the second one was slightly smaller in comparison.
He would look at it after the presentation. His intent was
to show an apples-to-apples comparison. He noted he had not
attempted to quantify the diagrams based on particular
dollar values. All of the rations would change depending on
the ultimate price of the barrel of oil. He used
percentages as an example for the slide. It was not
intended to represent any particular dollar value.
Mr. Fitzpatrick moved to slide 8 which showed a map of
currently active leases on the North Slope of Alaska. He
noted that the next slide was the list of NOSLs with
additional details. He highlighted that the NPSLs that had
been issued on the North Slope were included in several
different units. All of the units containing NPSLs were
currently in production. However, not all NPSLs were
production. There were some units where there was
production from the unit but the production was not
credited to the NPSL because of the area that the
production horizon which was actually producing within the
unit. It did not reach the leases that had the profit share
term. Reading from left to right Colville River, Kuparuk
River, Oooguruk, Nikaitchuq, all had NPSLs.
Representative Wool noted there were 26 active NPSLs. He
asked how many leases were non-NPSLs. Mr. Fitzpatrick did
not have the exact number of non-NPSLs on the North Slope.
He thought the number was in excess of 1000. He could get
back to the committee with the number. Representative Wool
thanked Mr. Fitzpatrick and indicated the scale was fine.
Representative Johnson asked how many of the 26 NPSLs were
non-producing. Mr. Fitzpatrick wanted to continue to the
next slide that contained the answer to Representative
Johnson's question.
9:37:08 AM
Mr. Fitzpatrick indicated that slide 9 contained
information on all of the active NPSLs in the state. He
noted that the righthand column contained information on
whether there was production. It showed the payments that
were generated from the net profit share component. He
directed attention to the third set of leases. Point
Thompson was the unit that had NPSLs that currently were
not in production. There was production from the Point
Thomson unit, but the NPSLs in Point Thompson were not
associated with that production. There were two other sets
of leases in Kuparuk River and in Nikaitchuq where the
NPSLs were in production but had not reached payout
to-date. Therefore, they had not generated any net profit
share payments.
Mr. Fitzpatrick pointed to the issuance year on the left
side of the slide showing when the NPSLs were issued. He
noted that there were a couple of NPSLs with an issuance
date in the 2000s. They were NPSLs were created due to a
subdivision of a prior lease. A portion of the NPSL was
created in the 2000s, but the original lease that was
subdivided was issued during the late 1970s to early 1980s.
He pointed to the column showing the net profit share rate
for each lease. Most of them were issued at a 30 percent or
40 percent rate. In Duck Island and in Point Thompson there
were leases that were issued with higher percentages. They
were a result of lease options where the net profit share
rate was the bid variable. The royalty rates could also be
seen on the slide. Most of the leases were issued at a 12.5
percent royalty rate with the exception of the Duck Island
lease and the single Point Thompson lease which were issued
at a 20 percent royalty rate. At the time none of the
leases had a royalty percentage rate of 16.67 percent. He
believed it was after the state stopped issuing NPSLs that
the 16.67 percent royalty term became common for state
issuance.
Representative Josephson asked why Duck Island was treated
differently. He wondered why there was no gradation in the
bill. Mr. Fitzpatrick responded that the bill did not
contain the gradation. However, because the bill inserted
the modification of net profit shares into the currently
existing royalty modification structure, the existing
structure for royalty modification allowed for gradation.
The current structure required the Department of Natural
Resources to make a determination that new production or
continuing production would not be economic as part of a
modification. It would be in the case of new production or
for continuing production near the end of field life. He
believed the requirement that the department determined
that the production would not be economic without the
modification allowed the department to make the gradation.
9:42:23 AM
Vice-Chair Ortiz asked Mr. Fitzpatrick to define the term,
"non-economic." Mr. Fitzpatrick replied that within the
context of the royalty modification statute that existed
presently, the concept of non-economic or uneconomic
development was a development, either new or continuing,
that was not economic enough for the producer to make the
initial investment or to continue production from an
existing field. From the producer or the lessee's point of
view, the decision not to make the investment or to shut
down production from the existing unit. It looked at the
question of economics from the point of view of the lessee.
He qualified that the royalty modification, the statute
incorporated the notion of a reasonable lessee. The
department would not necessarily look at it from the
profitability standpoint of the particular lessee that was
applying for the royalty modification. However, from a
hypothetical general reasonable lessee or producer.
Vice-Chair Ortiz asked if it was accurate to say that
non-economic had to do with price.
Mr. Fitzpatrick responded that price was a variable that
could heavily influence whether a project was economic.
Economic would also include costs of development, projected
operating expenditures, the capital structure in place at
the time whether interest rates were low or high for
financing a development. The ultimate production would
influence whether a project was economical. If a
development had higher-than-expected or lower-than-expected
production could drive the economics. The intention of the
bill was not to change the modification process for
royalties. He noted that one of aspects of the existing
royalty modification statute was that in crafting any sort
of modification there was a sliding scale mechanism as part
of any modification. If oil prices rose in the future
higher than was expected at the time a modification was
granted, production came online at a higher rate, or costs
were less than anticipated, the royalty modification would
either phase out at higher process or phase out over time.
The statute as currently enacted considered the potential
for those changes after the modification was granted.
Representative Carpenter asked how the production got
associated with a particular lease. Mr. Fitzpatrick replied
that as a field or pool entered into production there was a
process of determining where the bottom hole of the wells
that were drilled ended up and production was associated
with those well locations. It was not necessarily based on
where the wells were drilled, but where the well bores
existed in the subsurface. Estimates were made of the
drainage radius around the well bore. Once those
determinations were made, the drain pattern as compared to
the surface leases and allocated on a percentage basis to
those different leases. He invited his colleague, Johny
Meza, to provide additional comments.
9:47:40 AM
JHONNY MEZA, COMMERCIAL MANAGER, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES (via teleconference),
responded that the explanation Mr. Fitzpatrick provided was
correct. He indicated the division generated percentages
based on the drainage production from each well and
provided the allocation percentage to each of the leases
including NPSLs.
Mr. Fitzpatrick reviewed the modification of the Northstar
Unit NPSLs through legislative action in 1996 on slide 10.
The slide provided some background on one of the issues he
had alluded to earlier regarding the modification of
certain NPSLs for the Northstar Unit. He noted he should
have mentioned when he was looking at the map and the list
of NPSLS a few slides back that neither the map nor the
list of current NPSLs included any leases in the Northstar
Unit. He further explained that while some of the leases in
the Northstar Unit were originally issued as NPSLs, in 1996
the legislature modified those leases through the enactment
of specific legislation to change those leases from NPSLs
to leases with a fixed and a variable royalty rate.
Mr. Fitzpatrick continued that the slide presented
information on the 4 NPSLs that were originally what made
up the Northstar Unit. They were issued in 1980. They were
leases that were issued with the net profit share as a bid
variable. He highlighted that the net profit share rates
ranged from a low of about 85 percent up to 93.2 percent.
It was the lease that he looked at as a specific example
earlier. He reported when the leases were originally issued
the expectation was that the Northstar Unit was going to be
a much larger discovery than it turned out to be. At the
time the leases were issued there was a bidding frenzy over
getting the leases and bidding high net profit share rates.
Once additional exploration was conducted it was found that
the discovery was not as large as expected which led to
issues getting the unit into development for several years.
Mr. Fitzpatrick reported that ultimately, BP approached DNR
and proposed development of the Northstar Unit including
the leases listed on the slide if something could be done
to modify the net profit share rates. At the time, the
legislature was enacting the royalty modification statute
that existed. However, the statute did not include the
authority to modify net profit share rates. Therefore, the
department initially declined to modify net profit share
rates for the particular leases. After continued
discussions, a modification package was negotiated with the
understanding that that package would be submitted to the
legislature for the legislature's consideration.
Mr. Fitzpatrick reported that in 1996, the Department of
Natural Resources and BP presented the legislation to the
legislature which modified the 4 specific leases listed on
the slide. The legislature considered and signed the
legislation into law. In the end, the leases retained their
20 percent fixed royalty rate. In exchange for the net
profit share rate, an additional sliding scale royalty
component was added to the leases based on the price of
oil. The sliding scale royalty could range up to an
additional 7.5 percent. The royalty component on the leases
ranged from a low of 20 percent to a high of 27.5 percent
based on the price of oil at any particular time. He
believed that a present, all of the leases were operating
at the highest rate, 27.5 percent, based on oil prices.
Mr. Fitzpatrick continued that after the legislation was
passed, it was challenged in the courts. The Alaska Supreme
Court upheld the modification by the legislature.
Thereafter, the Northstar Unit went into production, and
since entering into production the cumulative royalty
revenue to the state (listed in the far-right column on the
slide) had been $1.73 billion.
Representative Josephson asked who initiated the lawsuit.
Mr. Fitzpatrick could not remember the parties. He had a
reference later in the slide packet. He would follow up
with the committee with more information.
9:53:55 AM
Representative Josephson wondered why slide 6 was included
in the slide deck. He expressed astonishment that someone
would allow a bidding frenzy. He thought Mr. Fitzpatrick
had reported that the legislature essentially negotiated an
agreement to seriously modify the net profit share due to
the bidding frenzy. He suggested that the example that Mr.
Fitzpatrick used that was most egregious was never
realized. He asked if he was correct.
Mr. Fitzpatrick responded, "That's correct." He elaborated
that the lease that was issued on slide 6 with the 93.2
percent net profit share rate was one of the Northstar
leases that was modified by the legislature. He included
the example specifically to demonstrate that in particular
circumstances the modification of the net profit share rate
could lead to production that might not otherwise have
occurred. At the time the leases were issued in the
Northstar Unit, the expectation was that would be much
larger than it was which was the reason the net profit
share rates were bid so high. He thought the example
demonstrated potential issue with issuing NPSLs in that a
very high net profit share rate could insert circumstances
that were an impediment to the development of an oil and
gas unit that otherwise would provide royalty payments to
the state. Thereafter, it was determined that the use of
bonus bids in circumstances where there was a high
expectation, received state money on the front end, and on
the back end did not create the same potential for
development problems with the leases. It was one of the
reasons the state went from issuing NPSLs to more
traditional royalty leases with the bonus bid.
9:56:40 AM
Representative Wool thought the slide was showing 4 leases
issued in 1980 and undeveloped for 16 years. In 1996, the
lease holder communicated that they would not develop the
leases unless the state eliminated the net profit share
that ranged from 85 percent to 95 percent. He suggested the
percentage should have been reduced to 40 percent rather
than zero. He wondered why the decision was made to no
longer issue NPSLs.
Mr. Fitzpatrick had not delved into the history of the
state's decision to stop issuing such leases. He thought
encouraging development played a role. He had seen some
administrative challenges of administering the leases and
the net profit share component. They were certainly more
complex to administer. The state decided to stop issuing
the NPSLs in the early to mid-1980s. Thereafter, the state
had only issued oil and gas leases with the fixed royalty
percentage and the bonus bid.
Representative Wool did not believe the $1.73 billion
included production tax. He asked about production tax
which he assumed would be grater under a non-NPSL because
they could not deduct it. He wondered about further
analysis of the $1.73 billion with and without net profit
share including production tax. He thought the state would
have yielded more money cumulatively with royalty,
production, and net profit share. He asked if he was
accurate.
Mr. Fitzpatrick answered that it was difficult for him to
produce production tax numbers because of confidentiality
around tax records and the fact that several of the leases
did not have multiple tax payers with which the information
could be combined for confidentiality purposes. He did not
think he would be able to provide information around
production taxes specific to particular leases. He
suggested that production taxes levied at the tax payer
level across the Northslope with some variations for
individual units when there were accrued access lease
expenditures. It was difficult to present an apple-to-apple
comparison.
Mr. Fitzpatrick responded to the question of whether there
had not been a modification. If the Northstar unit had
entered production and the leases had included the original
net profit share rate, he would have expected to see a
larger revenue stream. He had not done the analysis
specifically. In the case of the Northstar Unit, the
modification was to reduce the net profit share rate down
to zero. It also added the sliding scale additional
royalty. The royalties received were larger than would have
otherwise been the case without the modification. He added
that the royalty payments began the moment Northstar
entered production. Whereas the net profit share payments
would have only begun after the initial development
expenses had been paid for. Without running the numbers, he
could not say which of the scenarios would have resulted in
a higher payment to the state. He could look at the
information, try to come up with something, and provide it
afterwards.
10:01:59 AM
Representative Wool thought it would be good information to
have. Mr. Fitzpatrick could try to come up with the
information. The question was whether Northstar would have
gone into production without the modification. At the time,
BP indicated they would not invest in Northstar in the
absence of the modification. He could look at the current
numbers for production and to come up with a hypothetical
payment stream with the net profit share rates. However, he
would not be able to do the analysis of whether the
investment would have been made without the modification.
10:03:50 AM
Mr. Fitzpatrick moved to the second section on the
description of why the department believed allowing
modification of net profit share could potentially add
value to the state.
Mr. Fitzpatrick moved to slide 12: "Increase Production
from Otherwise Stranded Resources." The intent of the bill
was to allow DNR to modify net profit shares. If production
did not occur the state would not receive royalty payments
or any net profit share payments. The state would not
receive production tax payments from the production that
did not occur. The goal of the legislation was to allow or
encourage production that otherwise would not occur so that
the state could receive some value for the resources. In
thinking about the potential for resources to become
stranded, there were two potential scenarios where
resources could become stranded.
Mr. Fitzpatrick conveyed that the first scenario was if a
new production, a production from a new field or pool, was
not economic and the producer elected not to move forward
with an investment in it. The state would not see any
production from the field which would result in a lack of
royalties, net profit share payments, or a production tax.
The state would receive no value for the resources other
than the bonus bid that was originally received for the
lease.
Mr. Fitzpatrick moved to the second scenario: when a field
or pool was nearing the end of its life and became a
stranded resource. He elaborated that when a field was
approaching the end of its life, production declined
causing revenues from the field to drop and operating
expenditures to potentially trend down with production,
although not likely at the same rate. The per-barrel costs
of production would increase. At some point, the per-barrel
costs might exceed the potential profit for a producer
prompting a shutdown. No additional production would be
received from the field or unit and no payments would be
made to the state. The goal of the bill was to allow
modifications when the department could determine that a
modification would result in production from a new field or
pool that would not be brought online otherwise. The
department could also find that a modification could extend
the life of a field or pool near the end of its field life.
It might result in the state receiving additional payments
from additional production. It could potentially lead to
lower royalty or net profit share rates, but the state
could receive payments for an additional number of years
where the field or pool would otherwise shutdown.
10:07:15 AM
Representative Johnson thought there were 26 active NPSLs
on the North Slope - 17 leases were producing and 9 were
not producing according to the chart on slide 9. She asked
if DNR would only be making changes to the 9 leases
currently not producing under the plan in the bill.
Mr. Fitzpatrick responded that, for the existing royalty
modification statute and for the proposed net profit share
modification process, the process required a producer or
lessee to approach the department with a proposal for a
modification. The department did not have the authority
under existing statute or in the bill to modify the royalty
rate or the net profit share rate without an application
from the lessee. The lessee had to first determine that the
field or pool was uneconomic either to bring into
production or to continue production and then propose
modification to the department. As part of the review
process the department looked at all of the records of the
lessee including financial records, resource evaluation
information, and subsurface data.
Mr. Fitzpatrick continued that the department also looked
at the current state of the market and potential forecasts
for changes in oil prices making its own determination
whether the production would otherwise be uneconomic. If
the department determined it to be uneconomic, only those
leases included in the application could be modified. The
department's goal, with reference to a sliding scale
royalty, was to only allow modification sufficient to
change the investment decision of the lessee. In other
words, the goal was to only allow enough modification to
either induce the lessee to make an initial investment to
bring a field into production or to invest enough in the
field or pool to continue production for a set number of
years.
10:10:03 AM
Representative Josephson thought that most of the fields
would have already invested heavily. He wondered why the
lease holders would not continue to invest. He asked how
the state measured the trustworthiness of lease holders.
Mr. Fitzpatrick thought Representative Josephson's question
got to the heart of when the department should be
authorized to allow for modifications. He reiterated that
the department did extensive analysis when a modification
application was received under the existing royalty
modification statute. There were a number of provisions in
place about how the analysis was done and included internal
guidelines within the department. He relayed that one part
of the statute allowed the department to seek a third party
to provide analysis and the cost would go to the applicant.
Mr. Fitzpatrick continued that one of the important
features of the current modification process was that the
legislature had set a higher bar of proof for modifications
than was typical for most applications. In the case of a
typical permit application, the burden of proof around the
application would be preponderance of the evidence (a 50
percent plus one burden of proof). If it was simply more
likely than not, then a fact was established and the permit
could be issued based on the fact.
Mr. Fitzpatrick explained that under the current royalty
modifications or net profit shares operated on a much
higher burden of proof. The lessee had to show clear and
convincing evidence that they had met the requirements of
the statute in order to be eligible for royalty
modification a standard the department took very
seriously. The applicant was required to produce voluminous
data on finances and sub surface data. The department
evaluated the information with a skepticism. There had been
8 royalty modification applications in the 26 years that
the statute had been on the books. He reported that of the
8 applications, the department had only approved 3 of them.
He detailed that 2 of the applications were denied and 3
were withdrawn by the applicant after a partial evaluation
by the department. The applicant opted to no longer proceed
with their modification application. Less than 50 percent
of the modification applications received by the department
had been granted. The bill intended to preserve the
requirement that the department treated modification
applications with a high degree of skepticism a component
of the review process.
10:14:23 AM
Representative Rasmussen asked if Mr. Fitzpatrick had any
graphs or charts that provided a timeline and additional
details of the 8 requested modifications. She thought some
background information at the time of the requests would be
helpful. Mr. Fitzpatrick replied that the information was
provided on slide 18. It listed all of the royalty
modification applications that the department had received.
The slide did not include the price of oil at the time of
the applications, but he could provide the information.
Representative Rasmussen thought that seeing a graphic
showing production levels prior to the modifications on the
three applications that had been approved would help to
show that the policy the legislature was putting into place
would work and would be in the state's best interest.
Representative Wool referenced the royalty modification
analysis. He asked if it had been done for the NPSL royalty
modification in 1996 shown on slide 10 in the Northstar
Unit. Mr. Fitzpatrick was not familiar with the analysis
that was conducted for the 1996 modification of Northstar.
He would follow up.
Representative Wool referenced the $1.73 billion that the
state netted from royalty. He speculated that BP decided
the field in the Northstar Unit was not feasible with the
net profit share rates. However, by adjusting the net
profit share rate to zero, it made it possible for BP to
make a profit. He assumed that BP did a calculation before
and after to verify their decision. He assumed the state
would have made the same calculations. Any information
would be interesting.
Mr. Fitzpatrick could look into the history of the
modification. He was not personally familiar with the
modification, but there might be others in the department
that might be.
Representative Merrick indicated there was about 40 minutes
left before the end of the meeting. She suggested that
members hold their questions until the end of the
presentation.
10:19:13 AM
Mr. Fitzpatrick moved to slide 13 to review flexibility for
royalty modifications. The department believed that
allowing for the modification of net profit shares would be
useful. Currently, the department could only modify
royalties. However, there were circumstances in which
allowing for the modification of net profit share rates
might give the department more flexibility when considering
an application for a royalty modification. For instance,
royalty payments were more certain. They started at the
beginning of production, whereas payments from net profit
shares might be delayed. The amount of royalty payments was
more consistent over time. There might be circumstances in
which the state would be better off allowing a modification
of net profit share rates instead of allowing a
modification of royalty rates.
Mr. Fitzpatrick elaborated that at present, the department
could only modify royalty rates. However, if given the
ability to modify net profit share rates in one of the
modification scenarios, the department might elect only to
modify the net profit share rates or modify net profit
share rates while modifying less royalty and preserving
more royalty payments for the state. With the option to
modify NPSLs, royalty shares might not have to be modified
or a blended modification could become an option.
Mr. Fitzpatrick addressed another way in which allowing for
modification of net profit share rates could increase the
department's flexibility. Currently, under the royalty
modification system, the department was allowed to decrease
royalty rates when considering a royalty modification
application. Similarly, the bill would allow for the change
in the net profit share rate to either decrease or
increase. When thinking about the sliding scale mechanism
for royalties, in a modification scenario there were
circumstances in which the department might seek to add an
increase in either royalty or net profit share rate in
order to recapture foregone revenue if royalty modification
was allowed early in a project's life or for lower oil
process in scenarios where process increased in the future.
There could be an increase in the net profit share rate in
addition to the royalty rate in order to recapture revenues
that had been foregone earlier in the project's life.
Additionally, in certain circumstances, it also might make
sense if the state was willing to forego royalty revenues
in low price environments to simply participate in higher
price movements using either royalty or net profit share
mechanisms. It might not be a recapture mechanism; it might
simply be an increase in the rates of higher oil prices in
order to capture more value for the state as part of one of
the modifications.
10:22:45 AM
Mr. Fitzpatrick continued to slide 14: "Why would DNR allow
the modification of the net profit share rate? A
hypothetical example." He pointed to the first graph and
the solid blue line. The slide had a pair of graphs that
represented two different potential economic scenarios
where modifications could make a difference in an
investment decision. He pointed to the first graph and the
solid light blue line with the economic evaluation from the
point of view of the producer. The zero-dollar line would
represent the total value to the producer. Where the solid
light blue line was below the zero-dollar line on the
graph, the project would be uneconomic. Based on the
information, the producer would not make the investment.
The dotted blue line above those lines represented a
modification of the net profit share rate. The dotted
orange line represented a modification of the royalty rate.
The solid grey line at the top of the graph represented a
modification of both the net profit share rate and the
royalty rate. In the first graph the hypothetical project
was uneconomic but very close to being economic. He
suggested that a modification of the net profit share alone
would be enough to push the line above the economic
threshold and sufficient to encourage or induce the
development in the investment by the lessee. In the example
the royalty modification would be granted. The state would
forego some portion of the net profit share payments but
would receive all of the royalty payments represented by
the difference of the dotted blue line and the dotted
orange line.
Mr. Fitzpatrick addressed the second scenario which was
similar in its construction. The lines represented the same
concepts. In the example net profit share leases consisted
of a larger share of the potential production. The
modification of net profit share rates contributed more to
the potential difference in economic outcome. In the
scenario the royalty relief alone would not be sufficient
to make the project economic. It was likely that a producer
would not invest in the project, and the state would
receive no royalty, profit share, or production tax
revenues at all.
Mr. Fitzpatrick continued that similarly, net profit share
modification alone would be insufficient to make the
project economic. If the state were to combine net profit
share and royalty modification, the state could get the
project to the economic threshold. The grey line
represented the maximum potential modification of both the
royalty and net profit share rates. However, the
department's goal in granting a modification would not be
to automatically move to the maximum potential modification
of those rates. It would only be to allow enough
modification of those rates to allow the project to become
economic and induce investment. The department would strive
to grant no more modification than was necessary to reach
the economic threshold. Instead of the grey line,
optimally, the department would strive to create a
modification mechanism that would involve both royalty and
net profit share modification but less than the total
amount that might be had in order to move the grey line
above the zero-dollar line so that the lessee invested in
the project but the state maintained the highest potential
returns for the project.
10:27:47 AM
Mr. Fitzpatrick turned to slide 15 to discuss the last
objective behind the legislation which was to streamline
the current process for net profit share modifications. He
referenced the Northstar modification process described
earlier. The modification required negotiations with the
state and a presentation of the modification package to the
legislature for its consideration. He indicated that the
Supreme Court decision that was mentioned earlier was noted
on the slide: Baxley v. State, 958 P.2d 422 (Alaskan 1998).
He would follow up with citational information about the
case.
allowing the net profit share modification along side the
royalty modification currently in statute would allow the
department to modify those rates in the same process as the
royalty modification presently and would streamline the
process. It was one of the goals of the legislation.
10:29:14 AM
Mr. Fitzpatrick moved to the third section of the
presentation starting on slide 16 which was an overview of
the modification process.
Mr. Fitzpatrick turned to slide 17: "Stranded Resources
Means Zero Production and Zero Revenues to the State." The
slide was a description of one of the royalty modifications
previously granted by the state to leases within the
Oooguruk Unit. The slide contained an excerpt of part of
the royalty modification decision. In the particular
instance, Pioneer Natural Resources applied to the state
for a royalty modification of the leases in Oooguruk
claiming they would not be able to economically develop the
project without a modification and would not proceed with
the investment. He noted that Pioneer shared data with the
state that allowed the state to conduct its own analysis of
Pioneer's claims.
Mr. Fitzpatrick reported that the department came to a
similar conclusion about whether the project was economic
and agreed to modify the royalty rates at Oooguruk. He
pointed to the bottom of the slide. The current payments
from the Oooguruk Unit to the state included $145 million
in royalties and $12 million in net profit share payments.
In 2006 the Oooguruk field was initially authorized and
came into production in 2008 or 2009. He noted that the
royalty modification that was originally granted had phased
out over time and ends completely in the current year. From
present day on, the Oooguruk Unit would be paying the state
royalties at the full rate that was originally in the
contract, and no other modification had been allowed after
2021. He invited Mr. Meza to provide additional details.
10:31:59 AM
Mr. Meza indicated that the production from the Oooguruk
Unit began in 2008. The royalty modification decision
enacted in 2006 contemplated a reduction in the royalty
rates in the first years of production until a certain
trigger. He confirmed that the royalty levels would return
to original rates beginning in 2021.
Mr. Fitzpatrick continued to slide 18 which provided a list
of all of the royalty modification applications that had
been received by the department since the royalty
modification statute was originally enacted in 1995. He
reported the department had received 8 modification
applications since the statute was enacted. He pointed to
the first application by BP from Milne Point which was
denied. Between 1995 through 1999 two additional
applications were received one by Unocal and one by
Phillips. Both applications were withdrawn after initial
analysis. In 2005 the Oooguruk application was the first
the department approved. The application was a joint
application by Pioneer and Eni and was the project he had
just discussed that was phasing out in the current year.
Mr. Fitzpatrick continued that two additional applications
were received in 2006 and 2007. The first, for the
Nikaitchuq Unit, was denied. The second application was
similarly withdrawn. In 2008, Eni, after purchasing the
entire Nikaitchuq Unit, applied again for royalty
modification at Nikaitchuq. The modification was granted in
2008 and contained a trigger based on oil price. The
royalty rated phased lower or higher overtime based on the
price of oil at a particular time. The modification would
phase out and end by 2036.
Mr. Fitzpatrick reported that the last application received
by the department was received in 2014 for a new pool
within the Oooguruk Unit, the Nuna Torok Pool. The
department considered and granted the application with a
provision included by the department in the grant of
royalty modification for Nuna was that Caelus had to
sanction the development and make a certain investment
level within a certain period of time after the royalty
modification as granted. Caelus did not make the investment
in Nuna which nullified the royalty modification.
10:35:43 AM
Representative Wool referred to Eni's royalty modification
application in 2008. The slide indicated that the NPSL had
not reached the payout stage. He also referred to the
previous graph on slide 14 containing different
modifications. He suggested that even with full
modifications, the fields did not become profitable for 18
years to 20 years. He wondered if it was typical for some
of the payouts to be delayed for such a long period.
Mr. Fitzpatrick responded that it varied field-by-field. He
referred to slide 9 containing the list of 26 NPSLs. He
confirmed that it could take several years for a field to
reach payout. Typically, it could take a while for the
initial development costs to be recuperated and for the
lease to reach payout. For certain fields if there was a
significant amount of production and relatively inexpensive
development, the payout period could be reached faster.
Whereas, for other leases where there was marginal
production or potentially more expensive development costs,
the payout could be much later. In both instances it took
some time after production began for the first net profit
share payments to be made. There were times where the state
waited 10 years to 20 years or longer for the first net
profit share payment to be made. Whereas royalty payments
were received the moment production began from the lease.
Representative Wool suggested that a royalty modification
appeared to be more desirable. He thought an NPSL
modification would be a lower priority. He asked if he was
accurate.
Mr. Fitzpatrick agreed that from a lessee's point of view
Representative Wool's statement was likely true. However,
from the state's perspective, if it was possible to modify
net profit share rates and if the modification of the net
profit share rate alone would make the field economic,
although the lessee might not benefit as much, the state
could preserve more of its royalty income especially
earlier in the field life while still making the field
economic. The state would be better off only allowing a net
profit share modification or a blended modification rather
than modifying royalty alone. One of the objectives of the
bill was to give the state the potential to craft a
modification that helped to flip the trigger of investment
by the lessee while preserving the state's interest to a
large extent.
Representative Wool agreed with the purpose of the bill.
10:40:13 AM
Representative Carpenter referred to the timeline and the
25 [26] active leases. He asked Mr. Fitzpatrick to provide
the number of original lease holders who continued to be
lease holders. He wondered how many of the original leases
had changed hands. Mr. Fitzpatrick could look into it and
see about providing some historical information.
Co-Chair Merrick asked how many applications the department
anticipated with a change in legislation. She also asked if
producers had requested the legislation. Mr. Fitzpatrick
responded that it would be difficult to predict whether
there would be a huge rush of applications. He believed
there had been discussions about extending Duck Island
production. He expected to receive more applications when
smaller units started to reach the end of their field life.
It was an area in which a legislative change could help to
increase the number of production years.
Representative Josephson drew attention to slide 18 which
highlighted the modifications and requests which were
granted and denied. He noted that for the Oooguruk Unit the
indirect expenditure report reflected that for 5 fiscal
years from FY 15 to FY 19 the state forewent about $90
million in royalties. The slide reflected royalties of
$142 million. He thought the slide suggested that without
the royalty relief, the royalty would have been
approximately $230 million. However, without the relief the
field might not have been developed. He highlighted that
royalty relief added up. He asked Mr. Fitzpatrick to
comment.
Mr. Fitzpatrick was not familiar with the methodology the
Department of Revenue (DOR) used for their indirect
expenditure report. He expected that Representative
Josephson was correct in his observation that the core
difference was whether the investment would have been made
without the relief. He could follow up with DOR to look at
their calculations and compare them to DNR's figures.
Representative Josephson responded, "If it's not too
burdensome, yes. Thank you."
10:45:37 AM
Representative LeBon asked about sunset dates. He wondered
why a modification was not done that did not include a
sunset date. He what the motive was for a sunset date. Mr.
Fitzpatrick responded that the sunset dates were calculated
for each project. In the first instance there were
conditions that were sometimes conditions that were put on
the modification in order toe ensure that the lessee
invests in the field the way they represented they would in
their application. In the second instance, once a
modification was granted and occurred for a number of
years, as part of that economic analysis, the department
strived to allow a modification only sufficient to induce
the lessee to make an investment or to keep a field in
production. Inserting a sunset into that modification
allowed the department to limit the amount of modification
that it granted in such circumstances. At a certain point,
the field returned to its original royalty rate or
potentially a net profit share rate. The state received the
additional revenues at that point in time. It was a way for
the department to limit the amount of modification to only
grant enough modification to change the investment decision
and no more.
Representative LeBon commented that the bill reminded him
of a bank being asked to modify a loan by a borrower
because of a change in interest rates to their
disadvantage. As a previous banker, he received that
request frequently. The structure a bank would counter-
propose to a borrower often included an element of shared
risk or benefit. If a borrower no longer liked its rate,
the bank would respond with some type of variable such as
including a floor and a ceiling. He hoped that if the bill
became reality that the state would be a good negotiator to
make sure there was shared benefit and risk.
10:49:19 AM
Representative Carpenter had a question regarding the
modification process. He wondered if economic factors other
than monetary factors were considered such as jobs lost or
local economic value. He pointed out that on slide 18 there
were 11 platforms in or near his district on the Kenai
Peninsula from the late 1990s. He noted that the Kenai
Peninsula oil industry had seen a sharp decline in jobs
over the previous decade. He wondered if the state had been
able to make conditions more favorable, whether job losses
would have been avoided. He reiterated his question as to
whether the modification process included an analysis of
job loss or local community impact.
Mr. Fitzpatrick responded in the affirmative. He elaborated
that additional impacts beyond revenues were considered.
The investments in the state and the jobs created were
potentially part of the best interest finding. Other
factors the state had considered previously when looking at
potential modifications were increases in production from
the North Slope that could potentially drive the tariff
rates on TAPS down. The tariffs were a function of the
throughput on the pipeline in part. If the state could get
additional barrels through the pipeline, it reduced the
tariff rate for all production on the North Slope
increasing the state's take from other fields. There was
less of a transportation deduction against the state's
royalty or tax revenues from other fields.
Mr. Fitzpatrick continued that there were definitely other
factors other than only the economics of a particular field
that were considered during the evaluation process. The
department also spent a large portion of time evaluating
the revenue and economics of a field because, ultimately,
it was what drove the investment decision what the state
was attempting to influence through the modifications.
Representative Carpenter understood the importance of
working with the lease holder. Ultimately, the state needed
to maintain flexibility to keep jobs in the state. He
reflected on a significant number of jobs lost in the
state. He encouraged flexibility.
10:53:48 AM
Representative Josephson spoke of a Supreme Court decision
regarding royalty. The court insisted that the legislature
and the executive branch impose a royalty, as there was not
one in the specific case. The Supreme Court indicated that
the state had to take a share of the mineral interest. He
wondered if the administration could request a lower share.
Mr. Fitzpatrick replied that it was possible to issue a
lease with less than 12.5 or 16.66 percent royalty. He
suggested that when there was limited geologic information
about the prospects on a particular lease, the department's
goal at the time of lease issuance was to try to capture as
much value for the state as possible. He thought, from the
department's perspective, the ability to propose a higher
royalty rate upfront then have the flexibility to
potentially modify the rate on the back end if warranted
and only to the extent that economic circumstances were
warranted allowed the department to capture more value
upfront especially from leases that turned out to be as
prospective as expected and for the limited set of
circumstances where the lease turned out to be not as
prospective gave the state the ability to modify the rates
to get the units into production without losing the
economic benefit of the higher royalty rate for other
leases. Representative Josephson commented that it made
sense.
10:56:33 AM
Representative LeBon asked if there was ever a situation
where the state would want to initiate a modification. Mr.
Fitzpatrick suggested that because the leases were
exercised through contracts, the state did not have the
ability to reopen and impose new terms on an oil and gas
the contract without the ascent of the counter party the
lessee. As pat of the royalty modification process, the
state had to wait for an application to be received by the
counter party in order to act on any modification.
Representative LeBon knew the answer to the question. He
encouraged the state to recognize that it was a one-way
street.
Co-Chair Merrick indicated the committee had reached a good
stopping place and reviewed the agenda for the afternoon.
HB 81 was HEARD and HELD in committee for further
consideration.
ADJOURNMENT
10:59:24 AM
The meeting was adjourned at 10:59 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| CSHB 81 Sectional Analysis 3.24.21.pdf |
HFIN 4/15/2021 9:00:00 AM |
HB 81 |
| HB 81 Letter of Support Alaska Oil and Gas Association 3.9.2021.pdf |
HFIN 4/15/2021 9:00:00 AM |
HB 81 |
| 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 |
| 2021-04-15_HB81 Presentation for HFIN.pdf |
HFIN 4/15/2021 9:00:00 AM |
HB 81 |