Legislature(2017 - 2018)BARNES 124
02/17/2017 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB111 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| += | HB 111 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
HB 111-OIL & GAS PRODUCTION TAX;PAYMENTS;CREDITS
1:06:36 PM
CO-CHAIR TARR announced that the only order of business would be
HOUSE BILL NO. 111, "An Act relating to the oil and gas
production tax, tax payments, and credits; relating to interest
applicable to delinquent oil and gas production tax; and
providing for an effective date."
1:08:07 PM
KEN ALPER, Director, Tax Division, Department of Revenue,
informed the committee the presentation on HB 111 would answer
previously submitted written questions and continue to specific
sections of the bill, which contain elements of legislation that
has been previously proposed, and is perhaps familiar to some
members. He introduced the four parts of the presentation.
REPRESENATIVE BIRCH asked Mr. Alper if HB 111 is the
administration's proposal and whether the bill has the
governor's support.
CO-CHAIR TARR, in response to Representative Birch, said the co-
chairs have asked the administration to respond to the bill "in
the same way that they provide the fiscal note. So Mr. Alper's
analysis today is relative to that."
MR. ALPER, in further response to Representative Birch, said the
governor does not support or oppose the bill, and does not take
a position on legislation as it works through the committee
process; however, he related the governor has said additional
changes need to be made in "the oil and gas tax credit world."
The administration did not propose the bill, and he said his
capacity today was to provide information and analysis.
Returning attention to part one of the presentation, Mr. Alper
advised there was an error in an earlier presentation and he
would point out the discrepancies. He then turned to the
question of government take, and stated $141 billion in oil and
gas revenue, restricted and unrestricted, is the actual total of
the amount collected since the beginning of the Trans-Alaska
Pipeline System (TAPS), early in 1978. Since the state's tax
policy switched to a net system, in the years 2007 to 2016,
Alaska has received $64 billion. Referring to previous
testimony advising government take should be one-third of oil
and gas revenue, he specified that 33 percent of market value is
too high because the market value of all Alaska oil was $527
billion, and the state averaged 27 percent from 1978 to 2016; a
33 percent share would put all of the development costs on
industry [slide 4]. Of the wellhead value, also known as gross
value at the point of production (GVPP), 33 percent share is too
low, and he provided the corrected totals: total wellhead value
of all Alaska oil was $347 billion and the state averaged 41
percent from 1978 to 2016. Of profits, 33 percent is too low.
Based on data available since 2007, the divisible profit of all
Alaska oil was $111 billion, and the state averaged 57 percent
from 2007 to 2016, with federal take added to that. At the time
of Senate Bill 21 [passed in the 28th Alaska State Legislature]
total government take was expected to be around 65 percent at a
wide range of prices, which reflects a two-thirds to one-third
split; however, the federal take will never approach 33 percent
following federal tax reform in 1987, and he explained the
effects related to federal taxes. Furthermore, with a new
federal administration, there may be additional decreases in
federal taxes [slide 6].
1:16:28 PM
MR. ALPER presented a graph of state the share of petroleum
revenue, based on market value that was unchanged from the
presentation at the hearing on 1/30/17 [slide 8]. Slide 9 was a
corrected graph of the state share of GVPP [wellhead value],
showing a decline from 1998 to 2005; in a higher price, higher
tax timeframe, the average state share of gross was about 47
percent, and now it is about 30 percent. In response to
questions, Mr. Alper adjusted GVPP for cash credits limited to
those earned on the North Slope.
REPRESENTATIVE RAUSCHER asked for clarification on the
corrections.
MR. ALPER, referring to the graph on slide 9, said the corrected
percentages are 40 percent, 47 percent, and 30 percent. In
further response to Representative Rauscher, he explained during
the creation of a new data set "a data point got dropped," which
added royalty barrels in error. Continued to slide 10, he said
the payment of cash credits is shown in blue crosshatch bars
subtracted from state share. He stressed in the gross period,
state share remains 40 percent, however, in the net profits
system during high prices, state share averages 46 percent and
during low prices, state share decreases to 27 percent,
illustrating that tax credits have more impact at lower prices.
REPRESENTATIVE PARISH asked whether the slide represents
outstanding credits that have not been repurchased by the state.
MR. ALPER answered the credits illustrated are actual cash out
the door; further, he said the impact of unpurchased credits
relates to credits from 2017 and are not reflected in slide 10.
CO-CHAIR JOSEPHSON returned to slide 10, and asked whether the
blue crosshatch bar for 2016 would be larger without the
governor's veto of $200 million.
MR. ALPER explained the governor put a cap on the repurchased
credits at $500 million. There was an estimate that credits
would reach $750 million, in fact, at the end of fiscal year
2016 (FY 16), the state paid $498 million worth of credit
certificates, which was an appropriate number for FY 16.
CO-CHAIR JOSEPHSON has heard in FY 16 there was turmoil related
to the certifications.
MR. ALPER further explained the governor's veto addressed the
concept of the open-ended repurchase of credits, which brought a
reaction from investors and industry; in fact, industry was
correct in recognizing a change. Specifically in Cook Inlet,
capital and well credits are tied to spending and applied for
quarterly and approved; net operating losses (NOLs) require an
annual tax filing due in March. When cash became limited, the
Department of Revenue (DOR) bundled the credits and the NOLs,
and that pushed certain credits into the next fiscal year.
CO-CHAIR TARR asked Mr. Alper to clarify fiscal year and
calendar year.
MR. ALPER gave an example of a company that has an operating
loss from work occurring in 2014, and files its taxes in March
2015, and DOR releases the credits in July. However, by the
time the appropriation and banking activities transpire, payment
is made in August 2015, which is FY 16 for a state expenditure
tied to a company expenditure in calendar year 2014.
CO-CHAIR TARR surmised the period of lower prices is also
related. In addition, slide 10 does not illustrate tax credits
used against tax liability.
1:28:36 PM
MR. ALPER clarified a tax credit against liability is revenue
that the state did not receive; the slide shows money that was
actually received, and therefore includes the credits against
liability. He continued to slide 11, which illustrated profits
on a barrel of oil at $54 per barrel, as forecast for FY 18.
The bill would reduce producer share from 29 percent to 27
percent, and increase state and municipal share from 56 percent
to 58 percent.
REPRESENTATIVE PARISH, referring to slide 11, asked why the
federal share is reduced.
MR. ALPER explained federal taxes are calculated after state
take, and so federal take is "their piece of a slightly smaller
pie." Adding additional information on the percent of value, he
said at $50 per barrel, each percentage point of total value is
worth about $90 million, and each percentage point of wellhead
value is about $75 million. A change proposed in HB 111 would
impact the per barrel credit and increase the state's revenue;
therefore, every dollar shift is a change, and for non-royalty
oil, $1 per barrel in added tax, or reduced credit, is $160
million. A 1 percent per barrel increase to a gross tax is
about $65 million. To explain how the bill affects companies
operating at a breakeven level, he said every 1 percent of
profit is $1.6 million to the state for every dollar above
"breakeven"; for example, if the breakeven is $40 per barrel,
and the price of oil is $60 per barrel, every percent of profit
taken by the state in increments would be worth $32 million
[slide 12].
1:34:01 PM
REPRESENTATIVE BIRCH observed the state's royalty share is 12.5
percent, "so is it fair to say that the state actually drives
twelve and a half times $90 million, or almost a billion dollars
in that scenario?"
MR. ALPER pointed out 12.5 percent belongs to the state after
transportation costs are subtracted; in fact, the state gets
12.5 percent of the wellhead value. The earlier slides
indicating the state received 30 percent included the royalty
percentage plus production, corporate income, and property
taxes.
REPRESENTATIVE BIRCH restated his point is every increase in
production is reflected in an increase in royalty share realized
by the state.
MR. ALPER said yes. Every dollar movement in the price of oil,
over the course of one year, is worth $25 million to $30 million
to the state. He turned to questions related to the economic
limit factor (ELF) [passed in the 10th Alaska State Legislature]
multiplier decline from 1998-2006. The data on slide 13 seeks
to "carve out" the North Slope portion of total production
because ELF was a North Slope multiplier. Within ELF
legislation, every oil field had a different multiplier; during
1995-1997 the average ELF multiplier was 11.1 percent. The last
column indicated lost or forgone revenue with a sum total of
nearly $3 billion over nine tax years [slide 13].
CO-CHAIR JOSEPHSON inquired as to the lesson learned from the
data provided on slide 13.
1:39:02 PM
MR. ALPER said the oil tax system had not changed since 1989;
the ELF formula was very complex, and formulas are based on
expectations and assumptions, which degrade over time, and
underperform. He opined slide 13 illustrates the tax system
should be revisited at the time it begins to underperform. As
an aside, Mr. Alper responded to a question on the cost of a
lawsuit defending an executive order in 2005 modifying ELF. The
state prevailed in the lawsuit, spending $486,000 in its defense
to save $500 million. Returning to questions from the
committee, he stated there were three earlier tax credits in the
gross tax system: 1.) exploration incentive credit against
royalty for exploration, now repealed; 2.) education tax credit
from 1987 for contributions to qualifying institutions; 3.)
alternative credit for exploration passed in 2003, designed to
be used against liability, carried forward, or transferred or
sold to another taxpayer [slide 14].
MR. ALPER directed attention to the oil and gas tax credit fund,
the statutory language of which has changed since FY 09. Slide
15 illustrated claimed credits, expenses, and end year fund
balance from estimated appropriations for FY 09 through FY 16.
Based on oil price, the percentage was either 10 percent or 15
percent, and limited by a statutory cap. Had the legislature
appropriated by the formula from FY 09 through FY 15, the fund
would be dry - in a manner similar to today - except for
industry's expectation that the state will repurchase the
credits.
1:48:57 PM
CO-CHAIR TARR surmised if the state followed its statutory
minimum, there would have been a balance in the fund in certain
years. However, if the tax system continues to allow credits,
the state must make further appropriations to the oil and gas
tax credit fund.
REPRESENTATIVE BIRCH said there has been anecdotal discussion
that the oil and gas industry invests around $6.5 billion to
generate state revenue through its royalty share and taxes. He
suggested DOR provide data that indicates whether the tax
credits have been successful inducing smaller independents,
production, and investment.
MR. ALPER offered to provide aggregated information from the
DOR, Tax Division, Revenue Sources Book and Forecasts (RSB),
broken out by the deductible lease expenditures of taxpayers and
the non-deductible lease expenditures by explorers.
REPRESENTATIVE RAUSCHER stated another byproduct of industry
investment, in addition to creating jobs, is the sales that are
conducted in the process of doing business.
MR. ALPER agreed the oil industry is critical to the Alaska
economy in terms of employment and procurement, and is estimated
to generate one-third of the state's economy.
CO-CHAIR TARR pointed out slide 15 illustrates the difference
between following statutory guidelines versus open-ended
payments.
1:54:10 PM
MR. ALPER stated slides 16 and 17 are updates to previous
presentations. Slide 16 was a graph of production tax before
credits, production tax net of repurchased credits, production
tax after credits used against tax liability, including Cook
Inlet credits, and NOL credits. As prices declined, credits
become a negative in FY 15; in FY 17, the vetoed credits are
deferred to FY 18, and thus are not a big impact. However, the
credits reappear as a $900 million expense in FY 18. Also, the
graph shows a blue line which represents carried forward NOLs of
the major producers. Slide 17 was the same analysis on all oil
and gas revenue.
1:57:22 PM
REPRESENTATIVE BIRCH asked for a slide showing just the North
Slope credits, because the high investment in Cook Inlet credits
influences the data. The tax credit discussion needs to be
centered on good and reliable information.
MR. ALPER said DOR will provide the requested information, and
advised the impact from FY 13 through FY 18 on the repurchased
credits will be approximately one-half.
MR. ALPER began the analysis of HB 111. He informed the
committee most of the provisions in the bill have been
previously debated in various formats - with the exception of
Section 6 - and he referenced sections of the bill and pertinent
proposed legislation [slide 19]. Section 1 addresses interest
rates, and he noted the interest rate of 11 percent was changed
in Senate Bill 21 to 3 percent over the federal discount rate,
not compounded. The administration felt this rate was too low
and the governor sought a compromise; however, the compromise in
House Bill 247 [passed in the 29th Alaska State Legislature]
changed the interest rate to 7 percent for a period of three
years, and afterward reverting to zero. A zero interest rate
means a taxpayer will not pay a tax assessment or settle a
dispute, because no interest would accrue, and HB 111 solves
this problem. He urged for an amendment so that a single
interest rate would apply to all outstanding state taxes [slide
20].
There followed a brief discussion on how to facilitate a change
to the interest rate related to taxes.
2:06:41 PM
CO-CHAIR JOSEPHSON inquired as to whether an interest rate that
applies for any type of tax would create a problem.
MR. ALPER said all of the other taxes were paying at 11 percent
from the '70s until 2013, and now pay 3.5 to 4 percent. Simpler
taxes get audited faster if at all; however, if there are taxes
due, the state should get a reasonable return, especially in the
likelihood of the state spending Alaska Permanent Fund earnings
to fund the operations of government, and permanent fund
earnings are about 7 percent.
REPRESENTATIVE PARISH questioned whether a change in the
interest rate on all outstanding taxes would inspire taxpayers
to initiate litigation.
MR. ALPER was unsure. He opined an aggressive audit program is
the most effective deterrent to elusive taxpayers. Turning to
Section 2, he provided a graph illustrating the increase in
revenue resulting from a change in interest from 4 percent to 5
percent. He noted an increase in the minimum tax tends to
slightly increase the range of prices at which the minimum tax
is in effect [slide 21]. Further, at $55 per barrel oil, the
impact of a 1 percent increase is $50 million to $60 million per
year [slide 22]. In response to Co-Chair Tarr, he stated at $80
per barrel, the Senate Bill 21 calculation generally governs,
and the minimum tax is not in affect. This factor is concealed
as the slide shows aggregated figures.
2:13:05 PM
REPRESENTATIVE BIRCH said slide 22 illustrates the proposed tax
increase on the oil and gas industry: at current prices, a $50
million to $60 million increase.
2:13:22 PM
MR. ALPER said yes. In further response to Representative
Birch, he said at current prices, this is the largest component
of the state's revenue increased by the bill. He acknowledged
the change in per barrel credits has an impact at higher prices,
but at current prices, [the increase in tax rate] is the largest
change in revenue. Changes in Senate Bill 21 prevented sliding
scale per barrel credits going below 4 percent of GVPP; however,
other credits, including NOLs, gross value reduction (GVR)-
eligible per barrel credits, small producer credits, and
alternative credits for exploration, can be used to reduce
payments below the minimum tax. Current law allows all credits
other than the sliding scale credits to reduce taxes below the
minimum tax - commonly referred to as "the floor"; the bill
seeks to prevent all other credits in AS 43.55 from reducing
taxes below the minimum tax - commonly referred to as "hardening
the floor" [slides 23 and 24].
MR. ALPER continued to explain the minimum tax in Section 3
addresses three different issues pertaining only to the North
Slope: 1.) small producer credits for companies producing fewer
than 50,000 barrels of oil per day in Alaska fields; 2.) per
barrel credits for GVR oil, now that GVR is limited from three
to seven years; 3.) NOLs for producers not eligible for cash
credits can be carried forward and used to pay below the minimum
tax - the most prominent issue surrounding hardening the floor
[slide 25]. Mr. Alper then explained how GVR-eligible per
barrel credits can reduce taxes below the minimum tax for legacy
and GVR-eligible oil at $60 per barrel [slide 26].
2:20:35 PM
CO-CHAIR JOSEPHSON questioned whether the terms in House Bill
247 restrict GVR oil from going beneath the floor.
MR. ALPER said no. House Bill 247 made two changes to GVR, but
producers can use the $5 per barrel credit to reduce the tax to
zero.
CO-CHAIR JOSEPHSON asked if the foregoing issue was vetted and
understood in 2013.
MR. ALPER opined it was recognized that GVR-eligible oil would
be allowed to go to zero. The issue is not a reduction of
value, but whether GVR can reduce the value to a negative. He
remarked:
What we learned was that the gross value reduction
could be used to artificially increase the calculated
size of a loss, and in doing so could increase a net
operating loss credit, and we started seeing some very
distorted operating loss credits that were far greater
than 35 percent of the loss - 80, 90, 100 percent of
the loss - because of the multiplicative factor of
being able to increase your loss with the GRV. That
was inadvertent, without question. There was some
substantial consensus in the committee process last
year, and that was a feature that found its way into
the final version of [House Bill] 247.
CO-CHAIR JOSEPHSON surmised the foregoing is an example of "the
stacking feature": legally using every credit to maximize a
loss.
MR. ALPER said the stacking feature is generally applying two or
more credits to the same expense, and he provided an example.
In response to Co-Chair Tarr, he gave an example of a company
with a $20 million loss that has earned a 35 percent credit of
$7 million; if the loss is modified by GVR and becomes a $50
million loss, the credit becomes $17.5 million, which equals a
90 percent tax credit.
REPRESENTATIVE RAUSCHER surmised the bill erased NOLs
altogether.
2:25:08 PM
MR. ALPER said no. House Bill 247 directs GVR cannot be used to
further reduce to a negative production tax value; Section 3 of
HB 111 proposes the calculation of tax for GVR-eligible oil - 35
percent of net as adjusted, minus the $5 credit - would not be
allowed to go below 4 percent of gross, which currently happens
until the price of oil increases to about $69 per barrel.
Therefore, currently new oil is not paying a production tax. He
reviewed the current cashable credit policy related to NOLs and
major producers: companies producing over 50,000 barrels per
day - the major producers and Hilcorp - are not eligible to
receive cash; NOLs for explorers and developers are allowable
expenditures, thus spending is a loss; NOLs for producers occur
when expenses exceed revenue due to low prices and/or
investment. As estimated in the RSB, at least one major
producer had an operating loss in 2015, and others possibly in
2016, thus $107 million worth of aggregated NOL credits are to
be carried forward and used against tax liability between FY 17
and FY 19 [slide 27].
2:29:19 PM
MR. ALPER recalled hardening the floor and letting loss credits
"roll forward" was recommended by a Senate working group in
2015, but due to market conditions for the industry and other
considerations, legislation did not do so. He expressed DOR's
technical concern with the bill, pointing out contradictory
language related to credits and the application thereof, and he
made a recommendation to address credits in various individual
sections [slide 28]. Mr. Alper turned to migrating credits,
addressed in Section 3, subsection (q), which prevents per
barrel credits from being used in a month other than the month
earned. He provided a slide listing the effects of migrating
credits, and advised in a period of volatile prices, the bill
seeks to "keep those per barrel credits in their own month"
[slide 29]. Slides 30 and 31 were graphics depicting the effect
of migrating credits. In 2014, during which prices were high
and then dropped, by October the per barrel tax was at $8,
reducing the tax after credits to about $60 million. By
December, companies could use $1 from the $8 credit, and pay the
minimum tax rate. For the year, the state received $1,522
million in production tax revenue; however, in November and
December, there were $112 million in "forgone" per barrel
credits. In April, DOR learned taxpayers had moved their
credits to January 2014, and applied them to offset a month of
higher oil prices. The state then refunded $112 million to
industry, resulting in a reduction of production tax revenue to
$1,410 million [slide 31]. Mr. Alper advised Section 3 of HB
111 intends to prevent migrating credits. He stressed the
revenue or savings gained by preventing migrating credits cannot
be reflected in the fiscal note, as the impact is only seen in
calendar years such as 2014, although the problem could be
exacerbated, and he provided an example [slide 32].
2:38:43 PM
MR. ALPER informed the committee Section 4 contains conforming
language related to migrating credits and how to administer the
new minimum tax. Section 5 addresses the NOL rate and he
described prior changes in the North Slope NOL credit rate from
2006 through 2016. During the time of Alaska's Clear and
Equitable Share (ACES) [passed in the 25th Alaska State
Legislature] tax system, the NOL rate was tied to the base tax
rate, thus at high prices and with progressivity, the effective
tax rate was often higher than the NOL rate. Senate Bill 21
tied the NOL rate to the base rate, but the per barrel credit
reduces the effective tax rate paid by producers to less than
the NOL rate to explorers, as explained and illustrated on
slides 33 and 34. The effect of HB 111 will move 35 percent to
15 percent, and mimic the effective tax rate as much as
possible, as a 35 percent flat tax rate is too high. Section 6
amends how companies can earn a tax credit certificate for an
operating loss credit. Currently, a certificate can be earned
for capital spending, well lease expenditures, and NOLs. Credit
certificates can be transferred to another taxpayer to use
against that company's taxes. However, HB 111 restricts NOL
credits so they are not eligible for state cash repurchase, but
must be sold or carried forward. Mr. Alper acknowledged this is
a very substantial change regardless of the tax rate [slide 35].
2:43:44 PM
MR. ALPER continued to Section 7. He directed attention to
slide 36 that illustrated the amount of per barrel credit
received in 2018, based on a range of prices. The effective per
barrel credit changes in dollar increments following the
wellhead value, until a wellhead value of $150 and above, when
the per barrel credit is zero. At $50 per barrel, per barrel
credits are zero, the minimum tax becomes equal or larger than
35 percent of net, and the minimum tax would govern. In Section
7, HB 111 proposes changing the calculation at prices between
$80 and $110, so that the per barrel credit cannot exceed $5.
This change is illustrated by the purple line and the dotted
orange line on slide 36. Slide 37 further illustrated the
change in minimum tax from 4 percent to 5 percent, the tax
received under Senate Bill 21 with the sliding scale credit, and
the 35 percent tax less the $5 maximum per barrel credit. The
change in revenue is nearly $300 million at an oil price of $75
to $85 per barrel, and he concluded the tax increase affects a
particular range of moderate prices, and less so at higher and
lower prices. He continued to Section 8 which prevents a
company from earning a cashable certificate for an NOL credit;
Section 8 limits credits that are eligible for repurchase to
Middle Earth and liquefied natural gas (LNG) storage and
refinery infrastructure credits [slide 38]. Section 9 addresses
how much cash per company per year can be spent, reducing the
current limit from $70 million to $35 million. House Bill 247
allows a company to get cash from the state at a certain
discount and subject to appropriation; HB 111 reduces the per
company, per year limit to $35 million, and reduces eligibility
for cash to producers below 15,000 barrels per day. He
explained DOR's concern is that the change only affects
explorers and developers in Middle Earth [slide 39]. He
provided further information related to large annual credit
payments made between 2007 and 2016, and pointed out of the
existing $500 million in earned certificates issued by the
state, three different companies are holding certificates of
over $100 million [slide 40].
2:48:11 PM
REPRESENTATIVE BIRCH asked whether the aforementioned $500
million represents the credits authorized by the legislature
last year and vetoed by the governor.
MR. ALPER advised the authorization by the legislature was for
$460 million, and $430 million was vetoed by the governor. Had
the veto not occurred, at this time the state would be holding
$70 million in uncashed credits. Finally, the material section
of the bill, Section 10, prohibits GVPP from being below zero.
He clarified wellhead value, under certain circumstances for an
individual field, can go below zero when affected by expensive
transportation, such as for a remote field, combined with low
oil prices. If so, the negative value can offset value from
other fields owned by the same producer; however, this is
relevant only in unusual circumstances [slide 41]. He provided
a slide that illustrated current tariff structures and pointed
out the difference in tariffs is related to the distance of the
fields to feeder pipelines and the Trans-Alaska Pipeline System
(TAPS); marine transport costs are added. The Point Thomson
pipeline is designed to carry 70,000 barrels per day which
consequently raises the cost of transporting oil, thus the
tariff from Point Thomson to the Badami connection is over $17
per barrel [slide 42]. Mr. Alper gave an example of gross value
potentially going below zero, and restated Section 10,
originally in previous legislation proposed by the governor,
protects the state from a company using a negative number from
other production in the calculation of its taxes [slide 43].
2:55:47 PM
MR. ALPER directed attention to the fiscal note identified as
"Provisions in HB 111\O." The line item impact of the minimum
tax increase from 4 percent to 5 percent results in increases of
$25 million in FY 18, $75 million in FY 19, and $60 million in
FY 20, which is the main revenue impact of the bill. In
addition, in FY 18 and FY 19, there are increases from changes
to credits effective 1/1/18, and from FY 20 to FY 22, increases
from changes to per barrel credits effective 1/1/18. Total
revenue impact is $45 million in FY 18, $75 million in FY 19,
and $60 million in FY 20 in new revenue from the bill.
Furthermore, there is the impact of reduced spending, such as no
cash repurchase of NOL credits, resulting in spending (budget)
impacts of $60 million in FY 19, and $120 million in FY 20.
Total fiscal impacts are $45 million in FY 18, $135 million in
FY 19, and $180 million in FY 20. He cautioned the reduced
demand for credits comes with a state obligation for future
demand for credits to offset future taxes, as indicated on the
slide, cumulating in $225 million in FY 22. All of the
estimates are based on the [RSB] Fall 2016 Forecast [slide 45].
Slide 46 illustrated the net fiscal impact of HB 111 with oil
prices ranging from $20 to $120 per barrel of Alaska North Slope
(ANS), in years FY 18 through FY 27. He concluded the impact of
HB 111 decreases as the price of oil rises. Mr. Alper offered
to provide comparative analyses on any forthcoming related
legislation, amendments, and committee substitutes.
HB 111 was held over.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB111 ver O 2.8.17.PDF |
HRES 2/13/2017 1:00:00 PM HRES 2/17/2017 1:00:00 PM HRES 2/20/2017 1:00:00 PM HRES 2/22/2017 1:00:00 PM HRES 2/22/2017 6:30:00 PM HRES 2/24/2017 1:00:00 PM HRES 2/27/2017 1:00:00 PM HRES 3/1/2017 1:00:00 PM HRES 3/1/2017 6:00:00 PM HRES 3/6/2017 6:30:00 PM HRES 3/8/2017 1:00:00 PM |
HB 111 |
| HB111 Fiscal Note DOR-TAX 2.12.17.pdf |
HRES 2/13/2017 1:00:00 PM HRES 2/17/2017 1:00:00 PM HRES 2/22/2017 1:00:00 PM HRES 2/22/2017 6:30:00 PM HRES 2/24/2017 1:00:00 PM HRES 2/27/2017 1:00:00 PM HRES 3/1/2017 1:00:00 PM HRES 3/1/2017 6:00:00 PM HRES 3/6/2017 6:30:00 PM HRES 3/8/2017 1:00:00 PM HRES 3/13/2017 1:00:00 PM |
HB 111 |
| HB111 Sectional Analysis 2.12.17.pdf |
HRES 2/13/2017 1:00:00 PM HRES 2/17/2017 1:00:00 PM HRES 2/20/2017 1:00:00 PM HRES 2/22/2017 1:00:00 PM HRES 2/22/2017 6:30:00 PM HRES 2/24/2017 1:00:00 PM HRES 2/27/2017 1:00:00 PM HRES 3/1/2017 1:00:00 PM HRES 3/1/2017 6:00:00 PM HRES 3/6/2017 6:30:00 PM HRES 3/8/2017 1:00:00 PM |
HB 111 |
| HB111 Sponsor Statement 2.12.17.pdf |
HRES 2/13/2017 1:00:00 PM HRES 2/17/2017 1:00:00 PM HRES 2/20/2017 1:00:00 PM HRES 2/22/2017 1:00:00 PM HRES 2/22/2017 6:30:00 PM HRES 2/24/2017 1:00:00 PM HRES 2/27/2017 1:00:00 PM HRES 3/1/2017 1:00:00 PM HRES 3/1/2017 6:00:00 PM HRES 3/6/2017 6:30:00 PM HRES 3/8/2017 1:00:00 PM HRES 3/13/2017 1:00:00 PM |
HB 111 |
| HB111 - DOR Response Questions & Bill Analysis Presentation - 2.17.17.pdf |
HRES 2/17/2017 1:00:00 PM |
HB 111 |
| HB111 - DOR Lifecycle Scenario Analysis Presentation - 2.17.17.pdf |
HRES 2/17/2017 1:00:00 PM HRES 2/22/2017 1:00:00 PM |
HB 111 |