Legislature(2017 - 2018)BARNES 124
02/13/2017 01:00 PM House RESOURCES
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| HB111 | |
| Adjourn |
* first hearing in first committee of referral
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| += | HB 111 | TELECONFERENCED | |
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ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
February 13, 2017
1:00 p.m.
MEMBERS PRESENT
Representative Andy Josephson, Co-Chair
Representative Geran Tarr, Co-Chair
Representative Dean Westlake, Vice Chair
Representative Harriet Drummond
Representative Justin Parish
Representative Chris Birch
Representative DeLena Johnson
Representative George Rauscher
Representative David Talerico
MEMBERS ABSENT
Representative Mike Chenault (alternate)
Representative Chris Tuck (alternate)
COMMITTEE CALENDAR
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."
- HEARD & HELD
PREVIOUS COMMITTEE ACTION
BILL: HB 111
SHORT TITLE: OIL & GAS PRODUCTION TAX;PAYMENTS;CREDITS
SPONSOR(s): RESOURCES
02/08/17 (H) READ THE FIRST TIME - REFERRALS
02/08/17 (H) RES, FIN
02/08/17 (H) TALERICO OBJECTED TO INTRODUCTION
02/08/17 (H) INTRODUCTION RULED IN ORDER
02/08/17 (H) SUSTAINED RULING OF CHAIR Y23 N15 E2
02/08/17 (H) RES AT 1:00 PM BARNES 124
02/08/17 (H) Heard & Held
02/08/17 (H) MINUTE(RES)
02/13/17 (H) RES AT 1:00 PM BARNES 124
WITNESS REGISTER
LISA WEISSLER, Staff
Representative Andy Josephson
Alaska State Legislature
Juneau, Alaska
POSITION STATEMENT: On behalf of Representatives Josephson and
Tarr, co-chairs of the House Resources Standing Committee,
sponsor, provided a presentation related to HB 111.
ACTION NARRATIVE
1:00:46 PM
CO-CHAIR GERAN TARR called the House Resources Standing
Committee meeting to order at 1:00 p.m. Representatives Tarr,
Birch, Drummond, Parish, Rauscher, Talerico, Westlake, and
Josephson were present at the call to order. Representative
Johnson arrived as the meeting was in progress.
HB 111-OIL & GAS PRODUCTION TAX;PAYMENTS;CREDITS
1:02:09 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."
1:03:04 PM
LISA WEISSLER, Staff, Representative Andy Josephson, Alaska
State Legislature, on behalf of Representatives Josephson and
Tarr, co-chairs of the House Resources Standing Committee,
sponsor of HB 111, provided a brief personal background related
to her involvement with Alaska's oil and gas resource law for
the past 36 years, beginning with her participation during
debate on the Petroleum Production Tax (PPT) [passed in the 24th
Alaska State Legislature], and instituted in 2006. In the
context of HB 111, she said she compiled a history of tax
credits in order to aid the committee's understanding of the
bill. Ms. Weissler paraphrased from a document entitled,
"Alaska's Oil and Gas Production Tax [ - ] Tax Credits History,"
and dated 2/13/17, provided in the committee packet as follows
[original punctuation provided]:
The Petroleum Production Tax (PPT)
In 2006, after fifty-one years of a gross value oil
and gas production tax, Alaska switched to a net
profit tax system known as the Petroleum Production
Tax or "PPT." Reasons for the change included that the
existing gross tax system resulted in almost no
production tax revenue from even very productive
fields; the system was unable to adjust for increasing
oil prices and differences in field conditions between
the North Slope and Cook Inlet; and it provided
insufficient incentives for investment in Alaska's oil
and gas fields. The PPT was intended to increase
Alaska's share of oil production revenue and provide
incentives for oil and gas companies to invest in the
state.
Major Producers' Incentives. It was believed that
the tax advantages of the net profit system would
increase the major producers' (ExxonMobil, BP,
ConocoPhillips) investment in enhanced production from
the large legacy Prudhoe Bay and Kuparuk oil fields. A
taxpayer could deduct certain operating and capital
lease expenditures as part of the calculation for
determining their tax liability. In addition, the PPT
offered a 20 percent tax credit for qualified capital
expenditures. In effect, the more a producer spent in
Alaska's oil fields, the lower their tax.
Independent Companies' Incentives. The PPT offered
several tax credits to encourage independent companies
to explore for and develop smaller oil fields.
Companies could accrue the 20 percent credit for
qualified capital expenditures, including exploration
costs. In addition, a producer with less than 100,000
barrels production per day could qualify for up to a
$12 million tax credit provided the producer had a
positive tax liability. The PPT also provided a credit
of up to $6 million annually for oil or gas produced
from leases outside Cook Inlet and the North Slope
(known as "Middle Earth").
Net Operating Loss. The PPT provided for a carried-
forward annual loss credit, referred to as net
operating loss (NOL). Net operating losses are lease
expenditures that would be deductible except when the
deduction would cause the net value of taxable oil and
gas to be less than zero. A percentage of the lost
deductions are converted to tax credits that can be
applied against future tax obligations. The PPT
provided for a 20 percent net operating loss credit.
The NOL credit was introduced primarily as a benefit
to independent companies who would not have enough oil
production to generate a tax liability against which
to apply their lease expenditure deductions. The major
producers were expected to have enough production tax
liability to realize the full benefit of their
deductions in the year the expenditure occurred.
Tax Credit Purchase. Because explorers and new
producers would not produce enough oil or gas to have
much of a tax liability against which to apply tax
credits, independent companies doing business in the
state asked the legislature to establish a credit
purchase program. As originally introduced, the PPT
legislation allowed certain tax credits to be
transferred and traded on the open market. Since the
market was limited to the three major producers,
independent companies were concerned they would not
receive full value for their credits, while the buyer
could apply 100 percent of the credit against the
buyer's tax liability.
The final PPT included a provision for the state to
provide for the purchase of certain tax credits.
Because legislators and administration officials
worried about the potential impact to state revenue
should oil prices drop, purchases were limited to
companies producing not more than 50,000 barrels of
oil per day and there was a $25 million cap per
company. In addition, an applicant was required to
incur a qualified capital expenditure or be the
successful bidder for a state oil and gas lease within
24 months after applying for a transferable tax credit
certificate. The purchase payment could not exceed the
total of the expenditures or bid.
Tax credits that qualified for purchase were the net
operating loss credits, qualified capital expenditure
credits and credits offered under a 2003 exploration
credit program.
2007 Alaska's Clear and Equitable Share (ACES)
In 2007, changes were made to the PPT under the
Alaska's Clear and Equitable Share Act or"ACES." The
changes were made because of lower tax revenue from
higher than anticipated lease expenditure deductions.
A corruption scandal that tainted the vote of several
legislators during the PPT debate led legislators to
be more receptive to making changes. Though the
administration considered switching the tax system to
a gross value tax, they concluded that a gross tax was
not flexible enough to address the differences between
oil and gas fields, and didn't account for expensive
resource development such as heavy oil. Among other
things, ACES retained the PPT tax credits and cash
purchase program; and established an oil and gas tax
credit fund to pay for the credits.
The Oil and Gas Tax Credit Fund and Credit Purchases
ACES established the oil and gas tax credit fund as a
way to purchase qualifying credits more efficiently.
The amount of money available to the fund was based on
a set percentage of production tax revenue; 10 percent
when oil prices were $60 or more, 15 percent when oil
prices were less than $60. The $25 million cap
established under the PPT was repealed. The $25
million per company cap was lifted because small
producers found the cap too low to be useful.
In response to legislators' questions regarding what
would happen to the fund if oil prices dropped, an
administration official explained that regulations
would determine how to allocate payments when there
was an insufficient fund balance. He said, "a long
period of low prices could lead to insufficient money
in the fund after lots of credits have been paid out,
and the legislature might choose to not spend the
money on credits." He stated that remaining credits
not purchased by the state could either be carried
forward or transferred to another taxpayer who had
sufficient tax liability.
Appropriations to the Oil and Gas Credit Fund. In
2008, the first year after the oil and gas tax credit
fund was created, the legislature followed the
prescribed formula in appropriating money to the fund.
Starting in 2009, the legislature provided an open-
ended appropriation to cover all tax credit purchase
applications. During the following years the
legislature continued this practice, creating an
expectation among oil and gas companies that all
qualifying credits would be purchased.
Easing Restrictions. In 2010, the requirement that
an applicant incur a qualified capital expenditure or
buy a state oil and gas lease to qualify for a
purchase payment was repealed. This was done to help
companies get project financing companies looking to
invest wanted to know they would get full value for
the credit without worrying about whether the credit
would meet the investment requirement. The legislature
also added a new tax well lease expenditure credit
program targeted at Cook Inlet gas exploration and
production. The new credits could be purchased by the
state.
Tax Credit Purchases and Private Financing. In 2013,
the legislature passed an amendment to the production
tax that specifically allowed for the assignment of
production tax credits to a third-party assignee
without the state's consent. This meant companies
could use their tax credits as collateral for loans or
sell credits to a bank or investment institution.
There is evidence the provision went farther than
intended. The provision was offered as an amendment in
House Finance to a Senate bill dealing with fish
taxes. An administration official testified that the
amendment would help open private equity markets to
smaller investors in the state. When asked about
whether the provision applied to North Slope
producers, the maker of the amendment said she
"believed that the amendment applied only to Cook
Inlet and Middle Earth" and to gas. The senator whose
bill was being amended stated "The goal was to bring
additional gas to Cook Inlet consumers." As it turned
out, the amendment applied to both oil and gas and to
all net operating loss, qualified capital expenditure
and well lease expenditure credits.
The Sure Thing. In 2015, a Wall Street Journal
article titled "How Wall Street Makes Money on
Alaska's Oil Tax Breaks" described how Alaska oil and
gas companies would sell their rights to a credit or
use the rights as collateral for a loan. The companies
would give up between five to twenty percent to a
lender or buyer, who would get the right to collect
the entire state payment. It has become apparent that
lenders saw little risk given the state's track record
in fully funding tax credit cash purchase
applications.
Not Such a Sure Thing After All. The estimated
amount of purchasable credits grew from $180 million
in 2009 to $700 million in 2015. In 2015, the
legislature passed an open-ended appropriation to
cover all purchase applications. Had the statutory
formula been followed, approximately $91 million would
have been available for appropriation. With oil prices
plummeting and a $3 billion deficit, the governor
vetoed $200 million of the appropriation. In 2016,
facing a $4 billion deficit, he vetoed $430 million,
leaving the $30 million required by the statutory
formula. The question remains how to deal with the
remaining tax credit purchase applications.
2013 - Senate Bill 21
In 2013, oil and gas companies' discontent with some
ACES provisions and concerns about declining North
Slope oil production and the fracking boom in the
Lower 48 led the Parnell administration to introduce
Senate Bill 21. Administration officials also
expressed concern that their analysis of $6 billion in
tax credits found no direct connection to future
production. They worried that if oil prices dropped
and company investments increased, the state budget
would have a deficit of billions of dollars and the
state would "still be on the hook for the credits."
Tax Credit Policy Change. For North Slope companies,
SB 21 changed the state's oil tax policy from tax
credits based on investment to credits based on
production; the more production from a field, the
lower the tax. The theory was that companies would be
more inclined to invest in the state and increase
their production.
SB 21 Tax Credit Changes.
SB 21 repealed the qualified capital expenditure
credit for North Slope oil and gas activities. The
credit remained in place for other areas of the state.
SB 21 included a gross value reduction (GVR) where a
certain percentage of "new oil" on the North Slope
would be tax-free. The bill added a $5 per barrel
credit for production that qualified as new oil
subject to the gross value reduction. The GVR and new
oil credit applied for the life of the field.
For production that did not qualify as new oil, such
as oil from the Prudhoe Bay oil field, a sliding-scale
production based tax credit was added; from $8 per
barrel when the gross value of oil was $80 or less, to
$1 per barrel between $140 and $149 gross value, and
zero after that. The credit is not available for
purchase by the state.
For the North Slope, SB 21 increased the net operating
loss credit to 45 percent until 2016 to ease the
transition away from qualified capital expenditure
credits. After 2016, the percentage was set at 35
percent the same as the new production tax rate of
35 percent. For other areas, the rate was set at 25
percent.
2014 Repeal Referendum. In 2014, public
dissatisfaction over the new oil and gas production
tax system prompted a citizens' referendum to repeal
SB 21. The repeal would have reinstituted ACES in its
entirety. Among other issues, supporters of the repeal
argued that over time an increasing percentage of oil
would qualify for the new oil tax breaks and the
state's percentage of profit would decrease
indefinitely into the future. There were also concerns
that tax credits on production would not encourage
Alaska investment since the credits did not require
instate investment. The opposition argued SB 21 was
working to attract Alaska investment and would
increase state revenue over the long-term by
increasing production. The referendum failed by a vote
of 99,855 (52.7 percent) to 89,608 (47.3 percent).
2016 HB 247
Starting in 2015, oil prices dropped from over $100
per barrel to below $40 per barrel. With a $4 billion
deficit, the state could no longer afford all the tax
credit incentives offered as part of Alaska's oil and
gas production tax. To ease the pressure on future
state budgets, the administration introduced and the
legislature passed HB 247 making changes to several
tax credits.
? HB 247 amended Cook Inlet tax credits to phase out
by 2018, including the net operating loss credit. For
Middle Earth, credits were approximately halved. The
bill also placed a cap on cash purchases to individual
companies; $35 million would be purchased at full
value, and another $35 million discounted by 25
percent. Any additional credits would have to be
carried into a future year for either a cash purchase
or use against a tax liability.
? For North Slope activities, HB 247 added a provision
to the gross value reduction setting a time limit on
how long the oil would be considered "new" oil
excluded from taxation. The reduction expires after
seven years of production or three years if the price
of oil is greater than $70 per barrel.
2017 What's Next
Most of the changes in HB 247 took effect on January
1, 2017. There are still credit programs and other
provisions that could cost the state millions,
possibly billions, in the coming years.
Net Operating Loss. The North Slope net operating
loss credit remains at 35 percent. Without changes,
there is the risk the credits could take the
production tax to zero and increase the amount of
credits available for purchase. The risk increases
with continuing low oil prices and increasing North
Slope activities.
Minimum Floor. Starting with the PPT, the production
tax included a tax floor of not less than four percent
of the gross value when oil prices were more than $25
per barrel. While the sliding-scale per barrel tax
credit cannot reduce a North Slope producer's tax
liability below the floor, net operating loss credits
can take the tax to zero. Purchasable credits can take
the tax below zero.
Migrating Credits. Currently, a taxpayer can apply
sliding-scale per barrel tax credits that cannot be
used in one month to offset a tax liability from a
different month in that calendar year. This occurs in
a year where the minimum tax is in effect in some
months and not in others in a year.
Outstanding Credit Purchase Applications. The
Department of Revenue's Fall 2016 Forecast estimates
there will be over $887 million in outstanding credits
available to purchase at the end of fiscal year 2018,
assuming around $74 million is appropriated under the
credit fund statutory formula. If cash purchases
continue to be permitted and appropriations are
limited to the statutory formula over the next decade,
this balance is expected to grow to $1.6 billion by
the end of fiscal year 2026.
[During the presentation the following questions were asked and
answered.]
1:14:53 PM
REPRESENTATIVE BIRCH asked whether net operating loss credits
(NOLs) were broadly supported by the legislature.
MS. WEISSLER was unsure, and opined the bigger concern at the
time was the cash payout, and how to "level the playing field"
for the independent companies. She offered to research this
question.
1:25:27 PM
CO-CHAIR JOSEPHSON questioned why the legislature would have
made a change in policy allowing a cashable credit to be spent
outside the state on an outside development or exploration
project.
1:25:59 PM
MS. WEISSLER explained that was not the intent of the change;
the intent was that the money would be invested in the state,
however, there were no "sidebars" limiting the law. She
referred to a Linc Energy 2013 annual report that described how
the company sold credits to an investment company and applied
the cash to Alaska and Gulf Coast costs. She said this was not
a policy decision but "trusting that they would invest in the
state - that was the intent."
1:27:02 PM
REPRESENTATIVE PARISH, noting there could again be insufficient
money allocated to meet the amount recommended in statute, asked
how the state determines which tax credits get paid.
MS. WEISSLER expressed her understanding allocating to "first
in, first out" is how the pertinent regulations work.
1:33:35 PM
REPRESENTATIVE BIRCH inquired as to how a former governor and
legislature could have differed by a significant multiplier on
what was clear and equitable about Alaska's Clear and Equitable
Share (ACES) [passed in the 25th Alaska State Legislature].
MS. WEISSLER pointed out oil prices were high and there "was an
atmosphere ... that was different from prior years."
1:34:40 PM
REPRESENTATIVE BIRCH questioned when tax credits first became an
inducement to investment and development in Alaska's tax policy.
MS. WEISSLER recalled in 1978, there was a tax credit tied to
leases and with certain requirements. The Economic Limit Factor
(ELF) [passed in the 10th Alaska State Legislature] was its own
incentive in 1977. The administration at that time determined
as operating costs go up and field production goes down, an
economic limit is reached, thus the field will not produce
enough to balance its costs during further production.
Therefore, the economic limit factor was part of a formula
developed to bring the tax rate down as fields decline, in order
to give companies an incentive to continue producing from
marginal fields, but there was not a credit system until PPT.
CO-CHAIR TARR, elaborating on Representative Birch's earlier
question, confirmed during debate on ACES, the proposed
progressivity rate was increased from 0.2 percent to 0.4
percent.
MS. WEISSLER said that sounds right. She agreed progressivity
increased exponentially with higher oil prices.
1:41:20 PM
REPRESENTATIVE BIRCH informed the committee he has read that the
majors would not make the investments today that they made many
years ago. He asked whether HB 111 is an increase or a
decrease, and if approved, for the broad range of the changes
the bill would net the state.
MS. WEISSLER said modeling is needed for the specific changes
and numbers, and she deferred to the bill's fiscal note.
1:42:57 PM
CO-CHAIR JOSEPHSON directed attention to Ms. Weissler's estimate
that the outstanding credits are growing by "only" about $100
million per year over the next decade, and noted this amount
could be offset by new opportunities on the North Slope;
however, because the payments could be capped at [$74 million by
the credit fund statutory formula], the credits can accrue into
the billions of dollars. He questioned whether this is a
conservative number.
MS. WEISSLER said Alaska's tax credit system is an unknown as
far as companies' decisions are concerned, and on how the tax
credits factor in; also, the state's return on investment is
unknown. She deferred the question to the Department of Revenue
(DOR) and advised the existing system lacks information and
analysis on the state's return on investment.
[CO-CHAIR TARR passed the gavel to Co-Chair Josephson.]
1:45:37 PM
The committee took an at ease from 1:45 p.m. to 1:50 p.m.
1:50:28 PM
CO-CHAIR TARR directed attention to a document provided in the
committee packet, verbally identified as a "cheat sheet," that
will help the committee recognize relevant sections of Alaska
Statutes during the sectional analysis of HB 111. One of the
goals of the proposed legislation is to establish durability in
the state's tax policy, understand the history of the policy,
and only make changes that move the state toward a stable and
predictable tax system at all oil prices. She pointed out the
frequency of repeals and reenactments of tax policy legislation
illustrates the difficulty in making the right decisions.
1:52:59 PM
REPRESENTATIVE BIRCH returned attention to HB 111 fiscal note
Identifier: HB111-DOR-TAX-02-10-17, and asked if the bill is a
$45 million tax increase, raising to $85 million in fiscal year
2023 (FY 23).
CO-CHAIR TARR explained the one tax increase in the bill is the
change in the minimum tax from 4 percent to 5 percent; most of
the other changes in HB 111 are prospective in nature, changing
the state's risk after the effective date of 1/1/18. She said
further discussion on the fiscal note would follow after the
sectional analysis.
CO-CHAIR TARR paraphrased from the sectional analysis for House
Bill 111, Version O, as follows [original punctuation provided]:
Section 1. Amends AS 43.05.225 regarding interest on
delinquent oil and gas production tax payments to
remove a three year limit on accrual of interest.
Since 2014, the interest rate for delinquent taxes was
set three points above the Federal discount rate. HB
247 added a new section increasing the rate for oil
and gas to seven points above the Federal discount
rate compounded. The higher rate applies only for the
first three years after the tax becomes delinquent
after which there is no interest. The amendment
repeals the three year limit because zero interest
discourages companies from settling tax disputes with
the state.
CO-CHAIR TARR further explained the three year limit is
removed because it is inconsistent with existing statute.
The Department of Revenue (DOR) has six years to complete
audits, due to the complexity of the tax system, thus the
three year limitation on interest is a "mismatch." She
acknowledged the industry's criticism of the time the state
requires to complete audits; in fact, no audits of the
present system have been completed. Co-Chair Tarr reviewed
the history of this issue. She continued the sectional
analysis [original punctuation provided]:
Section 2. Amends AS 43.55.011(f) to change the North
Slope minimum tax from not less than four percent of
the gross value to five percent for oil and gas
produced after 2018. The section removes the variable
minimum tax that would occur at sustained oil prices
at below $25 per barrel; the five percent minimum tax
would apply at all prices.
Note: The section ends the minimum tax for oil and gas
in 2022. That is not the intent. The minimum tax for
oil should continue past 2022. In existing statute,
the net production tax on gas will change to a gross
value tax system in 2022 and the minimum tax for gas
will end. A correction will be made in a future draft
of the bill.
CO-CHAIR TARR said the 5 percent minimum tax would apply at all
prices after 1/1/18. In addition, there is a drafting error to
be corrected by a later version of HB 111.
1:59:19 PM
CO-CHAIR JOSEPHSON recalled the increase from 4 percent to 5
percent was proposed last year and was related to the governor's
fiscal plan and its premise that all sectors of the economy
should participate in solving the state's fiscal problem. He
questioned whether the increase is based on "the
administration's thinking, at least last year."
CO-CHAIR TARR agreed. During the debate on Senate Bill 21
[passed in the 28th Alaska State Legislature] oil prices ranging
from $30 to $40 per barrel were not considered. However, the
price environment has changed, perhaps for the foreseeable
future. She continued the sectional analysis [original
punctuation provided]:
Section 3. Adds a new section to AS 43.55.011 to make
it clear that application of any tax credit issued
under the oil and gas production tax may not be used
to reduce the minimum tax of five percent. The second
sentence in this subsection relates to fixing a
situation where a taxpayer can apply per barrel
credits that cannot be used in one month due to the
minimum tax to offset a tax liability from a different
month in that calendar year (the "migrating" credit
issue). This issue only occurs in a year where the tax
rate is below the minimum tax in some months and above
the minimum tax in other months in a year.
CO-CHAIR TARR further explained the second part of Section
3 refers to the migrating credit issue described in the
earlier presentation. She continued the sectional analysis
[original punctuation provided]:
Section 4. Amends AS 43.55.020, related to monthly
installment payments, to reflect the change to the
minimum tax in section 2 and the migrating credit
issue in section 3.
Section 5. Changes the carried-forward annual loss
the net operating loss credit rate on the North
Slope from 35 percent to 15 percent. After January 1,
2018, a taxpayer will only be able to apply for tax
credits up to 15 percent of their net operating loss.
CO-CHAIR TARR further explained Section 5 does not eliminate any
of the state's current liability, but reduces the amount
companies can earn. The aforementioned fiscal note will show
additional information on the effect of Section 5.
2:06:25 PM
REPRESENTATIVE BIRCH directed attention to page 2 of the fiscal
note indicating $8 billion in tax credits have been received by
companies. Tax credits are meant to incent certain types of
behavior, such as exploration, and he questioned if the amount
of investment that has offset the amount in tax credits is
known. For example, whether $8 billion is offset by $100
billion worth of investment.
CO-CHAIR TARR responded net operating losses (NOLs) are
currently earned at 35 percent of loss, which is approximately
one-third [of investment]. Net operating losses are normally a
function of collecting against an income tax, and companies can
use NOLs against a corporate income tax. She reviewed some of
the state's previous approaches to taxes and methods to incent
behavior, and restated the legislation's goal to determine the
best way to provide incentives that will result in desired
activities. She referred to previous testimony from DOR
estimating that roughly one-half of the previous incentives have
led to production; however, at this time policymakers lack
sufficient access to privileged information to know. Co-Chair
Tarr continued the sectional analysis [original punctuation
provided]:
Section 6. Amends AS 43.55.023(d) to remove the
ability for taxpayers to apply for a cash payment for
net operating loss credits issued under AS
43.55.023(b).
CO-CHAIR TARR noted the cheat sheet provided indicates
subsection (a) is a qualified capital expenditure (QCE), and (l)
is a well lease expenditure (WLE); Section 6 limits net
operating losses, but not does limit QCE and WLE. She continued
the sectional analysis [original punctuation provided]:
Section 7. Amends AS 43.55.024(j), the per barrel tax
credit, from zero to $8 to zero to $5 per barrel
depending on the price of oil. The most a taxpayer
could receive is a credit of $5 per barrel at prices
below $80.
2:11:25 PM
CO-CHAIR TARR pointed out Section 7 only addresses non-gross
value reduction (non-GVR) oil. The bill does not address gross
value reduction (GVR) oil as that was addressed in House Bill
247 [passed in the 29th Alaska State Legislature]. As discussed
in the earlier presentation, there remains the question as to
whether some oil was already going to be produced, even without
financial incentives. She directed attention to the bill on
page 14, beginning on line 24 and continuing to page 15, which
read [in part]:
(1) [$8 FOR EACH BARREL OF TAXABLE OIL IF THE AVERAGE
GROSS VALUE AT THE POINT OF PRODUCTION FOR THE MONTH
IS LESS THAN $80 A BARREL; (2) $7 FOR EACH BARREL OF
TAXABLE OIL IF THE AVERAGE GROSS VALUE AT THE POINT
OF PRODUCTION FOR THE MONTH IS GREATER THAN OR EQUAL
TO $80 A BARREL, BUT LESS THAN $90 A BARREL; (3) $6
FOR EACH BARREL OF TAXABLE OIL IF THE AVERAGE GROSS AT
THE POINT OF PRODUCTION FOR THE MONTH IS GREATER THAN
OR EQUAL TO $90 ...
CO-CHAIR TARR said the change means if prices go up, the state
would see some additional revenue, although at current prices,
the producers' breakeven price is about $46 per barrel. She
questioned whether the state wants to issue a credit when prices
are between $50 and $80 per barrel and the producers begin to
make a profit. She said this is a policy call that does not
fundamentally change Senate Bill 21.
2:15:56 PM
REPRESENTATIVE JOHNSON expressed her concern that Section 7
of the bill would affect the current increase in
production.
CO-CHAIR TARR advised the base rate in ACES was a 25 percent
credit, which was increased to 35 percent in Senate Bill 21,
along with the addition of the per barrel credit. A way to
simplify the system would be to adjust the base rate, which
would act like "a reverse progressivity." She has asked DOR to
provide modeling for each section of the bill at the hearing
scheduled for 2/17/17.
CO-CHAIR JOSEPHSON agreed production is up, but because of
the credit outlay, the state will not gain net revenue from
severance tax - setting aside royalty - until the price of
oil increases, thus the bill seeks to narrow the span of
the per barrel tax credit.
REPRESENTATIVE PARISH surmised "old oil" gets an $8 per barrel
credit, and "new oil" gets a $5 per barrel credit, which
provides a competitive advantage to legacy fields.
CO-CHAIR TARR restated the bill affects non-GVR oil, which is
old oil, and this provision does not apply to new oil. As
discussed in the earlier presentation, a net profits tax system
is generous with deductions and provides incentives for
producers; the policy question is whether additional incentives
are needed. However, she opined 35 percent of the base rate
would be unusually high.
2:20:25 PM
REPRESENTATIVE BIRCH referred to an earlier statement "setting
aside royalty." He pointed out a 3 percent increase in
production does generate additional royalty income to the state,
and questioned whether the primary focus of the bill was on non-
royalty provisions. Representative Birch opined royalties are
significant, and should not be set aside.
CO-CHAIR JOSEPHSON said the state owns its royalty share, and
the question is whether the oil otherwise would not be produced.
He said the debate has moved to a greater focus on royalty
because that is where the current money is, and restated the
royalty "is ours, sort of by definition." Co-Chair Josephson
posited the reduction from 35 percent to 15 percent in NOLs for
the producers, is argued by industry that in times of low price
the reduction discourages their continuing investment, because
the state is not there to help them in the current low-price
environment.
2:22:18 PM
CO-CHAIR TARR said it's possible. However, the producers always
benefit from deductions for transportation, capital expenditures
(CAPEX), and operating expenditures (OPEX), and the NOLs are
quite expensive for the state, as reflected in the bill's fiscal
note. She opined the production and revenue forecast is
confusing because the state not only has the liability of
cashable credits, but also lost revenue due to low prices.
Also, if prices go up, the state will still not benefit because
the carry-forward loss credits will reduce any additional income
from higher prices. The effective date of the bill is 1/1/18,
so the producers - even at $30 per barrel oil - due to all of
the deductions, will still have protection in the system for
years of low prices, but the state has none. In response to
Representative Birch on his question of royalty, she said in
Alaska, natural resources are common property and on public land
the state gets its royalty share; however, in other states where
oil and gas development happens on private land, the royalty
goes to the landowner and taxes go to the sovereign. In Alaska,
the royalty share and tax revenue can get confused.
CO-CHAIR JOSEPHSON asked how the bill would affect non-
producers; for example, currently if a company spent $10 billion
to develop a large field, the state would be responsible for
about one-third of the cost of development. However, under the
terms of HB 111, the state would be responsible for 15 percent,
and would provide much less cash assistance after 1/1/18.
CO-CHAIR TARR said the state seeks incentives for certain
behaviors and must decide what it can afford and what incentives
will be successful. A future section of the bill will explain
how the bill will limit the state's exposure, but not the amount
companies can earn. She continued the sectional analysis
[original punctuation provided]:
Section 8. Amends AS 43.55.028(a) to reflect the
section that removes the ability for taxpayers to
apply for a cash payment for net operating loss
credits. The only credits that may qualify for a cash
payment are the qualified capital expenditure credits
in AS 43.55.023(a) and the well lease expenditure
credits in AS 43.55.023(l). Under HB 247, for Cook
Inlet, the qualified capital expenditure and well
lease expenditure credits apply only to expenditures
incurred before January 1, 2017. Once those credits
phase out, the only credits that may qualify for cash
payments are capital expenditure and well lease
expenditure credits acquired by companies operating in
the area outside Cook Inlet and the North Slope known
as "Middle Earth.
2:26:12 PM
CO-CHAIR TARR said DOR will provide modeling based on the
premise that the state paid the statutory minimum on net
operating loss credits during past years of high and low prices.
Also, after QCE and WLE are phased out, Section 8 will only
apply to NOLs for companies operating in Middle Earth [the non-
North Slope, non-Cook Inlet areas of the state]. She continued
the sectional analysis [original punctuation provided]:
Section 9. Changes AS 43.55.028(e) to limit the
state's purchase of credits to $35 million per
company. Only companies with production of not more
than 15,000 barrels per day may apply for a cash
payment. Current law sets the purchase limit at $70
million and applies to companies with not more than
50,000 barrels per day.
CO-CHAIR TARR further explained Section 9 - also in the oil and
gas tax credit fund - limits the state's purchase of credits to
$35 million per company, reduced from $70 million. She reviewed
the history of the changes to the limit, and observed these cash
payments had the original intent to help non-producers, small
companies, and independents with exploration and drilling.
2:32:01 PM
REPRESENTATIVE BIRCH advised the committee a basic aspect of
finance is the time value of money. He questioned the value of
an incentive a company would have to wait 30 years to receive.
Invoking a tax credit to induce a behavior, and delaying payment
for a long time, when the tax credit is needed for current
obligations, is disingenuous at the least.
CO-CHAIR TARR acknowledged there has been extensive debate on
this topic. She agreed if a company has "a long time horizon"
for funding, the net present value of the tax credit is zero.
She restated the prospective nature of the legislation and
pointed out companies most impacted by this change will have an
opportunity to evaluate the changes. Also, the proposed
limitations may allow the state to pay its debts, creating more
stability, which also has value.
REPRESENTATIVE BIRCH said the legislature appropriated the money
to pay the tax credits and the governor vetoed payment.
Although the proposed legislation may be prospective, at this
time the state has a $1 billion liability, and businesses are
making significant decisions affecting jobs and opportunities
based on the state honoring its obligations.
CO-CHAIR TARR agreed the state is considered an unstable
business partner at this time; the state must address its
liability and also meet its goal of stability and durability of
its tax system at all prices.
2:37:28 PM
CO-CHAIR JOSEPHSON clarified the aforementioned legislative
appropriation was $430 million, not the entire allocation, and
the legislature chose not to override the governor's veto. Co-
Chair Josephson opined the governor was prepared to appropriate
$1 billion to the liability, and the reason for the veto was
that the legislature did not produce a fiscal plan.
REPRESENTATIVE JOHNSON appreciated the historical information
but urged the committee to focus on what is proposed. She asked
how many companies are producing not more than 15,000 barrels
per day and will be affected by Section 9.
CO-CHAIR TARR said currently the limit is 50,000 barrels per day
which qualified the three majors and Hilcorp; after the
reduction to 15,000, Caelus will be impacted.
CO-CHAIR JOSEPHSON added the statute does not require credits to
be cashable, but provides the option to the legislature through
its power of appropriation. He stated his personal concern
about the state's failure to pay the credits.
REPRESENTATIVE RAUSCHER observed companies on the North Slope
have been bought out over the past 10-30 years, and questioned
whether bankruptcies are due to state inaction, when what is
desired is to "help them help us." He asked if after a
bankruptcy or sale, the new buyers also acquire tax credits.
CO-CHAIR TARR responded it would depend upon whether the
purchasers used a bank for financing. If a bank lent money
based on the state's payment of tax credits, testimony from Bank
of America revealed borrowers will default without the payment
of the tax credits, and after default the assets and lease
become the property of the bank and would be sold. Otherwise,
without bank financing, the credits go to the next owner.
CO-CHAIR JOSEPHSON, in response to Representative Johnson, said
at least 12 companies in the exploration and development phase
are affected by the reduction in Section 9. He urged for
testimony from Caelus regarding the effects of the bill.
2:43:46 PM
REPRESENTATIVE RAUSCHER inquired as to additional testimony on
the bill.
CO-CHAIR TARR said the bill will be heard for two weeks. She
then clarified the aforementioned 12 companies are those
currently awaiting payment, and the change brought by Section 9
also affects Caelus. She also restated the limit is on cash
payments for NOLs. Co-Chair Tarr continued the sectional
analysis [original punctuation provided]:
Section 10. Adds a new section to AS 43.55.150 to
ensure that the gross value at the point of production
does not go below zero. The gross value is determined
by subtracting tariffs and transportation costs from
the West Coast sale price per barrel. The gross value
at the point of production is used in various
calculations throughout the production tax statute.
Section 11. Repeals AS 43.55.028(g)(3). The language
proposed to be repealed was added in HB 247. If an
applicant wanted to apply for the full $70 million in
credits in one year, they would receive 100 percent of
the first $35 million and 75 percent of the other $35
million. This was to give applicants an incentive to
wait and collect credits in a future year and lessen
the cash outlay by the state in a single year.
Section 12. (a) Sections 3 and 4 the five percent
minimum tax and resolution of the migrating tax issue
apply to credits applied to reduce a tax liability
for the tax year starting on or after January 1, 2018.
(b) The changes to the net operating loss credit in
section 5 apply to lease expenditures incurred on or
after January 1, 2018.
Section 13. If a person has applied for cash payment
of a net operating loss credit before January 1, 2018,
the department may purchase the credit.
Section 14. The change to the interest rate is
retroactive to January 1, 2017.
2:49:01 PM
REPRESENTATIVE JOHNSON questioned whether the legislation
creates a new tax rate effective retroactively to 1/1/17.
CO-CHAIR TARR explained the retroactive 1/1/17 effective rate
applies to the interest rate and not to the tax rate. For
example, if DOR finds delinquent taxes after an audit, it will
charge an interest rate for the delinquent amount during its
settlement negotiations. In further response to Representative
Johnson, she suggested the dates in question are related to the
provisions of House Bill 247, that are based on a calendar year,
and the one provision in the proposed legislation, that is based
on the fiscal year, and therefore must be reconciled.
CO-CHAIR JOSEPHSON surmised industry files [tax returns] in
spring, thus the timing should not create a problem for
industry.
CO-CHAIR TARR agreed the timing is challenging to explain and
gave an example: during calendar year 2016, taxes are due in
2017, but [filed] in fiscal year 2018 (FY 18). She continued
the sectional analysis [original punctuation provided]:
Section 15. The change to the interest rate and its
retroactivity is effective immediately.
Section 16. All other sections take effect January 1,
2018.
CO-CHAIR TARR directed attention to the fiscal note summary of
revenue impact on page 2, and the total revenue impact, total
budget impact, and total fiscal impact on page 4. She pointed
out various elements of the fiscal note.
2:57:44 PM
CO-CHAIR JOSEPHSON questioned whether the 35 percent NOL was
intended to parallel the 35 percent "progressive rate at the
highest price per barrel."
CO-CHAIR TARR said yes; however, the rate is not progressive but
is a flat 35 percent tax rate. In addition, she said, "It's not
really ever 35 percent because you have credits you can always
apply to it."
CO-CHAIR JOSEPHSON acknowledged the legislation is very
complicated and urged the committee to work with the co-chairs
on developing consensus; he stressed the state's cash obligation
to the industry is owed, but is untenable.
REPRESENTATIVE TALERICO anticipated many hearings of the bill
and testimony from all of the affected parties. He stated it is
very difficult for the committee to determine estimates of
capital expenditures as they involve drilling and
infrastructure, and encouraged additional forthcoming
information.
REPRESENTATIVE BIRCH directed attention to page 4 of the fiscal
note analysis that indicated a $45 million impact in FY 18,
increasing to a $300 million per year total fiscal impact in FY
26; he concluded the proposed legislation seeks to add $50
[million] to $300 million per year to state take.
CO-CHAIR JOSEPHSON agreed.
CO-CHAIR TARR cautioned the analysis by DOR is based on a five-
year forecast of production, and thus there will be many
changes. She noted the presentation on the history of oil and
gas tax policy was intended to help the committee understand
previous decisions and thereby avoid repeating mistakes.
[HB 111 was held over.]
3:02:48 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 3:02 p.m.
| 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 Supporting Document-Tax Credit History 2.13.17.pdf |
HRES 2/13/2017 1:00:00 PM |
HB 111 |
| HB111 Supporting Document - PowerPoint Sectional 2.13.17.pdf |
HRES 2/13/2017 1:00:00 PM |
HB 111 |