Legislature(2017 - 2018)BARNES 124
01/30/2017 01:00 PM House RESOURCES
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| Presentation(s): Tax Division Update, Department of Revenue | |
| Adjourn |
* first hearing in first committee of referral
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+ teleconferenced
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ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
January 30, 2017
1:01 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 Chris Tuck (alternate)
OTHER LEGISLATORS PRESENT
Representative Mike Chenault
COMMITTEE CALENDAR
PRESENTATION(S): TAX DIVISION UPDATE~ DEPARTMENT OF REVENUE
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
KEN ALPER, Director
Tax Division
Department of Revenue
Juneau, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation
entitled, "Alaska's Oil and Gas Taxation-Status Report," dated
1/30/17, and answered questions.
ACTION NARRATIVE
1:01:47 PM
CO-CHAIR GERAN TARR called the House Resources Standing
Committee meeting to order at 1:01 p.m. Representatives Tarr,
Birch, Drummond, Johnson, Parish, Talerico, Westlake, and
Josephson were present at the call to order. Representative
Rauscher arrived as the meeting was in progress. Also present
was Representative Chenault.
CO-CHAIR TARR made opening remarks.
^PRESENTATION(S): TAX DIVISION UPDATE, DEPARTMENT OF REVENUE
PRESENTATION(S): TAX DIVISION UPDATE, DEPARTMENT OF REVENUE
1:04:54 PM
CO-CHAIR TARR announced [that the only order of business would
be a presentation by the Tax Division of the Department of
Revenue.]
1:04:57 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
said DOR is responsible for collecting and administering most of
the taxes for the state. He advised that oil and gas issues are
complex and contentious and his presentation would provide
"facts and figures." Oil and gas taxation is a collection of
four major revenue items that fund most of Alaska's operations:
property tax on oil and gas infrastructure and facilities raises
approximately $0.1 billion per year, and approximately $0.4 of
that is shared with local governments; royalty [landowner share]
raised $1.2 billion in fiscal year 2016 (FY 16) and at least
one-quarter of that is deposited into the Alaska Permanent Fund;
production tax - which is a net profits tax - raised $0.2
billion in FY 16; corporate income tax is an apportionment share
tied to global earning and is reduced to a negative for FY 16.
Mr. Alper pointed out that in FY 12, the state collected a total
of $9.7 billion in oil and gas taxes and royalty revenue, and in
FY 16 the total was reduced to $1.5 billion (slide 3).
MR. ALPER returned to the topic of property tax, noting that
property tax statutes are relatively unchanged since the 1970s,
although property assessments, such as the Trans-Alaska Pipeline
System (TAPS), are often litigated. Royalties are set by
contract and the terms of the leases, and he described aspects
of state land ownership and subsurface minerals rights on the
North Slope and elsewhere (slide 4).
1:10:16 PM
REPRESENTATIVE TALERICO asked whether property tax assessments
on infrastructure have held a constant value, in spite of the
fluctuation in oil prices.
MR. ALPER said yes, and pointed out that the assessments may
vary, but the underlying statutes have not changed much in 40
years.
REPRESENTATIVE TALERICO understood that Alaska cannot sell its
subsurface mineral rights, but under the terms of the Alaska
Statehood Act [passed in the 85th U.S. Congress], the state has
the option of returning said rights to the federal government.
MR. ALPER agreed.
REPRESENTATIVE JOHNSON requested a comparison of Alaska's
corporate income tax to that collected by other states.
MR. ALPER offered to provide specifics, and added that Alaska's
corporate income tax rate statutes are similar to those of other
states.
REPRESENTATIVE BIRCH questioned whether Alaska's Clear and
Equitable Share (ACES) [passed in the 25th Alaska State
Legislature] would generate less revenue today than Senate Bill
21 [passed in the 28th Alaska State Legislature].
MR. ALPER said he would provide a complete answer later in the
presentation.
CO-CHAIR JOSEPHSON, referring to corporate income taxes, asked
whether Alaska is in the minority of states that do not tax S
corporations, limited liability companies (LLCs), or
partnerships.
1:13:58 PM
MR. ALPER responded that the aforementioned entities are taxed
through each state's personal income tax; it is hard to tax said
entities through a corporate income tax because the earnings are
not retained by the company, but are passed on to the owner's
individual income, and Alaska does not have an individual income
tax. He returned attention to royalties, and listed the factors
affecting royalties. In most states royalties go to a private
landowner, but as the owner of the resource, Alaska collects
royalty in kind - meaning in oil - or as money. He cautioned
that in the future, as oil not in the central North Slope is
developed, royalties will pay a lower rate that is proportionate
with the share of the federal royalty; for example, offshore
three to six miles, the state collects 27 percent (slide 5).
CO-CHAIR JOSEPHSON surmised that from production offshore beyond
six miles from the shoreline, the only benefits to the state
would be applicable property and equipment taxes, and jobs.
MR. ALPER stated that a large discovery offshore would reduce
the tariff on transportation through the pipeline, which would
benefit the state, but there is no specific revenue tied to
offshore oil development.
REPRESENTATIVE PARISH said he expects that the federal
government would negotiate royalty rates within the Arctic
National Wildlife Refuge (ANWR) and the National Petroleum
Reserve Alaska (NPRA). He inquired as to whether the federal
government could set the federal royalty rate at zero.
1:18:10 PM
MR. ALPER explained that the royalty set with the oil companies
is on a case-by-case basis, usually at 12.5 percent. Certain
statutory requirements are that a portion of the federal royalty
goes to the state where the asset is located; regarding offshore
oil development, he advised that there is pending congressional
legislation that may benefit Alaska and other states that have
offshore development off of their borders. In further response
to Representative Parish, he said in the Gulf of Mexico, beyond
six miles, producer states get a three-eighths share - 37.5
percent - and Alaska gets 27 percent [from three to six miles].
This is related to the state's connection to the outer
continental shelf (OCS), where there is no longer active
exploration underway.
MR. ALPER returned to the corporate income tax, which is an
apportionment formula based on a company's worldwide earnings
and Alaska's proportion of its income tied to sales, property,
and barrels of oil produced. The focus of the following
discussion will be directed to the production or severance tax,
where there have been recent changes; however, he cautioned that
often the numbers discussed are in the aggregate because
information related to a specific taxpayer is confidential
(slide 6). Mr. Alper identified the years between 1977 and 2005
as a stable period in the history of oil and gas taxes, during
which there was a one percent gross tax on Cook Inlet
production, and an additional gross tax based on the Economic
Limit Factor (ELF) [passed in the 12th Alaska State Legislature]
formula. He described the purpose and effects of ELF, as
modified, on state revenue; for example, by 2005 most oil fields
were paying less than one percent tax, and the legislature began
efforts to reform oil and gas taxes (slide 7).
1:23:19 PM
CO-CHAIR JOSEPHSON assumed that currently, the state would
collect more revenue from a 15 percent gross tax, but during a
period with oil prices at $130 per barrel, the state would
collect less from a 15 percent gross tax.
MR. ALPER explained that revenue from a net tax is less at low
oil prices and more at high prices. In 2006, when the Petroleum
Production Tax (PPT) [passed in the 24th Alaska State
Legislature] began to tax net profits, the weighted average ELF
tax on a barrel of oil produced on the North Slope was about 7
percent; now, most of the oil is taxed at the alternative
minimum tax affected by Senate Bill 21: 4 percent. However,
the ELF formula has not been modeled for the last ten years,
thus the actual ELF tax is difficult to determine. Mr. Alper
turned to the years between 2005 and 2017 - the volatile period
of oil and gas taxes - as evidenced by the fact that the state
has changed taxes six times over the last [eleven] years as
follows (slide 8):
• 2005, ELF aggregation by executive order
• 2006, PPT
• 2007, ACES
• 2010, Cook Inlet Recovery Act [passed in the 26th
Alaska State Legislature]
• 2013, Senate Bill 21
• 2016, House Bill 247 [passed in the 29th Alaska State
Legislature]
1:26:31 PM
REPRESENTATIVE BIRCH asked if any of the foregoing changes were
tax increases.
MR. ALPER answered that the [2005 aggregation] was an increase;
PPT was neutral; ACES was an increase; Cook Inlet Recovery Act
was a decrease; Senate Bill 21 was a tax cut, except at very low
prices it is a small increase; House Bill 247 was a reduction in
some benefits. In further response to Representative Birch, he
acknowledged that Senate Bill 21 was a tax cut; although Senate
Bill 21 has netted the state about $100 million, at the time of
the legislation, the price of oil was about $100 per barrel and
the fiscal notes described a [$500 million] to $700 million tax
cut.
MR. ALPER provided further details related to the executive
order by former Governor Frank Murkowski that aggregated Prudhoe
Bay satellite fields into a higher ELF multiplier (slide 9). In
2006, PPT was passed, and he provided details leading up to the
PPT legislation and the aftermath thereof (slide 10).
1:30:38 PM
REPRESENTATIVE PARISH asked for further details and costs
related to the legal challenge of former Governor Murkowski's
executive order that aggregated Prudhoe Bay fields for tax
purposes.
MR. ALPER said that the Department of Law represented the state
and he would provide information regarding the cost of the
litigation.
CO-CHAIR JOSEPHSON recalled that the tax credits provided by PPT
in 2006 were an outlay of $56 million.
MR. ALPER responded:
The key portion of the capital credit was not anything
we might have spent ... the capital credit was
embedded as a component of the PPT tax for the major
taxpayers, so if a, if a major producer might have,
let's call it a billion dollars in taxable profit,
they would then multiply it by the tax rate and then
from that, subtract their capital credit. It would
come off the top before they paid the tax, and the
great bulk of this capital credit was ... revenue
foregone, rather than any outlay of the state.
CO-CHAIR JOSEPHSON questioned whether 11 years ago the
commitment was under $100 million, and in the last fiscal year
it was over $700 million.
MR. ALPER said, "... yes, there was a ramping up of our
obligation for cash tax credits." He explained that after the
passage of the Cook Inlet Recovery Act the amount for Cook Inlet
grew, and the current year's obligation is estimated to be about
$700 million. However, after the actions taken by the governor
and the legislature, the state spent $498 million [for credits]
in FY 16. Mr. Alper directed attention to the ACES tax system,
and provided details on the ensuing debate that was focused on
progressivity and on the windfalls from high oil prices that
resulted in large budget surpluses, savings accounts, and a
large capital budget. The Act also created the tax credit
repurchase fund and the formula for annual appropriations (slide
11). In 2010, the Cook Inlet Recovery Act did not change the
ACES tax, but was targeted at Cook Inlet and expanded to other
areas, and created a tax credit to build a gas storage facility
in Kenai. He provided details surrounding the intent and the
effects of this legislation, noting that by FY 14, more than
one-half of repurchased credits were outside the North Slope
(slide 12).
1:37:56 PM
MR. ALPER continued to the current tax regime, Senate Bill 21,
legislation that intended to increase investment in new
production on the North Slope. He provided details, most
notably that most of the revenue impact is at high prices, which
will be explained later in the presentation (slide 13).
REPRESENTATIVE BIRCH asked for confirmation that if ACES had
been restored, "the delta there is about $100 million a year
today."
MR. ALPER agreed. He then directed attention to the most
recent tax change - by House Bill 247 - that represented the
governor's intent to slow the rate of the growth of the state's
obligations and liabilities. He provided details of the changes
in the final bill that "left the fundamental tax calculations
intact ... we weren't changing SB 21 per se ...." (slide 14).
CO-CHAIR JOSEPHSON referred to transparency and expressed his
understanding that only officials of the Department of Natural
Resources (DNR) perhaps the Department of Revenue (DOR) know
which North Slope fields earned credits for a certain company.
1:42:18 PM
MR. ALPER responded that for tax purposes, a company files one
tax return for all its operations on the North Slope, which
explains why tax credits impact a new company differently than
they impact an existing producer; House Bill 247 requires the
state to report the name of each company and the amount of cash
received for tax credits per year. Said reporting does not
include the use of the money, or which company has credits but
did not receive payment.
CO-CHAIR JOSEPHSON surmised that House Bill 247 reduced the
annual cap to approximately $60 million.
MR. ALPER said there was not previously a limit, and House Bill
247 established a $70 million limit in statute - and that is
further affected by the "hair cut" provision - thus a company
taking cash to the cap would receive $61.25 million per year.
In further response to Co-Chair Josephson's question about
whether cash credits are subject to appropriation, he remarked:
... there's no requirement to appropriate anything at
all. The [$]70 million company cap is obviously moot
in a year where there's only $30 million in the fund,
so that we haven't actually used that provision for
anything yet. Had it been in place five years ago it
would have been quite material.
MR. ALPER began to explain how oil has funded the state; since
FY 78, Alaska has received $141 billion in total petroleum
revenue, which he described as 27 percent of the oil's market
value and 35 percent of the oil's wellhead value. He provided
further details on past unrestricted general fund (UGF) revenue
and the FY 17 oil revenue forecast (slides 15 and 16). In
response to Co-Chair Tarr, he clarified that the oil revenue
that makes up over 90 percent of UGF is the non-Alaska Permanent
Fund portion of royalties; about 30 percent of royalties do not
go through the budget, but go directly into the Alaska Permanent
Fund. Mr. Alper directed attention to a graph that depicted
the state's share of the market value of petroleum revenue from
1978 through 2016 (slide 17). He pointed out that the revenue
was lower in the earlier years because there was less production
and a high tariff on TAPS; however, the wellhead value in the
earlier years is higher (slide 18). The wellhead value is known
in tax law as the gross value at the point of production (GVPP).
Slide 19 was an annotated version of slide 18 and illustrated
that beginning in 1978 revenue hovered around 32 percent, with
the exception of 1994, during which there was a large payment of
royalty settlement money to the Constitutional Budget Reserve
Fund (CBRF). As more wells were drilled, ELF rates for the
larger fields declined, thus revenue started to decline from
1998 to 2005; after the change to a net profits system - which
collects high revenues when prices are high - during the period
from 2007 to 2013 revenues averaged 41 percent. When oil prices
fell, from 2014 to 2016, revenue also fell to approximately 26
percent (slides 18 and 19).
1:50:21 PM
REPRESENTATIVE PARISH asked how much revenue was lost to the
state due to companies' business decisions "of drilling
additional wells to drive down the, the rate in a given field."
MR. ALPER was unsure; however, [the decline beginning in 1998]
was due to a natural occurrence in that more wells were being
drilled, which was changing the [ELF] multiplier, and there was
an emphasis on the Prudhoe Bay satellite fields that were
aggregated in 2005. He offered to research this question.
MR. ALPER turned to the present and discussed the meaning of
percent of value (POV). Currently, production of approximately
185 million total barrels at $50 per barrel is worth $9.25
billion on the market, and each 1 percent of total market value
is about $90 million to the state treasury; the wellhead value
is about $7.4 billion, and each 1 percent of wellhead value is
about $75 million. He further described the impacts of adding
tax, or reducing credits, to the value of taxable and royalty
barrels of oil, concluding that additional revenue of about $450
million reaches a revenue percentage of 32 (slide 20). During
the ACES tax regime, the state earned high revenue because oil
prices were high and costs were low; however, because prices
were high, the oil industry searched for and developed
challenging fields where the cost to produce oil costs $40 per
barrel. He directed attention to a graph that illustrated the
increase in lease expenditures for producing fields from 2007 to
2016. Noting the decrease of total cost in 2016, he explained
that companies deduct costs against taxable barrels, which
increases [taxable] total cost by 10-15 percent (slide 22). The
steps of Senate Bill 21 tax calculations for legacy oil were
illustrated on slide 23. Mr. Alper clarified that
transportation costs are about $10 per barrel, including the
TAPS tariff and transportation to a refinery, and production tax
value is also referred to as PTV or net profits before tax.
He observed, "You could get a sense that SB 21 was written
around higher prices; at any price below [$]90, that was
considered very low, so oil is receiving a credit at the maximum
level, $8 per barrel" (slide 23). Slide 24 illustrated Senate
Bill 21 tax calculation for a range of oil prices from $40 to
$140 per barrel, as per the DOR Revenue Sources Book (RSB)
Spring 2016. Transportation and lease expenditures are
constant, but as the PTV (net) goes higher, he estimated that
the "crossover [from the minimum tax to $7.12 calculated level]
is maybe [$]65, $68 a barrel." He stressed that in a net
profits tax, price impacts are magnified through the tax system,
whereas a gross tax has a more linear relationship of price to
tax.
1:59:54 PM
CO-CHAIR TARR compared the costs illustrated on slide 22 to
those of slide 24, and pointed out that under a net profit tax
system, transportation costs and lease expenditures are deducted
from the production tax; for example, at $40 per barrel, the PTV
is negative in value. She advised that in a low-price
environment under a net system, there are deductions that
protect the industry, but do not protect state.
MR. ALPER restated that the minimum tax is 4 percent of GVPP.
CO-CHAIR JOSEPHSON questioned whether at less than $60 per
barrel, the state's share is larger than that of the industry.
MR. ALPER, referring to information gleaned from industry tax
returns, said that the breakeven price of an average barrel of
oil produced on the North Slope last year was $45, and for the
current year is $41, due to cost containment measures taken by
the industry. In further response to Co-Chair Josephson, he
agreed that the industry is in an unfavorable position and is
suffering from low oil prices around the world.
CO-CHAIR JOSEPHSON remarked:
On the other hand, the minimum tax is, is not a
minimum tax because - depending on the facts of each
field - because of a number of features can that drive
the tax rate beneath the 4 percent floor. Is that
correct?
2:05:57 PM
MR. ALPER responded that new oil - gross value reduction
eligible oil - is not subject to the minimum tax, and can pay a
zero rate; in addition, credits can be used to bring tax
payments below the minimum, which led to debate related to
"hardening the floor, making it so that certain taxes can't be
used so as to protect the minimum tax for the state." He
stressed there are other taxes in addition to production tax -
such as royalty and corporate income tax - and production tax is
a severance tax to pay the state for removing a non-renewable
resource that cannot be replaced; in fact, there is thought that
a severance tax should be paid under any conditions, which is
the intent of the minimum tax.
CO-CHAIR TARR returned attention to slide 24, and stated that
changes to operating expenditures (OPEX} and capital
expenditures (CAPEX) such as layoffs and scaled-back drilling,
would lag behind price changes, albeit depressing PTV.
MR. ALPER agreed that as companies cut their costs and reduce
their breakeven price, the state benefits somewhat, except for
job losses. The information on slide 24 is complicated and he
summarized the important points as follows (slide 25):
• the price of oil fell by 50 percent
• the wellhead value declined by 54 percent
• the taxable net declined by 75 percent
• production taxes paid declined by 92 percent
• due to the impact of the variable per barrel credit - the
tax paid at $120 per barrel was $26.32 and the tax paid at
$60 was $2.03 per barrel - there was a reduction from $4
billion to $325 million per year in production taxes
2:10:14 PM
REPRESENTATIVE BIRCH questioned whether the state "bought into
this ... as far as the volatility goes ...."
MR. ALPER acknowledged that the state chose taxing on net, which
is known to be higher at high prices and lower at low prices.
He turned attention to the types of credits and provided a
history and the economics of the system of exploration, capital
expenditure, and carried forward annual loss credits (slide 27).
Not shown on slide 27 is the exception to the expired
exploration credits related to Middle Earth that will remain in
effect until 2022. In response to Co-Chair Tarr, he said Cook
Inlet is defined in statute as the Cook Inlet Sedimentary Basin,
water and land; the land north of latitude 68 degrees north is
considered the North Slope; everything else is Middle Earth.
Returning to credits, he clarified that carry forward annual
loss credits are generally known as net operating loss (NOL)
credits, and pay a company for a percentage of its losses that
are not tied to a specific project. He characterized the
aforementioned credit as "the main thing, when we look at our
future credit burden .... What we're going to be paying in the
future is this 35 percent North Slope NOL if anything big
happens ...." Returning to a previous question, he said
"stackability" is in effect when a company has both an NOL and a
capital, well, or exploration credit, and he gave an example.
2:17:37 PM
CO-CHAIR JOSEPHSON inquired as to whether a company in
production could have an NOL if the price of oil were $100 per
barrel, because the company would be making a profit.
MR. ALPER said the price of oil does not matter. If a company
is developing, and is not in production, its spending is
effectively a loss. In further response to Co-Chair Josephson,
Mr. Alper explained that an NOL affects producers and non-
producers differently. He remarked:
Conoco recently announced their Willow major find ...
[that is expected] to produce a hundred thousand
barrels of oil a day, [located] twenty or so miles
west of existing infrastructure. ... Conoco is also a
partner in Prudhoe Bay and Kuparuk, and the existing
producing fields on the North Slope. They will be
able to take that spend on a month-to-month basis and
subtract it from their profits from their producing
fields, and reduce their tax liability, more or less,
in real time. They will reap the benefits of a 35
percent write-off, from month to month. If say
Armstrong ... found a similarly sized field ... and
spent several billion dollars ... they have no
recourse other than a cashable tax credit system to
get paid back, to get any sort of short-term benefit
from the state on that. ... [This credit] creates some
form of equity in tax treatment between the producer
and the non-producer.
REPRESENTATIVE BIRCH inquired as to how and when the state will
pay the tax credits it has offered and has an obligation to pay.
2:21:23 PM
MR. ALPER responded that tax credits are used generally to
offset future taxes, which was the intent of the tax credits as
written; in fact, the tax credit certificates issued by the
state can be used for that purpose. The state also agreed to
buy them back at face value subject to available funds, which
was unique. He said that the credits submitted for purchase
will have funds appropriated as necessary; however, the statute
that created the tax credit fund gives a formula based on a
percentage of revenue. In the most recent budget the governor
used the statutory formula, reasoning that the credits do not
lose value, can be used to offset future taxes, and can be sold.
Last year the original version of House Bill 247, as part of the
governor's fiscal package, had a fiscal note to pay all of the
tax credits from CBRF. The governor was expecting the bill and
other revenue measures to pass. The measures did not pass, and
the fiscal note was not funded either, which left the tax credit
balance as an obligation. As to the question of when the tax
credits will be paid, Mr. Alper opined the legislature and the
governor will address that as soon as the underlying fiscal
problem is resolved.
REPRESENTATIVE WESTLAKE, as an aside, suggested latitude 68
degrees north includes offshore.
REPRESENTATIVE PARISH asked whether the state pays credits
immediately rather than, for example, in the instance where a
customer buys $100 worth of goods, and receives a store coupon
worth $25 off their future purchase.
MR. ALPER said yes. In further response to Representative
Parish, he recalled that this practice was established because
the state had a policy to diversify the North Slope and
encourage new companies to invest. Also, at that time, Alaska
could afford the credit obligations, but as revenue has reduced,
the credit obligations have not.
2:26:46 PM
REPRESENTATIVE PARISH asked what proportion of NOL credits have
gone to small producers.
MR. ALPER estimated that about two-thirds of the NOL credits the
state has issued have gone to the major producers, but not in
cash; major producers must use the credits to offset or reduce
their tax payments. About one-third has been in checks written
to smaller companies that produce less than 50,000 barrels per
day or are not producing at all.
MR. ALPER, in response to Representative Rauscher, said the
split of new [companies] versus old was relatively stable until
affected by the recent economy and activities in Cook Inlet. In
further response to Representative Rauscher, he elaborated that
the last couple of years have been "an aberration."
MR. ALPER returned to the presentation and described small
producer credits, per-taxable barrel credits, and credits
against corporate income taxes. He stressed that to qualify for
cash, a company must produce less than 50,000 barrels per day;
companies larger than that must "carry forward" to use against
future year's taxes (slide 28). In response to Co-Chair Tarr,
he clarified that the cash credits are considered a repurchase,
not a refund. Mr. Alper returned to the history of tax credits
and said that from FY 2007 through the end of 2016, about $8
billion in state credit money has been spent or foregone, of
which $4.4 billion are credits against tax liability and $2.3
billion have been paid to repurchase credits on the North Slope.
Outside the North Slope, there are $0.1 billion credits against
tax liability and $1.2 billion have been paid to repurchase
credits (slide 29). Slides 30, 31, and 32 provided further
details on the distribution of the nearly $3.5 billion in state
repurchased credits through FY 16, described by location and
project. Slide 30 was corrected to read: $0.9 billion and $0.3
billion.
2:39:00 PM
CO-CHAIR JOSEPHSON expressed his concern that the state made a
$1.5 billion investment for the equivalent of five months of oil
production.
MR. ALPER stated this is incremental production from generally
smaller and more challenged fields. An issue facing the credit
system is that if a larger project is developed using the tax
credit system, both volumes and liabilities will increase
dramatically. He provided a production tax graph that
illustrated the historical and forecast costs of statewide tax
credits and production tax by three colored bars for each year:
production taxes without any credits are shown on the left as a
pink bar; production taxes paid after credits are used to offset
tax liability are shown in the middle bar; the net effect after
cash credits are paid is shown on the right as a red bar. At
the outset and through the early years, tax credits truly were a
reinvestment of surplus revenue to build for the future (slide
33). In regard to FY 15, FY 16, and FY 17, he remarked:
If the credits were being paid at the rate at which
they are being earned, we would actually be spending
substantially more on tax credits then we would be
receiving in the production taxes that support them.
MR. ALPER provided a similar graph that illustrated statewide
tax credits and all unrestricted petroleum revenue except for
the "permanent fund piece" (slide 34). In regard to FY 17, he
said the forecast assumes $700 million in credits is paid, as
opposed to the actual amount of $30 million that was spent, and
that the blue line on the graph is also out of date. Regarding
forthcoming legislation with the intent to "harden the floor" he
cautioned that the issue is this: A company with a carry
forward loss could reduce its payments below the minimum tax and
possibly to zero. In response to Co-Chair Tarr, he confirmed
that the minimum tax is 4 percent for legacy oil and less for
new oil.
2:44:11 PM
REPRESENTATIVE TALERICO recalled previous testimony that
companies have cut their expenses, impacting net operating
losses and reducing the cost to produce a barrel of oil. He
asked whether assumptions related to factors impacting net
operating losses are "figured in."
2:44:35 PM
MR. ALPER advised that slides 33 and 34 have not been updated;
however, in the RSB and other DOR official forecasts, the
assumption of companies' profits and losses, and the impact to
future tax revenue, has been fully incorporated. He stressed
that slides 33 and 34 illustrate that when the state had more
revenue, the credits "meant something very different than they
do in the current context." He offered to provide updated
slides to the committee. Mr. Alper directed attention to the
aforementioned credit appropriation formula AS 43.55.028(b) and
(c), and described the use of and possible uses of the formula
(slide 35). He added that in FY 18, DOR anticipates about $490
million in production tax; 15 percent of $490 million is $74
million, which was in the governor's budget proposal, and the
same formula was used to determine the related governor's veto
of $30 million in FY 17. Continuing details of tax credit
history were presented on slide 36.
2:50:04 PM
CO-CHAIR JOSEPHSON suggested that with $3 billion to $3.5
billion in CBRF, even with a cut to the budget of $0.5 billion,
the state [budget] would almost drain CBRF, thus funding the
aforementioned without a fiscal plan is "absurd."
MR. ALPER recalled that one year ago it was expected that the
CBRF balance would be $6 billion or $7 billion, and
appropriating $1 billion to clear a major state liability made
more sense. He cautioned that CBRF money is needed for a crisis
such as a geological disaster. Returning to the presentation,
he provided further details on tax credit certificates that have
been paid, transferred, are ineligible, and are awaiting
repurchase (slide 37).
REPRESENTATIVE TALERICO asked whether the aforementioned credits
were all acquired in FY 17, or if some were from previous fiscal
years.
MR. ALPER responded that most were expenditures during the
calendar year 2015; as NOL credits require an annual profit and
loss statement, applications are submitted at the end of March
and that is the start of a 120-day processing time. Therefore,
NOL credits are generally issued in July and August. In
further response to Representative Talerico, he offered to
provide additional information on the state's current liability
on an annual basis, and directed attention to a graph from the
RSB Fall 2016, which illustrated how the credit liability will
grow over the next few years, based on certain assumptions
(slide 38).
2:56:41 PM
REPRESENTATIVE BIRCH opined that postponing the payment of tax
credits for ten years will not provide the benefits that were
intended.
MR. ALPER agreed, and restated that the state is only obligated
to pay under the credit appropriation statutory formula and that
tax credits were designed to offset future taxes. He continued
with details on the options for companies holding credit
certificates (slide 39). He further explained that the option
to sell certificates to a company with a tax liability -
generally one of the three major producers - is rarely taken
because the state buys certificates for 100 percent [of their
value] and a third-party buyer would negotiate a purchase at a
discount; however, under present circumstances, "we're seeing
credits change hands." Furthermore, there are restrictions on
how many credits a company can buy to the amount it can offset
from the taxes that it owes; in addition, NOL credits can only
offset 20 percent per year. Conversely, exploration credits do
not have that restriction thus a company can offset all of its
taxes with exploration credits, and he anticipated that
exploration credits will be found in the secondary market.
MR. ALPER turned to the major provisions and regional impacts of
House Bill 247, the tax credit reform bill, and provided details
(slide 40). He noted that a qualified capital expenditure is
known as QCE and a well lease expenditure is known as WLE.
Regarding a statewide impact, the bill changed the interest rate
charged on delinquent production taxes, carved out the
production tax, and increased the interest rate for three years
and then dropped it to zero which, he opined, will cause tax
disputes in future years.
3:03:02 PM
CO-CHAIR TARR recalled that the intent of the surety bond is to
protect local Alaska businesses if companies go out of business
and local vendors are not paid.
CO-CHAIR JOSEPHSON questioned whether the intent of the increase
in interest rates is to ensure audits are completed in a timely
manner.
MR. ALPER said the provision is related to audits and the
statute of limitations. He acknowledged, "It's unfortunate that
we have been pushing the six-year limit and especially when
interest rates were higher. ... Eleven percent compounded for
six years kind of doubles your cost, and companies were finding
that quite onerous, and deservedly so." The provision also
eliminated compound interest, and then after three years
interest goes to zero. He cautioned that the problem with this
part of the provision is that if an audit assessment ends up in
litigation for five more years after the audit, no interest will
accrue, and thus there is no incentive for a company to ever
settle a tax issue.
3:05:18 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 3:05 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| DOR Present Oil Tax Status Report HRES 1-30-17 final ka.pdf |
HRES 1/30/2017 1:00:00 PM |
Status Update on Oil and Gas Tax Regime in Alaska |