Legislature(2017 - 2018)BARNES 124
03/06/2017 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB133 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | HB 133 | TELECONFERENCED | |
| += | HB 111 | TELECONFERENCED | |
HB 133-OIL & GAS: TAXES; CREDITS; GROSS VALUE
1:03:41 PM
CO-CHAIR TARR announced that the only order of business would be
HOUSE BILL NO. 133, "An Act relating to the oil and gas
production tax, tax payments, and tax credits; relating to
adjustments to the gross value at the point of production; and
providing for an effective date."
1:03:55 PM
REPRESENTATIVE LES GARA, Alaska State Legislature, speaking as
the prime sponsor of HB 133, provided a PowerPoint presentation
entitled, "And Fairness to All Fair Production Tax To Alaskans
And Industry, HB 133." Representative Gara informed the
committee HB 133 is the legislature's best attempt to ensure
Alaska receives a fair share for its oil in order to provide
stable funding for schools, oil tax credits, and the University
of Alaska, and to move society forward. Further, HB 133 intends
to provide balance to the state's fiscal plan so that everybody
contributes, without a focus just on those who have little and
not on those who do well; the bill also follows the provision in
the state constitution that directs state government to develop
the state's resources for the maximum benefit of Alaskans, thus
HB 133 also provides balance between meeting the aforementioned
constitutional mandate and treating industry fairly [slide 2].
REPRESENTATIVE GARA said, "We have fields in the state that we
are supposed to be living off, in terms of raising revenue,"
however, under current law, the aforementioned fields are
allowed to pay a production tax of zero, and many other fields
will pay zero for their first seven years. In addition, bigger,
higher taxpaying fields, until the price of oil reaches about
$74 per barrel, pay a 4 percent tax. That, he opined, in
combination with generous tax credits, is a "double whammy" for
the state: very low production taxes, and tax credits that will
eat up all of the production taxes this year and in future years
will yield very little net production tax.
REPRESENTATIVE GARA explained in 2003, Gross Value Reduction
(GVR) fields were unitized, and GVR fields include "most post-
2003 fields, and they are all future fields." For example, if
the Arctic National Wildlife Refuge (ANWR) were to open [to oil
production], fields there would pay GVR tax, thus a field of any
size in ANWR would pay zero production tax - [as long as oil
price is below] $70 per barrel oil - for seven years, which
could be some of the fields' most productive years. When oil
price reaches $90 per barrel, the state would receive one of the
lowest profits taxes in the world at 12.2 percent [slide 3].
There are three factors that qualify an oilfield for the GVR tax
provision; one factor is to accommodate fields at Point Thomson,
and he provided a short history of the status of Point Thomson
production. Point Thomson's primary owner is ExxonMobil
Corporation, which would benefit from "this zero percent GVR tax
for their first seven years as long as oil remains below $70 a
barrel." [The three ways to obtain GVR tax reduction for post-
2002 fields were shown on slide 4.]
1:07:58 PM
REPRESENTATIVE GARA said there are parts of Senate Bill 21
[passed in the Twenty-Eighth Alaska State Legislature] and parts
of Alaska's Clear Equitable Share (ACES) [passed in the Twenty-
Fifth Alaska State Legislature] that make sense, and he urged
the legislature to learn from the past and develop an oil tax
bill that makes sense for everyone. Currently, Alaska assesses
a zero percent tax until oil reaches $15 a barrel, and a 1
percent tax at an oil price just above $15 per barrel, rising to
4 percent between $25 per barrel and $74 per barrel. In North
Dakota, at $10 per barrel oil, the tax is 10 percent gross, and
in Louisiana it is 12.5 percent gross. He cautioned against
comparing Alaska's revenue with North Dakota and Louisiana -
Alaska should instead compare revenue with big basins around the
world - although other states raise substantially more revenue
than does Alaska, up to $74 per barrel [slide 5].
REPRESENTATIVE GARA advised in the coming fiscal year, Alaska
will not take in $6 billion to $7 billion in production taxes
and royalty as in the past, but will instead garner
approximately $225 million in production taxes; after paying out
tax credits to companies, the state will actually be $25 million
in the red. By fiscal years 2019 (FY 19) and FY 20, after Cook
Inlet tax credit changes have taken place, even though the state
will take in, in theory, around $250 million in production
taxes, it will give back approximately 60-70 percent of that to
the industry. So, the net earned by the state will be about
$100 million in FY 19 and $150 million in FY 20. He opined that
is far short of what Alaska should be generating, especially as
[oil] prices get higher [slides 6 and 7].
1:11:14 PM
REPRESENTATIVE JOHNSON stated the materials presented seem to
indicate that the oil tax credits appear to be working, and that
the state's production is up for the first time in 14 years.
She suggested a comparison between Alaska and North Dakota was
relevant and said, "I believe Exxon said they were going to be
looking to $40 a barrel oil, for production ... and that
includes some of the large basin areas ...." Representative
Johnson observed this tax is only a portion of the equation.
REPRESENTATIVE GARA pointed out that under the old ACES system,
the state had a very high tax and paid out very generous
credits; under current law, the state has a low tax and pays out
generous credits. He said the fields with current activity were
moving forward under ACES; for example, Eni, Armstrong, and
Repsol came to Alaska under ACES and before companies were
offered tax breaks. Representative Gara remarked:
And [Repsol] came up under ACES saying, "Alaska has
great geology, it's a stable place to do business,
we're going to invest three-quarters of a billion
dollars, and we're going to move forward with those
fields that, that are economic." And we have seen
some of those fields announced, but I don't think that
there's a field - if there is, there's maybe one - I
don't think there's a field that wasn't moving forward
before Senate Bill 21. And our goal is to increase
oil production, though, the forecasts are that it's
going to continue to decrease over the next 15 years
unless there is a major find, and we're hoping for
major finds.
REPRESENTATIVE JOHNSON asked what part of oil production will
continue to decrease.
REPRESENTATIVE GARA answered that according to the Department of
Revenue (DOR) and the Department of Natural Resources (DNR), oil
production is forecast to decrease almost every year through the
next 20 years, down to less than 300,000 barrels per day.
REPRESENTATIVE JOHNSON said, "But that's not what ... we're
currently experiencing."
REPRESENTATIVE GARA expressed his understanding that DNR's model
forecasts one year where oil production isn't going down, but
then it continues to go down, which is similar to all of the
forecasts the state has had for the last 10 years.
1:14:11 PM
REPRESENTATIVE BIRCH asked whether the materials presented
incorporate the royalty share; for example, in the event
production does go down to 300,000 barrels per day, if there is
a one-sixth royalty share, 50,000 of the aforementioned barrels
are state-owned. He further asked whether any of the state
asset [royalty] - that is made possible as a result of this
production - is represented in today's presentation.
REPRESENTATIVE GARA responded no, today's presentation is about
production taxes. He acknowledged that the state receives 12.5
percent royalty on some fields, and receives approximately 16
percent royalty on other fields. He said he would address
royalty briefly later in the presentation, but currently the
discussion is focused on production taxes levied under the
Economic Limit Factor (ELF) formula [passed in the Tenth Alaska
State Legislature, and modified in 2005], the Petroleum
Production Tax (PPT) [passed in the Twenty-Fourth Alaska State
Legislature], ACES, and now Senate Bill 21.
REPRESENTATIVE BIRCH said at some point the state needs to
"account for that production," and as a one-sixth or a one-
eighth owner of the oil that is produced, the committee needs to
recognize and understand that [royalty] is a key component in
Alaska's revenue picture. He stressed anything the state can do
to increase throughput or production is a good thing.
Representative Birch said he welcomed discussion on the [tax]
credits, however, he urged the legislature to maintain its focus
on what is needed to do to increase production and invite
additional exploration and development.
REPRESENTATIVE GARA turned attention to slide 8 that depicted
the state's current effective tax rates on net value. He
explained bigger "Prudhoe Bay-type" fields are called non-GVR
fields. According to DOR, the state has a "greater of" system:
when the profits tax, under Senate Bill 21, is greater than the
4 percent minimum gross tax, the profits tax kicks in, and DOR
projected around $73 or $74 per barrel, the state will generate
more money on the profits tax version of current law than from
the gross minimum. Slide 5 showed that the state assesses a 4
percent tax on the Prudhoe Bay-type fields until $73 or $74 per
barrel. Even at $80 per barrel for Prudhoe Bay-type fields,
under current law there is a minimal 13.1 percent tax, and an
oil price much over $80 per barrel is not forecast for the next
10 years; furthermore, 13.1 percent production tax is reported
to be in the lower end of what is charged around the world.
Representative Gara continued as follows:
If you look at the GVR fields, the ones with the lower
tax rate, they, for the first seven years, if prices
are below $70, [would] not pay a production tax. Were
prices $80 a barrel, their production tax is about 40
percent lower than the non-GVR fields. So, the newer
fields - the ANWRs, the fields you hear ... talked
about - they pay about a 40 percent lower tax rate for
their first seven years, or if there are three years
of $70 prices then for three years. But, those are
low tax rates. ... I don't think that we can move
this state forward at a zero percent production tax on
GVR fields, and a 4 percent tax on non-GVR fields, for
prices that go up to the $70 range.
1:18:22 PM
REPRESENTATIVE GARA said DOR estimates the cost for producing a
barrel of oil on the North Slope, is about $40 [slides 9 and
10]. He explained that the "4 percent oil tax problem" occurs
because up until about $73 per barrel, there is a tax rate of 4
percent. Proposed HB 133 recognizes that an average field on
the North Slope is profitable at approximately $41 per barrel,
therefore, he suggested not raising the 4 percent tax to 5
percent until $50 per barrel, and then at every $8 increment,
raise it by 1 percent. The analysis from DOR [on HB 133] is
that the state share [would be] 5 percent at $50, 6 percent at
$58, and 7 percent at $66 per barrel, which does not approach
the North Dakota or Louisiana tax rates. The aforementioned
price-sensitive and profit-sensitive increases would still leave
the industry with a larger share in revenue than the state. He
reiterated this component of HB 133 provides a price- and
profit-sensitive gross tax that increases modestly as prices go
up [slide 11].
REPRESENTATIVE TALERICO asked whether Representative Gara had
information on royalty shares or municipal property tax rates in
North Dakota or Louisiana.
REPRESENTATIVE GARA indicated Representative Talerico's question
would be answered later in the presentation; he recalled
previous testimony before the committee that private royalty
assessed where oil is being produced on private land is much
higher than Alaska's royalty, as well as [the cost of] leasing
acreage.
REPRESENTATIVE TALERICO asked whether there is state take in
"those areas."
REPRESENTATIVE GARA answered states do not get royalty if
production is not on state land; the royalty is paid to the
owner of the land.
REPRESENTATIVE TALERICO restated his request for information on
municipal taxes.
REPRESENTATIVE GARA responded that every state is different; for
example, North Dakota has a severance tax, and another [unnamed]
tax, both of which add up to 10 percent of the gross. Experts
may be able to offer information on what is called "government
take," although that should be called "government take plus
private take," because in many other states royalty goes to a
private landowner.
CO-CHAIR TARR noted that the House Resources Standing Committee
refers to "non-producer share" to reflect [taxes or royalty an
oil producer pays to governments, or to a private landowner, or
both].
REPRESENTATIVE JOHNSON returned attention to slide 9, and asked
what is included in the average break-even point of $40.21.
REPRESENTATIVE GARA said the Fall 2016 Revenue Sources Book
(RSB), DOR, indicates $40.21 includes the cost of transportation
and the cost of production. In further response to
Representative Johnson, he explained that the cost of
development is $40.21, before taxes, and deferred to DOR for
confirmation.
CO-CHAIR TARR said yes, and added that lease expenditure are
estimated at $30.88 [slide 10].
1:24:13 PM
CO-CHAIR JOSEPHSON shared others' concerns about "4 percent up
to $74." However, as indicated on slide 11, HB 133 would
provide 10 percent gross at $90 per barrel, and he pointed out
that the state receives a higher percentage under Senate Bill 21
at $90 per barrel.
REPRESENTATIVE GARA advised that by $90 per barrel, the current
law "shifts over" to a profits tax, and he remarked:
Is a 10 percent on the gross bigger than 14 percent
profits? Probably, but ... it's field-sensitive -
there might be a very profitable field that is at a 20
percent tax rate at $90 per barrel. So, ... our bill
does the same thing that current law does, which is
when the profits tax is bigger than the gross tax, the
profits tax kicks in, so were the profits tax to be
larger than 10 percent on the gross, the profits tax
would kick in. This would not stop that from
happening.
REPRESENTATIVE BIRCH returned attention to slide 10 - second
line from the bottom - that indicated the "North Slope Credits
applied against [total] tax liability," totaled $225 million.
He asked:
Are not those credits an expenditure that was incurred
in the production of the revenue that's realized in
the line above, in other words, the gross revenue? ...
It seems to me like that's a part of the cost of doing
business, the credits basically are a representation
of the expenditure that was made necessary for the
exploration, development, and realization of the
revenues that are derived out of that field. Are they
not?
REPRESENTATIVE GARA responded, "You know, the tax is on top, and
then you get the credits back." He agreed with Representative
Birch's point.
REPRESENTATIVE BIRCH said the point is that the credits could
also be realized as an expense against doing business. For
example, certain costs are incurred in the daily operation and
the startup of a new business. He expressed his understanding
that the credits relate to an expense that was actually incurred
in the production and realization of the oil asset flowing
through the Trans-Alaska Pipeline System (TAPS).
REPRESENTATIVE GARA further agreed that Representative Birch was
accurate as to what [slide 10] does not show, [which are] the
additional credits the state pays and gives to companies that
are not producers.
REPRESENTATIVE JOHNSON pointed out that the estimates for
transportation costs and lease expenditures are not the same on
slides 8 and 10.
REPRESENTATIVE GARA acknowledged there is about a $2 difference,
and deferred to Ken Alper, Director, Tax Division, DOR, for an
explanation.
[There followed a brief discussion on the aforementioned
discrepancy.]
1:29:05 PM
CO-CHAIR JOSEPHSON commented that [an average break-even point
for oil producers] of $40-$41 was provided by the Alaska Oil and
Gas Association in January [2017]. For the purpose of
explaining the bill, he opined, [$40.21] works as well as
anything, because the amount is not an audit-specific number.
REPRESENTATIVE JOHNSON stressed it is important to have accurate
facts; in fact, DOR has said that sometimes the break-even point
is as high as $46.
REPRESENTATIVE GARA observed that a break-even point changes
from field to field; for example, in Prudhoe Bay the break-even
point is probably a lot lower than it would be for Nuna, as each
field is different in size, age, and infrastructure. The break-
even point [on slide 9] is DOR's best assessment of the average
costs for a North Slope field over the life of the field.
REPRESENTATIVE JOHNSON agreed that the discussion was "the
average" and expressed her hope "that we weren't picking
individual fields ...." She noted various estimates from DOR
that were included in the presentation, and urged DOR to explain
why there is a discrepancy.
REPRESENTATIVE GARA said, "The basic point of HB 133 is to not
start the progressive gross minimum tax until above the point
where a field is profitable on the North Slope." Royalty relief
will be addressed later in the presentation; in fact, there
cannot be an exact tax that is perfect for every single field,
which is why adjustments through royalty relief are necessary.
The bill doesn't raise the 4 percent minimum until $50 per
barrel - above where the average field on the North Slope is
profitable - and the bill slowly increases the tax rate to 6
[percent to 10 percent], in order to recognize company
profitability and the impact that price plays on company
profitability.
REPRESENTATIVE GARA presented slide 12 that was a comparison of
the tax rate the state would levy as a minimum tax under HB 133,
with the tax rates of North Dakota and Louisiana. He
acknowledged North Dakota and Louisiana are not the perfect
states to compare to Alaska, and there are other states with
lower tax rates; however, Alaska is really not competing with
shale oil states, but with jurisdictions around the world that
have big traditional pools of oil.
REPRESENTATIVE JOHNSON asked why Alaska isn't competing with
shale oil states.
REPRESENTATIVE GARA answered that some companies try to produce
both, but shale oil is produced by a different technology that
involves drilling well after well, because some wells only last
two years. He has heard from tax experts that Alaska is
actually competing with jurisdictions that have pools of oil
similar to those found on the North Slope.
1:33:43 PM
REPRESENTATIVE JOHNSON reported that ExxonMobil Corporation, one
of Alaska's major producers, stated this morning it is looking
to develop the production of shale oil at $40 per barrel, which
sounded to her like direct competition [with Alaska].
REPRESENTATIVE GARA responded, "... Exxon is okay, I guess, with
the North Dakota tax rate, which is much higher than what we
have, if we're competing with North Dakota." He pointed out HB
133 is for the committee to assess, and if the committee
believes the state is competing with North Dakota, Louisiana, or
Norway, Alaska has a much lower tax rate. In the end, the
legislature is supposed to determine a tax rate it believes
achieves the maximum benefit to the public, as the constitution
requires, and which, he stated, is a combination of [obtaining
maximum] oil revenue for the oil the state owns, and also
ensuring there is production.
REPRESENTATIVE GARA directed attention to slide 13 and recalled
the longest and much criticized tax regime in Alaska was ELF.
Under ELF until 2005, the gross tax rate on Prudhoe Bay was 13
percent, and on Alpine and Northstar [oilfield units] it was
approximately 10 percent; these fields represent the majority of
the state's production. Under ELF - criticized as being too
generous to industry - the tax rate on the aforementioned fields
was double and triple that of current law. In fairness, under
ELF, "a number of fields paid nothing in terms of production
taxes [such as] smaller fields, [and] older fields. But Prudhoe
Bay, [and] the places we had that got the majority of our
production from under ELF, [oil companies] paid a much higher
gross tax than [they] do right now."
REPRESENTATIVE GARA continued to slide 14, and remarked:
So, the reality is that producers, they will take home
what they get after they pay everybody else, right?
And, in Alaska that's largely the state. In other
states, that's the state and private landowners.
While our normal royalty in Alaska is about 12.5
percent, in Texas though, according to Mr. Ruggiero,
it's now up to 20 to 30 percent. The Competitive ...
the Competitiveness Review Board, the report that we
got in 2015, back then the average Texas royalties
were 12.5 to 30 percent depending on the landowner.
Mr. Ruggiero says they're now 20 to 30 percent
according to the landowner in Texas. California [is]
16 to 25 percent, North Dakota [is] up to 25 percent,
[and] Oklahoma [is] up to 20 percent. The royalty
share and also the land lease payments in those states
tend to be much higher than they are in Alaska.
REPRESENTATIVE BIRCH related his understanding from the
commissioner of DNR that "Most of the leases that are going out
now are one-sixth of royalty share, or one-sixth, or sixteen and
two-thirds, whatever one-sixth works out to." He recalled some
of the legacy fields, the older ones, are one-eighth, which
would be 12.5 percent.
REPRESENTATIVE GARA said there are a number of one-sixth fields
now, however, Prudhoe Bay and Kuparuk are 12.5 percent fields.
The general view of DNR, he opined, is that on the more
promising fields, higher royalty is part of the contract. He
explained:
Oddly enough, under current law, you basically lose
the benefit of the higher, higher royalty because
there's a provision in the current law that says "Even
for those more generously profitable fields that you
have a 16 percent royalty on, we just give you the
money back in a lower production tax rate." So, it's
a wash right now under current law.
1:38:28 PM
REPRESENTATIVE GARA further explained under any tax system, a
particular field may not have the right tax and therefore is not
profitable. Royalty relief is a repair mechanism to ensure that
the overall taxes charged by the state - production taxes and
royalty - are not too high. If a company can prove a field is
not economic under the current royalty system, most of the
royalty can be waived. Or DNR can issue royalty orders which
specify that at low prices, most of the royalty will be waived,
in order to make the field economic. For example, royalty
relief applications from Oooguruk, [Nikaitchuq], and Nuna have
all been granted [slide 15]. Furthermore, royalty for new
fields can be reduced to 5 percent to make a new field economic,
and if costs to a producer change, including a change in taxes,
royalty on a producing field can be reduced to 3 percent. Thus,
he said, the state would receive one-fifth of the 16 percent
royalty [the state is due] if DNR determines that royalty relief
is necessary to keep a field economic [slide 16]. Royalty
relief statute is AS 38.05.180 [slide 17]. He reiterated that
royalty relief was granted to Nuna in 2014, and to Oooguruk and
[Nikaitchuq] [slides 18 and 19].
REPRESENTATIVE GARA informed the committee ConocoPhillips is the
only oil company that reports its Alaska profits, as it is
required to do so by the Securities Exchange Commission (SEC).
As an aside, he said BP also lists Alaska profits, but one year
included the cost of the Deepwater Horizon [4/20/10 oil well
explosion and] spill [as a loss], therefore, he questions BP's
veracity. Returning to ConocoPhillips, he said in 2016 Alaska
was one of the highest generating regions in the world for
ConocoPhillips, generating $116 million in profits for the
fourth quarter, although the company lost money overall.
Representative Gara attributed Alaska profits for ConocoPhillips
to Alaska's larger pools of oil, and ConocoPhillips' interest in
Prudhoe Bay, Alpine, and some of the more profitable fields
[slide 20]. In past years of higher oil prices, ConocoPhillips'
profits in Alaska were approximately $2 billion on an annual
basis [slides 21 and 22]. Slide 23 illustrated that by FY 19,
if HB 133 is adopted, it would generate about $200 million in
additional revenue; however, the amount of additional revenue
from any new legislation will depend on the price of oil, and
the oil price is projected to be about $60 per barrel by FY 19,
and $78 per barrel by FY 24 [slide 24].
1:43:07 PM
REPRESENTATIVE BIRCH turned to the larger issue of tax credits
and inviting new development, and recalled the initiative that
encourages smaller investors has been fairly successful. He
asked whether Representative Gara agreed that the credit program
was generally successful.
REPRESENTATIVE GARA remarked:
When you have a tax system that generates a large
amount of money, you can afford to be an investor in
new oilfields with very generous credits. When you
have a tax system that is generating almost nothing,
you can't afford to do that. Whether those credits
lead to new production - a company will always say
that. Do we know that's true? Possibly, possibly
not. And, I know this committee is looking at that.
I am not one for taking somebody who receives money at
face value when they say, "that money was really good
to me and really important." They will always say
that. You should have some independent experts that
tell you whether or not they are working. I'll tell
you, in Louisiana, their credit is basically a two-
year credit on horizontal drilling, from 1994, when
horizontal drilling was new. And you can only take
the credit for the cost of the well, and you can only
take that for up to two years and if you can't deduct
it within two years, you can't use it. It has been
testified, when I've been around, that no other
jurisdiction in the world has the same combination of
low tax revenue take and high credit payments as
Alaska. Alaska is unique in the world in that
combination of the revenue it generates and the
credits it pays.
REPRESENTATIVE GARA stated he has no interest in going back to
the ACES mechanism, or debating whether ACES was better than
Senate Bill 21. The maximum profit take under ACES on
production tax was approximately 75 percent, and under HB 133
the state would do better at low prices, and not as well at high
prices; in fact, HB 133 is a compromise that is "modest on both
ends" [slide 25]. Turning to the second feature of the bill, he
reminded the committee that the profits tax for GVR fields can
be next to nothing: below and around 10 percent at very high
prices. For non-GVR fields, until approximately $90 per barrel,
the profits tax ranges from 10 percent to 12 percent, which he
characterized as very low. Under PPT, the tax rate was 22.5
percent and ACES incorporated a base 25 percent tax rate. He
pointed out there are few "profits jurisdictions" around the
world with a 12 percent profits tax; HB 133 maintains the
current approach that the state gets paid the higher of either
the profits tax or the gross minimum tax. However, if oil
prices rise to $90 per barrel, it is unfair that Alaskans would
have to live off of a 13 percent profits tax, because that would
be too generous to industry. Representative Gara explained as
follows [slide 26]:
So, we've imposed a new sort of higher of minimum tax,
and that will be -- we will still have the mechanism
for determining the profits tax under the current law,
but it can't go below an effective rate of [22.5]
percent. You can deduct below that your, your credits
but ... having an effective tax rate of 9 percent, 11
percent - at $90 a barrel - [or] 13 percent doesn't
seem sustainable to me. And so, we've adopted a very
modest [22.5] percent profits tax as the higher of tax
that ... would be imposed when it's larger ... than
the gross minimum tax.
1:47:56 PM
REPRESENTATIVE GARA noted the bill also incorporates former
Governor Sean Parnell's first effort to reduce the ACES tax:
[through] bracketing. Because at some point oil companies reach
windfall profits range, HB 133 also addresses future high prices
through bracketing. Under the ACES tax system, when the tax
rate increased, the higher taxes applied to all oil, thus
Governor Parnell and opponents of ACES proposed a bracketed
windfall profits tax such that when companies achieve a $40
profit per barrel, there is a 10 percent profits surcharge; at a
$50 profit per barrel, the [surcharge] would increase by 5
percent on the portion of net income between $50 and $60 per
barrel; an additional 5 percent [surcharge] at $60 per barrel on
that portion of net income between $60 and $70 per barrel; an
additional 5 percent [surcharge] at $70 per barrel and above.
Therefore, a company could have a 25 percent surcharge, but the
incremental charges on the incremental value of oil would be
much less [slide 27]. In summary, Representative Gara advised
HB 133 provides the following [slides 28 and 29]:
· a fair and modest compromise, with a higher gross tax at
lower prices to protect the state, that would be fair to
the industry, and that includes royalty relief
· a modest profits tax at high prices
· recognition that when the price of oil increases all should
benefit
REPRESENTATIVE GARA then presented slide 30 that showed an
alternative provision for the committee's consideration, and
remarked:
We have a proposal that says at $50 a barrel the rate
goes up to 5 percent - the gross minimum tax; and then
it goes up goes up at every $8 increase at $58, at
[$]66, at [$]74, at [$]82, and at [$]90, by 1 percent.
We erred on the side of being conservative before we
had modeling done on the bill. But, the state's share
of the increase in a gross minimum tax would remain
smaller than the overall revenue taken in by an oil
company producer if we did it at every $6, and if we
did it at every $6, and instead of going all the way
up to 10 percent, just capped it at 8 percent. So,
just four additional brackets instead of six. So, we
did, 5 [percent] to 6 [percent] to 7 [percent] to 8
[percent] and stopped at a maximum 8 percent gross
minimum tax, but we did it at every $6 price increase
so at [$]56, at [$]62, at [$]68, [and at $]74. Next
fiscal year we would take in an extra $200 million in
revenue. The state's share for those, for that
increase would allow for the producer also to take in
extra profits and extra revenue that would be greater
than the amount of money the state's share would be.
So, their revenue share would be higher than the
state's ... additional take. I think that's the
better proposal, I didn't want to ... put it in the
bill until ... it was modeled. But, that would be my
personal recommendation, and not go all the way up to
10 percent - only go up to 8 percent.
1:52:09 PM
REPRESENTATIVE RAUSCHER noted that the slide presentation
alluded to progressivity and bracketing, and often referenced
the ACES tax system. He asked whether Representative Gara
recommended a return to ACES.
REPRESENTATIVE GARA answered no. The legislature should learn
from all of the previous oil tax systems and devise a system
that addresses the valid concerns related to prior or current
law, and that incorporates the best parts from those laws and is
informed by the best advice available. He said, "Frankly, were
that [Ballot Measure 1, Alaska Oil Tax Cuts Veto Referendum,
defeated 8/19/14] to pass, I would have proposed a different law
back then, and I had, as a matter of fact."
REPRESENTATIVE GARA further described the alternative proposal:
5 percent at $50; 6 percent at $56; 7 percent at $62; capped at
8 percent at $70. At the point when the profits tax becomes
bigger than the gross minimum, he said, "that would take over."
The result would be $200 million in revenue in FY 18, rather
than $100 million after credits. Representative Gara stated the
bill would allow the legislature to start building the state
again, pay back outstanding oil tax credits of almost $1
billion, and create one component of a revenue plan that would
help get the state out of the red [slide 31].
REPRESENTATIVE RAUSCHER asked whether all would agree that more
oil moving down the pipeline would be, in a large part, the
answer to the current problem.
REPRESENTATIVE GARA agreed that all seek more oil down the
pipeline; however, it is not in the state's greatest interest to
have more oil in the pipeline while receiving a zero percent
production tax for the first seven years, during some of the
most vibrant years of a field's production, "or a 4 percent tax
after that."
REPRESENTATIVE BIRCH referred to fiscal note [Identifier:
HB133-DOR-TAX-03-03-17] found in the committee packet which
indicated that approaching FY 23, additional revenue increases
from $200 million a year to over $300 million per year "as you
have a presumably, a declining throughput," and asked whether
[the legislation] is basically a $300 million tax increase on
the oil industry.
REPRESENTATIVE GARA answered:
When you're looking at those "out" years, where it
raises $300 million a year, that's only because oil
companies are reaping in much larger profits, so you
would ... be taking a share as oil companies are
getting a share from higher oil prices. So, that $300
million-year is at much higher prices than we have
today, and I think an oil tax system should be written
in a way where the state shares and industry shares in
high oil prices.
1:56:00 PM
REPRESENTATIVE GARA returned attention to GVR - gross value
reduction - which reduces a company's tax payment to zero until
approximately $70 per barrel for the first seven years, and then
by approximately 40 percent of the tax rate paid by other
fields. He said HB 133 would eliminate GVR for large fields
that are presumably more profitable - 50,000 barrel fields -
while recognizing that small, more challenged fields can still
retain GVR. Further, the maximum length of the GVR benefit
would be five years, instead of seven years. Turning attention
to Cook Inlet, Representative Gara said under current law, after
a certain sunset date, Cook Inlet [producers] will pay 35
percent profits tax; presently, producers are paying essentially
zero, and the calculations resulting in "close to no production
taxes in Cook Inlet" can be explained by DOR. The credits
provided by the legislature for Cook Inlet production were
intended to incentivize the production of natural gas, although
when searching for gas, many companies found oil. The bill
proposes a 22.5 percent tax on profits in Cook Inlet, but does
not propose a gross minimum tax. In addition, a bracketed
windfall profits surcharge is assessed after a company achieves
$40 per barrel in profits; however, Cook Inlet is a challenged
area and a $40 per barrel profit may never be achieved. He
opined some tax is needed as right now, "Cook Inlet is all
zeros" [slide 32].
REPRESENTATIVE GARA acknowledged the bill contains one mistake
in judgment on his part, and one drafting error. The bracketed
provision was not written as intended, thus there is an
amendment available to address the aforementioned technical
error [amendment not provided]. Further, there was no intent to
increase the gross minimum tax on heavy oil, which is defined by
the "Schrader Bluff and Ugnu definition of heavy oil," in that
any field that has oil with a lower gravity than the Ugnu and
Schrader Bluff reservoirs would not be subject to the rising
gross minimum tax, but would be left at the existing gross
minimum tax rate [amendment not provided].
REPRESENTATIVE JOHNSON asked whether Representative Gara had
reviewed HB 111, and how HB 111 compares to HB 133.
REPRESENTATIVE GARA pointed out HB 133 does not address tax
credits, and he opined the House Resources Standing Committee
should make a decision on tax credits. He restated that if the
state has higher revenue it can afford to pay tax incentives,
otherwise, it cannot. He added that there are two sides when it
comes to the state's fiscal health: the revenue the state
brings in, and what the state does in terms of incentives. The
proposed legislation addresses the revenue side; in fact, the
provisions in HB 133 protect the fiscal health of the state and
allow it to move forward in a more economically vibrant way,
while respecting company profits.
REPRESENTATIVE JOHNSON inquired as to Representative Gara's
opinion on changing tax policy almost on a yearly basis.
REPRESENTATIVE GARA stressed that the two most unstable tax
regimes possible are those that are too high, because there will
always be efforts [by industry] to make changes, and those that
are too low, because that affects investment decisions made in
anticipation of changes brought by the public. Currently, the
state has a too low tax regime that may be subject to an
initiative and/or future legislation. Preferable to changes -
brought by industry or the public - is passing legislation such
as HB 133 that would provide more certainty to the oil industry.
2:02:20 PM
REPRESENTATIVE BIRCH opined there is stability in Senate Bill
21. He suggested comparing the cost of production in Alaska
with the cost of production in competitive fields in the Lower
48, excluding royalty, which has been discussed. He cautioned
that bankers who have invested in small producers based on the
state's promise to pay their exploration costs, have indicated
there is a very competitive market for capital. He asked if the
bill sponsor had compared the cost of production in Alaska with
that of other jurisdictions.
REPRESENTATIVE GARA said yes. As a legislator, he has listened
to an unknown number of oil tax presentations from experts, "And
it's not as simple as just taking the cost"; in fact, there are
significant cost differences between producing a Shell oilfield
and drilling for shale oil, which can be done with many small
wells. All things being equal, drilling a large pool of oil is
more efficient than drilling for tiny amounts of oil with large
numbers of small wells. In addition, one could compare
production in Alaska with offshore oil production in the Gulf of
Mexico, although the cost per barrel of offshore oil production
is much higher than oil production on land. There is no simple
answer as to where Alaska ranks in terms of cost, he advised,
but a profits tax equalizes the fact that the costs may be
higher; furthermore, there is not one decisive comparison
factor, but many comparison factors.
REPRESENTATIVE PARISH returned attention to slide 6 that showed
production tax net of tax credits earned [in FY 18] was about
negative $25 million. He asked about the state's net in the
previous years of FY 16 and FY 17.
REPRESENTATIVE GARA answered that prior analyses measured oil
production revenue compared to what the state owes in cumulative
years of tax credits. He was unsure whether 2017 was the first
year the state owed more in tax credits than it received in
production taxes. The state is hampered in its ability to pay
the tax credits due to decreased levels of oil production tax
revenue.
2:07:25 PM
KEN ALPER, Director, Tax Division, DOR, referred to an earlier
question regarding estimated per barrel costs for
transportation, capital expenditures (CAPEX), and operating
expenditures (OPEX). [Differing estimates of per barrel lease
expenditure and transportation costs were shown in slides 8 and
10.] He said both estimates were from the current RSB, Appendix
E tables. However, the estimate of $9.33 in transportation cost
is the division's estimate for FY 17, the current fiscal year
[slide 10]. The other estimate of $9.77 is the division's
estimate for FY 18 [slide 8]. Therefore, this year, the total
estimated cost is approximately $40 and next year the estimated
cost is approximately $43. Last year, the division expected the
cost for FY 17 would be $46, but company efficiency measures
have reduced the oil industry's per barrel spending by
approximately $5 per barrel in the current fiscal year.
CO-CHAIR TARR suggested industry's changes in costs might lag
behind the actual change in oil price because, for example, the
companies cannot respond overnight with reductions in workforce.
MR. ALPER advised each year DOR contacts industry regarding its
plans for work in the next year, thus data is collected in
September and October for inclusion in the Revenue Sources Book.
For the industry, mobilization of workforce requires months or
even one year's notice and depends upon each company's
investment decisions and reaction to price changes. He opined
once industry determined the drop in oil price was not going to
immediately rebound, "spending has followed." The division's
forecast from the fall of 2014 - when the price first dropped -
was that oil price would be back up to $100 by FY 17. Soon
thereafter, the division extended its negative outlook, and in
spring 2016, forecast prices in the low [$]40s for the next two
or three years. However, the fall forecast is a bit more
optimistic.
CO-CHAIR JOSEPHSON recalled discussion about the unofficial
"[former Governor Jay] Hammond Doctrine" of oil industry taxes:
[two-thirds for state and federal government, and one-third for
industry]. Apropos of [slide 6], in 2018 state production tax
was $230 million. He questioned whether legislators should ask
if industry received $710 million, [approximately $230 million
times three] or whether the state's portion of tax revenue
should not be paid until oil prices return to $100 per barrel.
He pointed out that the state is due billions of dollars, "of
course, that's not possible right now." Co-Chair Josephson
asked, "How do I know what the industry brought in, in 2018?"
MR. ALPER returned attention to slide 6 that showed production
tax, and explained total government take, or total non-producer
take, is the sum total of all of the different taxes; in fact,
an oil company working in Alaska typically has five different
taxes: state property tax, state production tax, state
corporate income tax, royalty, and federal corporate income tax.
Total government take is a share of "divisible rents" - the
total divisible profit from producing oil, which is more or less
production tax value with the royalty added back into it as part
of the divisible total. As discussed in a previous
presentation, it is hard to track the share of the net because
the division must use aggregated data taken from net profits tax
filings; thus, the division does not have knowledge of any
company's profits in 1995, because that information was not
required. Further, the division's use of corporate income tax
filings [to determine profit] is complicated by apportionment
formulas and the complexity of corporate income tax. However,
data is available from 1978-1981, a time period during which
corporate income taxes were determined through a separate
accounting mechanism.
2:13:49 PM
CO-CHAIR JOSEPHSON questioned whether the division could use
data from ConocoPhillips to extrapolate profits earned by other
companies.
MR. ALPER said probably, although in the years before 2006, the
breakdown of ownership would need to be known; for example,
ConocoPhillips may have 30 percent ownership. He added, "I
suppose that would be possible ... [but] there's always going to
be differences among the producers based on their corporate
structure, their, what investments they're making at that moment
in history, that sort of thing."
REPRESENTATIVE WESTLAKE returned attention to slide 8, and
referred to the discrepancy that was discussed earlier.
MR. ALPER restated the estimate of $9.77 in transportation cost
and $33.64 [in per taxable barrel in deductible lease
expenditures], is the division's current forecast for the
average [oil industry] spending in FY 18. In December [2016]
the tax division was asked to use the aforementioned data,
assume the other features of the tax system, and calculate the
average effective tax rate at a variety of price points; thus
the data on slide 8 is taken from a letter to Representative
Gara dated January or February [2017], included in the committee
packet.
REPRESENTATIVE WESTLAKE said he understood the need to revisit
the issue of tax credits, and asked whether [revenue
information] on royalty is readily available.
MR. ALPER answered that royalty revenue is fully documented and
reported in the Revenue Sources Books [prepared by DOR]. He
observed Prudhoe Bay, Kuparuk, and other major finds were
discovered on state land; however, future production in the
National Petroleum Reserve-Alaska (NPR-A), offshore, and the
Arctic National Wildlife Refuge (ANWR), which are not located on
state land, will not provide the state the same share of
royalty.
REPRESENTATIVE PARISH referred to Representative Gara's
statement that BP reported deductions of Deepwater Horizon costs
from its Alaska profits, and asked whether Mr. Alper had further
information.
MR. ALPER indicated no.
REPRESENTATIVE GARA, in response to Representative Parish,
clarified an example of why BP's annual reports could not be
relied upon for an accurate rendition of their Alaska profits is
that BP deducted some of its Deepwater Horizon costs, which are
not allowed to be deducted from Alaska's corporate income tax;
if BP is paying the gross minimum tax of 4 percent, there are no
deductions other than the net operating loss. He pointed out
Alaska's corporate income tax system works in a "funky" way, and
deferred to Mr. Alper for an explanation of worldwide
apportionment.
2:18:38 PM
CO-CHAIR TARR asked Mr. Alper to briefly describe worldwide
apportionment.
MR. ALPER informed the committee oil companies have a global
income number, which is their profit from around the world, thus
taxes paid in Alaska are not necessarily on profit made in
Alaska, but are on the amount a company made worldwide,
multiplied by a series of ratios tied to ratios of Alaska
activity to global activity, such as a payroll ratio, a property
asset ratio, and an extraction factor. The resulting formula is
multiplied and applied to regular corporate income tax for non-
oil and gas companies, and to a special formula for oil and gas
companies. He continued:
The effect of that, on average, is a little bit less
than the statutory tax rate. So, if you look at the
corporate income tax statutes in [AS] 43.20, the top
rate is 9.4 percent of profits. What we've learned,
based on a track record of many years, is at this
moment in history, the average oil and gas company is
paying the equivalent of about [6.5] percent of their
profits to the State of Alaska. So, the short answer
there is, the net effect of that multiplier is that
we're a little bit of a, a below-the-mean type
calculation for the State of Alaska. And, that's why
you sometimes hear talk about going back to this idea
of separate accounting which would - at least in
theory - bring us back to the 9.4 statutory rate.
MR. ALPER, in response to Representative Parish, clarified that
the percentage actually paid, on average, is a modeling
convention of approximately 6.5 percent. For modeling purposes,
he explained, the division deducts production tax paid from the
income, or production tax value, and "the amount that is left
after the production tax is what we calculate the corporate
income tax on. And then to go further, after subtracting the
corporate income tax, what's left after that, that's what you
would calculate the federal corporate income tax on."
2:21:22 PM
REPRESENTATIVE PARISH concluded that the state is receiving
approximately 3 percent less in corporate income tax than the
statute indicates.
MR. ALPER agreed "on average"; however, the percentage will vary
from company to company because each company has its own
circumstances and ratios.
REPRESENTATIVE PARISH further asked whether the global
apportionment formula takes into account the higher average
quality of Alaska oil - which is low gravity oil - in contrast
with tar sands that are prevalent in other parts of the world.
MR. ALPER was unsure and offered to provide a response from the
division.
CO-CHAIR JOSEPHSON questioned whether the state is receiving
less than what is statutorily designated because the formula at
the present time is affected by worldwide deductions,
apportionment, and such.
MR. ALPER said exactly right. For example, if a company's
global share of income is $1 billion, Alaska's 10 percent of
that would be $100 million, and if the share of property the
company owns in Alaska is less than one-tenth of its global
property, "that will reduce the multiplier in some way, those
kinds of factors."
2:23:24 PM
REPRESENTATIVE PARISH returned attention to the global
apportionment issue and opined if the state is getting paid
less, due to the aforementioned formula, somebody else must be
getting paid more.
MR. ALPER recommended that Representative Parish discuss this
issue with the division's corporate income tax expert, Brandon
Spanos, Deputy Director, Tax Division, DOR.
CO-CHAIR TARR recalled there was previous legislation sponsored
by Representative Seaton [House Bill 191 introduced in the
Twenty-Ninth Alaska State Legislature] on this topic, and said
over the years the monetary value of separate accounting versus
worldwide accounting has added up to approximately $6 billion
[in additional revenue to the state].
MR. ALPER related in 1978 the legislature enacted a separate
accounting based system, which was adjudicated through the
courts, and which greatly increased Alaska's revenue take. At
that time, in 1978, Alaska had a lot of production and
relatively low amounts of infrastructure. The state was brand-
new to the oil business and not a lot of infrastructure had been
built, thus "the multipliers were strongly in our favor."
However, multipliers are shifting toward breaking even: Alaska
is currently at two-thirds [rate of government take collected
from industry] and was probably at one-third or one-quarter [in
1978]. Within the tax division, there is concern that a return
to separate accounting may instigate manipulation of the tax
system by taxpayers' sophisticated accountants. He gave the
simple example of a major operator in Alaska that sells its
Alaska operations to a subsidiary based in Washington State, and
then leases the Alaska operations back for $5 billion per year;
for corporate income tax separate accounting purposes, this
would mean the major operator is now operating at a loss. He
cautioned that the cumulative impact of a return to separate
accounting is unknown. Furthermore, the division performed a
rudimentary analysis for the fiscal note attached to
Representative Seaton's bill, and estimated a change to separate
accounting may have raised a couple hundred million dollars per
year, presuming nothing else changed.
REPRESENTATIVE JOHNSON requested the committee hear testimony
from the [Oil and Gas] Competitiveness Review Board (OGCRB),
DOR.
CO-CHAIR TARR related there were no plans to hear from OGCRB.
She added there was a delay in the board's work after the new
administration took office, and she was unsure whether the board
was fully appointed at this time.
MR. ALPER advised that the 2015 Oil and Gas Competitiveness
Review Board Report was made available to the committee. He
explained that the most recent project on the board's
[deliverables] cycle would have been a Cook Inlet analysis;
however, the board chose to defer that analysis due to the major
changes to the Cook Inlet taxation system that were made last
year. The board recently began the process of hiring an outside
contractor to look at various pieces of legislation, and how the
board might compare and contrast Alaska's competitiveness, and
he said, "So, I would doubt that there is much of, of interest,
that's extremely timely, that could be brought to the committee
now, although, later in session I think there will be at least a
draft report to bring forward."
2:28:07 PM
CO-CHAIR TARR said she would report to the committee on the
status of OGCRB.
2:28:31 PM
REPRESENTATIVE GARA closed, restating that the state contracts
for a higher royalty on a field that it believes has the
potential to be more profitable. During the debate on Senate
Bill 21, an amendment was [adopted] to reduce the production
taxes on [potentially more profitable] fields to reduce overall
government take to that of the 12.5 percent fields; however, the
benefit that lowers the production tax on 16 percent royalty
fields is eliminated in HB 133. Finally, the gross minimum tax
in HB 133 never gets to North Dakota and Louisiana levels.
Representative Gara reminded the committee to subtract about
four-tenths from the tax because 35 percent of the taxes paid to
the state are deductible from a company's federal corporate
income tax. He further explained:
So, we can sort of piggyback a little bit on the
federal government's decision not to accept as much of
a share as it could, but if we raise taxes by 3
percent, we're really raising them by 2 percent
because the company then gets that much bigger of a
federal deduction. And the way our corporate tax
works, you get to deduct your production taxes from
your state corporate tax, too. So, you get two
deductions for any tax increase, and so, any tax
increase here really should be viewed as ... only
about six-tenths of what it looks like because about
four-tenths of that, the company doesn't really pay.
CO-CHAIR JOSEPHSON, although not representing industry,
suggested that one of industry's responses to HB 133 will be
that Louisiana's fixed 13 percent tax rate is higher at oil
prices through $90 per barrel, but HB 133 provides an
opportunity for the state, theoretically, to get 35 percent at
an oil price of $170 per barrel.
REPRESENTATIVE GARA pointed out legislators have a duty to
represent their constituents now, and now, no one anticipates
world record oil prices of the amount it would take to get the
profits tax under current law up to 35 percent. He said it's a
mythical tax rate because never has there been an oil price that
would have gotten the state [to a 35 percent tax rate]. In
order to protect the future of Alaskans during the next decade,
and provide a vibrant university system and schools in which
Alaskan children can thrive, Alaska legislators need to look at
the near-term - three years, five years, and ten years into the
future - and HB 133 protects Alaskans over the next ten years;
without this proposed legislation, the revenue the state needs
now, for reasons the committee understands, will be lost.
2:32:56 PM
REPRESENTATIVE RAUSCHER spoke of the confusion created for
producers related to whether the proposed legislation is a
permanent fix to the oil tax system.
REPRESENTATIVE GARA agreed the legislature should not develop a
partial oil tax system that would have to be revisited. He
remarked:
So, in this bill we've addressed the low-price problem
of the zero percent production taxes on GVR oil, [and]
the 4 percent gross minimum tax that we live on until
$74 a barrel. So, that's the "for the next 10 years
problem." But, we also address the next 30-year
problem by also addressing the fair share we should be
getting when companies are in windfall profits range.
So, this bill has both provisions. One provision that
probably won't kick in for many, many years, which is
when companies are in the windfall profits range, [is]
"What should our share be?" And, one provision for
what we do now. And so, it's ... intended to be
stable across all prices, and to be less aggressive
than ACES was at high prices, but to be stable across
all prices, rather than focusing on just now, or just
later.
REPRESENTATIVE GARA reiterated there are two amendments to the
bill that better reflect the legislation's intent: 1. to not
increase the tax on heavy oil; 2. to correct language on
bracketing [amendments not provided].
CO-CHAIR TARR announced the committee's intention to have one
[oil and gas tax] bill reported from the committee, therefore,
the purpose of today's presentation was to hear other options
that could be included in upcoming legislation.
[HB 133 was held over.]