Legislature(2015 - 2016)BARNES 124
02/22/2016 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB247 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 247-TAX; CREDITS; INTEREST; REFUNDS; O & G
1:23:25 PM
CO-CHAIR NAGEAK announced that the only order of business is
HOUSE BILL NO. 247, "An Act relating to confidential information
status and public record status of information in the possession
of the Department of Revenue; relating to interest applicable to
delinquent tax; relating to disclosure of oil and gas production
tax credit information; relating to refunds for the gas storage
facility tax credit, the liquefied natural gas storage facility
tax credit, and the qualified in-state oil refinery
infrastructure expenditures tax credit; relating to the minimum
tax for certain oil and gas production; relating to the minimum
tax calculation for monthly installment payments of estimated
tax; relating to interest on monthly installment payments of
estimated tax; relating to limitations for the application of
tax credits; relating to oil and gas production tax credits for
certain losses and expenditures; relating to limitations for
nontransferable oil and gas production tax credits based on oil
production and the alternative tax credit for oil and gas
exploration; relating to purchase of tax credit certificates
from the oil and gas tax credit fund; relating to a minimum for
gross value at the point of production; relating to lease
expenditures and tax credits for municipal entities; adding a
definition for "qualified capital expenditure"; adding a
definition for "outstanding liability to the state"; repealing
oil and gas exploration incentive credits; repealing the
limitation on the application of credits against tax liability
for lease expenditures incurred before January 1, 2011;
repealing provisions related to the monthly installment payments
for estimated tax for oil and gas produced before January 1,
2014; repealing the oil and gas production tax credit for
qualified capital expenditures and certain well expenditures;
repealing the calculation for certain lease expenditures
applicable before January 1, 2011; making conforming amendments;
and providing for an effective date."
1:24:18 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
on behalf of the governor, first drew attention to two letters
to Representative Seaton from the Tax Division, dated February
2, 2016, and February 19, 2016. He explained that these letters
are the latest iterations and updates to modeling efforts for
the North Slope and the Cook Inlet that were prepared over the
last interim in response to Representative Seaton's request for
analysis of field lifecycle costs and benefits to the State of
Alaska of various new field developments and what the state's
cash flow is going to look like from new development. The
letters are provided as background documents for the committee
as well as a precursor to some of the modeling that DOR will be
providing in its next presentation to the committee. That
modeling looks at the current situation, which is what is in the
aforementioned letters, as well as looks at the impact on that
of the changes envisioned in HB 247.
MR. ALPER began a PowerPoint presentation titled, "Oil and Gas
Tax Credit Reform-HB247, Additional Modeling and Scenario
Analysis - Part 1." He turned to slide 2, "What We Will Be
Discussing," and outlined the topics that he planned to cover
today and on 2/24/16: overview of revenue and production; what
credits worked and what didn't; credit cost in perspective; bill
details and how the pieces work; scenario analysis and economics
of changes; and gas supply issues in Cook Inlet.
1:27:01 PM
MR. ALPER moved to the graph on slide 4, "Overview of Revenue
and Production," to discuss what the state's revenues have
looked like over the last 10 years [fiscal years 2006-2015]. He
pointed out that the production tax (depicted in dark blue) is
the most reactive to the changes in the price of oil. This is
followed by the state's other petroleum revenues such as the
corporate income tax and property tax (depicted in orange),
unrestricted royalties (depicted in gold), restricted royalties
(depicted in grey), and non-petroleum revenues (depicted in
lighter blue). Thus, the graph shows the state's undesignated
general fund (UGF) plus the permanent fund royalties. The graph
puts into perspective how much impact that changes in the price
of oil have on things, especially on the production tax side.
MR. ALPER displayed the pie chart on slide 5, "Overview of
Revenue and Production," and reported that 17 billion barrels of
crude oil have been produced on the North Slope since the Trans-
Alaska Pipeline System (TAPS) began [in 1977]. The great bulk
of that oil, over 90 percent, came from two fields - Prudhoe Bay
(depicted in red) and Kuparuk (depicted in dark green). Various
other fields are depicted by the other colors on the chart.
MR. ALPER brought attention to the graph on slide 6, "Overview
of Revenue and Production," to review the declining curve in oil
production between the years 1977 and 2025. He explained that
things ramped up after the commencement of commercial operations
and have been gradually declining since then. An expectation of
a flattening in the decline can be seen on the graph, but a
decline still continues from today's number of about 500,000
barrels a day to about 300,000-400,000 barrels a day in 8-10
years from now.
1:28:53 PM
MR. ALPER showed slide 7, "Overview of Revenue and Production,"
and noted that the graphic is from the U.S. Energy Information
Administration. He said the graph depicts the scale of Alaska's
oil fields and shows production aggregate [from 1990 to date].
The central North Slope has produced about 8 billion barrels of
oil [shown in black] and still has a lot of oil yet to be
produced (shown in light blue). A substantial chunk of that oil
is proven, especially in the offshore. There is also a very
large amount of unproved technically recoverable oil, oil that
has not explicitly been discovered but which the professionals
say is there. The two bars at the bottom of the graph depict
the largest shale developments in the Lower 48, the Bakken and
the Eagle Ford, which in terms of total production are much
smaller than Alaska has had, but they have very large volumes of
potential or technically recoverable oil.
MR. ALPER turned to the pie charge on slide 8, "Overview of
Revenue and Production," to point out that the great bulk of
Alaska's oil production comes from the three "majors," which are
BP, ConocoPhillips, and ExxonMobil. Alaska also has five other
substantial producers: Chevron, Hilcorp, ENI, Anadarko, and
Caelus. Some of these five companies operate smaller fields of
their own and some have smaller partnerships in the major oil
fields of Prudhoe Bay and Kuparuk; many of the proposed changes
in HB 247 would impact these companies. The proposed changes in
the bill would also impact the explorers, such as the Brooks
Range/Mustang field, the Repsol/Armstrong project, Great Bear,
Furie, BlueCrest, and several others.
1:30:54 PM
MR. ALPER moved to slide 10, "Credits: What Worked, What
Didn't?" He noted that a number of credits have been put into
law over the years that have never been used. These include the
New Areas Credit [AS 43.55.024(a) and also known as the Middle
Earth Credit], a credit of up to $6 million that was provided in
House Bill 3001, the production profits tax (PPT) bill that was
passed in 2006 [Twenty-Fourth Alaska State Legislature]. This
credit was structured very similarly to the Small Producer
Credit: a company that began producing in the frontier areas in
the Interior would get a $6 million offset to its taxes. That
has not been used because there has not yet been any commercial
production from the Interior portions of the state. Another
unused credit is the Jack-Up Rig Credit, which was part of the
various reform measures passed in 2010 [AS 43.55.025(m) Senate
Bill 309, Twenty-Sixth Alaska State Legislature]. Also unused
is the 80 percent Frontier Basin Drilling Credit that was part
of the Frontier Basin Act of 2012 [AS 43.55.025(n), Senate Bill
23, Twenty-Seventh Alaska State Legislature]. While some of
those activities have occurred, the companies have found it
advantageous to use ....
CO-CHAIR NAGEAK requested a definition of the term "stacking."
MR. ALPER used the Cook Inlet Jack-Up Rig Credit as a means to
define stacking. Under that credit, he explained, the state
will pay 100 percent of the cost of drilling a well that meets
certain criteria. But tied up with that 100 percent credit are
various conditions, including some data requirements and a
requirement to pay back half the money if commercial production
is brought in from that. In Cook Inlet, companies have found it
more advantageous to instead use the general purpose 40 percent
Well Lease Expenditure Credit and to stack it, combine it, with
a 25 percent Net Operating Loss Credit. In that circumstance
the state pays roughly 65 percent of a company's costs without
some of the contingencies and requirements to pay it back in the
future.
1:33:13 PM
MR. ALPER resumed his discussion of slide 10 and reiterated that
the New Areas Credit, Jack-Up Rig Credit, and Frontier Basin
Drilling Credit are in current law but scheduled to sunset [in
2016]. To qualify for any of these benefits a company would
have to do some activity by sometime in 2016. He said [the Tax
Division] doesn't anticipate making any payments on those,
although there is certainly a possibility of it.
MR. ALPER drew attention to slide 11, "Credits: What Worked,
What Didn't?" and discussed credits that have been used but are
scheduled to sunset and be phased out regardless of what the
committee does. Regarding North Slope exploration credits, he
said the Exploration Incentive Credit that came into statute in
2003 is scheduled to sunset on July 1, 2016, meaning the work
must be done by that date. While DOR cannot provide specific
numbers due to confidentiality, he can say that the state has
paid between $125 million and $200 million on those exploration
credits. Another $150-$200 million was used against liability,
meaning the companies that explored had a tax liability, most of
those companies being the state's major producers, and they used
that credit to reduce their tax payments. The great bulk of
credits used against liability occurred before fiscal year 2011,
while the refunded credits have been more used in recent years.
In round numbers, the North Slope exploration credits have
resulted in between $275 million and $400 million of state past
expense, direct or indirect. Regarding non-North Slope
exploration credits, primarily Cook Inlet Exploration Credits,
the range of refunded credits is roughly between $25 million and
$75 million. Not a material amount of credits was used against
liability because there is not a lot of tax liability due to the
Cook Inlet tax caps that are in statute. He further noted that
as part of Senate Bill 21 [passed in 2013, Twenty-Eighth Alaska
State Legislature], the Net Operating Loss (NOL) Credit was
increased to 45 percent starting January 2014. When that
happened the Exploration Credit of 40 percent could be stacked
with an operating loss and there was a time period where the
state was paying up to [85] percent of companies' costs on the
North Slope. That was a two-year increment that went away at
the end of 2015. Meanwhile, with the addition of the 40 percent
Well Credit in 2010, the Exploration Credit became somewhat
redundant. Many of the expenditures that were qualified for the
Exploration Credit were also qualified for the Well Credit with
certain exceptions like in seismic work. These exploration
credits are going to be going away under current law.
1:35:55 PM
MR. ALPER turned to slide 12, "Credits: What Worked, What
Didn't?" and discussed two more credits that are scheduled to
sunset and be phased out. He explained that the Small Producer
Credit is a nonrefundable, non-carry forward credit that can
only be used to reduce a small producer's tax by up to $12
million. This credit has been well used on the North Slope:
between $250 million and $400 million was used through fiscal
year 2015 and another $257 million is projected to be used
before this credit goes away. He explained that even though
this credit is going away, the sunset is for applying for the
credit and that is why another [$257] million is projected.
Once a company starts producing as a new producer, the company
can get this credit for up to nine consecutive years. Although
those companies that might have been receiving it since 2007 or
2008 are phasing out, any new companies coming into it now will
be able to receive this credit until approximately 2025, so the
state will be making some payments on this credit until then.
1:36:58 PM
REPRESENTATIVE JOSEPHSON said that sounds like, in effect, the
companies control the key to the statute of limitations because
they set the clock ticking.
MR. ALPER replied the clock begins ticking when a company first
claims that credit, which is generally when it first came into
production. It is not like companies are in production and
choosing not to use the credit, it is that there are companies
that are just starting up and they will begin using the credit.
REPRESENTATIVE JOSEPHSON, using the North Slope exploration
credits on slide 11 as an example, surmised that someone within
DOR or DNR knows which of the credits bore fruit as a general
proposition for the people of Alaska, but cannot fully disclose
that because it would violate current law.
MR. ALPER responded that [the Tax Division] cannot discuss on a
case-by-case basis. For example, [the division] cannot say the
state gave $20 million to Company X and Company X ended up not
producing anything, or that Company Y was given $10 million and
subsequently found an oil field that is producing 10,000 barrels
a day. [The Tax Division] is unable to share at a level of
detail, but it can aggregate these things. For example, last
week the committee was shown a slide that talked about total
dollars on projects that have borne fruit, are in production
right now, and then dollars spent on credits that have not yet
borne fruit. He said he believes that for the North Slope about
$650 million in credits has gone to companies or projects that
are not yet in production and about $1.45 billion in refunded
credits has gone to projects that are now in production.
REPRESENTATIVE JOSEPHSON asked whether as a general proposition
there should be a statute that at least lets [legislators] meet
in executive session so that they can do their jobs fully and
not miss this critical fact.
MR. ALPER answered he is not an attorney and is not certain how
that would work. He pointed out that Section 8 of HB 247 does
allow for a confidentiality waiver so these things could be
discussed going forward. To be able to have an executive
session to discuss what credits the state has spent over the
last 10 years so legislators and policymakers could understand
the scope of what is before them is an idea that he thinks is
excellent. However, he qualified, he does not know the legal
nuance of that.
1:39:43 PM
MR. ALPER returned to his discussion of slide 12. He reiterated
that the Small Producer Credits will sunset slowly. A smaller
amount of the Small Producer Credits was used in Cook Inlet
because the volumes are smaller in the inlet: $50-$100 million
has been used against liability and about another $15 million is
projected before that credit goes away fully.
MR. ALPER noted that the credit which subsidized the Cook Inlet
Natural Gas Storage Alaska (CINGSA) facility in Kenai was part
of the Cook Inlet Recovery Act of 2010 [AS 43.20.046, House Bill
280, Twenty-Sixth Alaska State Legislature]. That credit was
specifically written to only allow a single credit for a
specific project and has been used. That statute could
therefore be repealed without any plus or minus to the system,
but [the administration] didn't contemplate doing that when
writing the bill. That statute has a specific confidentiality
waiver, he said, so he is able to tell the committee that the
state gave $15 million to CINGSA to build its facility.
1:40:55 PM
REPRESENTATIVE SEATON inquired as to why the CINGSA credit was
not eliminated from the statute given it is a credit targeted
specifically to corporate income tax rather than production tax.
MR. ALPER confirmed that this credit is in AS 43.20, which is
the corporate income tax statute and so was intended to be used
against that tax. He said he does not recall whether CINGSA is
a corporate taxpayer, but that the company earning this credit
would have the ability to transfer or sell that credit to a
company that might owe corporate income taxes in Alaska. That
occurred and was paid out in fiscal year 2014. According to the
historic record of credits provided for this meeting, it can be
seen that credits under AS 43.20 are $15 million in fiscal year
2014, which is a specific reference to this credit that has been
paid. He reiterated that there is no reason why this statute
could not be repealed as part of this or any other legislation.
REPRESENTATIVE SEATON advocated for repealing this credit
because, to his knowledge, it is the only place where the state
is giving an oil and gas production tax credit against corporate
income tax. He said he thinks this is a model that the
committee would want to remove from statute.
CO-CHAIR NAGEAK inquired whether Representative Seaton plans to
move his suggestion at a later time.
REPRESENTATIVE SEATON replied that he will be doing so, but
added that he is just making members aware of the probability.
MR. ALPER pointed out that there are two other credits in the
oil and gas statutes that go against corporate income tax,
CINGSA being AS 43.20.046. He explained that AS 43.20.047 is a
similar credit that would build storage tanks; for example,
liquefied natural gas (LNG) storage tanks are envisioned for the
Interior gas utility. He offered his belief that there is
intention to use that credit, which remains on the books and is
useable against corporate income tax. Likewise, he continued,
the "Refinery Tax Credit" in AS 43.20.053 [qualified in-state
oil refinery infrastructure expenditures tax credit] can be used
against the corporate income tax, and at least one Alaska
refinery is publicly talking about an asphalt plant project that
it envisions earning that tax credit against.
1:43:24 PM
MR. ALPER brought attention to slide 13, "Credits: What Worked,
What Didn't?" to discuss which credits would be repealed in HB
247. He noted that the bill would change many of the rules but
would not repeal that many credits. He allowed that the two
credits that would be repealed, the 20 percent Qualified Capital
Expenditure (QCE) Credit and the 40 percent Well Lease
Expenditure (WLE) Credit, are very large credits. The Qualified
Capital Expenditure Credit existed on the North Slope until
2013, but the Well Lease Expenditure Credit never existed on the
North Slope. [The Tax Division] cannot discuss exact totals, he
noted, but he can say that a total of between $500 million and
$800 million in Cook Inlet and some in the Interior has been
credited, cashed out, for these line items. Over 85 percent of
it occurred after fiscal year 2013, largely because of the
greater activity that was incentivized by the passage of the 40
percent Well Lease Expenditure Credit in 2010. So, the state is
spending $150 million to $200 million a year. If these credits
were repealed, the state's credit liability going forward would
go down commensurately by about $150 million per year. Mr.
Alper noted that these credits were created, in part, due to
supply anxiety and the fear that gas was going to run out in the
Cook Inlet. That problem has now been somewhat fixed. He urged
members to keep in mind that these credits could also be spent
on oil drilling and oil well workovers and activities that
increase oil production, which are good for the economy and
great for having oil in the refineries, but not necessarily the
same sort of life and death issue....
1:45:05 PM
CO-CHAIR NAGEAK requested Mr. Alper to expand on well workovers.
MR. ALPER explained that a workover is when an existing oil well
is cleaned out and new equipment added, a second-generation
activity to make an old oil well newer again and produce better.
It fits under the definition of well lease expenditures, so
generally that sort of activity would get the higher level, 40
percent, credit. Cook Inlet has a lot of old oil wells. In the
1960s production was over 200,000 barrels a day. New players
have come in and worked over some of the old wells and Cook
Inlet oil production has more than doubled in the last few
years. A lot of that activity would have been eligible for the
state's credits at the higher level because that activity met
the definition.
CO-CHAIR NAGEAK asked whether this is currently being used "up
north" by the companies that have taken over production from the
bigger companies and are doing well workovers.
MR. ALPER replied yes, "Cook Inlet north" is most definitely
earning these credits.
CO-CHAIR NAGEAK clarified he is meaning the North Slope.
MR. ALPER responded that on the North Slope these well drilling
credits are not available so the companies are unable to claim
the credits. However, the companies are working over old wells
and trying to get increased production from mature fields in the
North Slope.
REPRESENTATIVE NAGEAK recounted that he visited one of those
wells last year and was told that smaller companies have taken
over fields from BP and others and these companies have a system
for doing this to the wells. He said he thinks this will occur
more and more as the wells age.
MR. ALPER answered it is important to note that, yes, this is
happening on the North Slope and companies are not getting
drilling credits for it, although the state is offering drilling
credits in Cook Inlet for similar work. He surmised that the
companies will provide greater detail in this regard when they
testify before the committee.
1:47:20 PM
REPRESENTATIVE SEATON inquired whether splitting out the amount
that was given for oil and for gas can be done without breaking
confidentiality.
MR. ALPER replied he will talk with staff to determine whether
that would be possible. He asked whether Representative Seaton
is meaning to try to break the oil-related from the gas-related
expenditures for Cook Inlet or non-North Slope credits in this
category.
REPRESENTATIVE SEATON responded yes and added that he would like
the information for the years since 2013.
MR. ALPER agreed to do his best to get that to the committee.
1:48:35 PM
MR. ALPER concluded his discussion of slide 13. He said he will
make the case later in the presentation that the Cook Inlet gas
supply issues are less problematic than they were in 2010 when
Southcentral Alaska was planning and practicing brownout drills.
MR. ALPER moved to slide 14, "Credits: What Worked, What
Didn't?" to outline the credits that would remain on the books
should HB 247 pass as presented. He said the Carried-Forward
Annual Loss Credit, also called the Net Operating Loss (NOL)
Credit, is the primary credit envisioned by [the administration]
as being part of the state's system going forward. This credit
is 25 percent in Cook Inlet and the Interior, and 35 percent on
the North Slope. It can be cashed out, with the exception that
large producers must carry it forward and use it against
liability. Regarding the exploration credits that he earlier
spoke to as being about to sunset, he explained that the
exception to that is the Middle Earth Exploration Credits, which
are outside of the North Slope and the Cook Inlet. These
credits are 30-40 percent of qualified expenditures depending on
the location of the well and the activity, and will sunset in
5.5 years on January 1, 2022. Regarding the Cook Inlet Tax
Caps, he noted that they are not strictly speaking a credit but
a statutory maximum on the amount of taxes the producers can pay
if they are producing in Cook Inlet. He said this cap is
roughly 17 cents per thousand cubic feet (MCF) of gas and the
oil tax is zero. These tax caps are tied to the old economic
limit factor (ELF) formulas that were in place in 2005 and are
currently scheduled to sunset on January 1, 2022.
1:50:35 PM
REPRESENTATIVE SEATON drew attention to the Net Operating Loss
Credit that is 35 percent on the North Slope and 25 percent in
the Cook Inlet. He requested Mr. Alper to explain why 25
percent is working well in Cook Inlet while it is 10 percent
more on the North Slope.
MR. ALPER answered that the Net Operating Loss Credit has
historically been tied to the base rate of the Net Profits
Production Tax. The 2007 bill, Alaska's Clear and Equitable
Share (ACES), had a 25 percent tax rate with a sliding scale, or
progressive factor, that went higher based on that, so the
decision was made to pay losses at the base level of that 25
percent and that was both Cook Inlet and North Slope. On the
North Slope, the passage of Senate Bill 21 raised the tax rate
itself. The rate of 35 percent is more of a maximum tax than a
minimum tax and it tends to slide down because of the sliding-
scale credit. The way the legislature addressed that in 2013
was by raising the size of the Net Operating Loss Credit on the
North Slope to 35 percent, tying it to the tax rate. The 25
percent operating loss rate in Cook Inlet is a remnant of the
2007 ACES statute. In some ways the North Slope Net Operating
Loss Credit is called a playing field leveler: a producing
company who owes taxes spends more money and reduces its tax
liability, so this creates a parallel benefit to the newcomer.
In Cook Inlet where there isn't much tax liability, it is
arguable that the 25 percent Net Operating Loss Credit itself
isn't needed to level the playing field, but it is very much of
an incentive and encourages ongoing work and enables people to
get an advantage to investing money in Cook Inlet.
1:52:36 PM
REPRESENTATIVE SEATON noted that there is the increased base of
35 percent on the North Slope as well as a "per-barrel well
credit" that is not figured in or subtracted from the 35. He
asked whether the way to make these things equivalent would be
to somehow calculate in the [Per-Taxable-Barrel] Credit against
the 35 percent base tax.
MR. ALPER replied that Representative Seaton is really talking
about a calculation of the effective tax rate after [Per-
Taxable-Barrel] Credits and somehow scaling back the Net
Operating Loss Credit to an effective tax rate. He advised that
there might be some technical complexities in doing that because
the effective tax rate varies from field to field and producer
to producer, but if it was the will of the committee to reduce
that Net Operating Loss Credit to some sort of metric that used
an effective tax rate for the North Slope, [the administration]
could help the committee produce an amendment or different
language. He added that Representative Seaton is correct that
as a playing field leveler the state is probably giving more
than equal benefit. When looking at it from the marginal dollar
level - and other committees have looked at marginal costs and
marginal tax rates over the years - when a major producer spends
one incremental dollar it gets an incremental 35 cent tax
benefit at the margin because the producer has reduced its
taxable base, its production tax value, by $1, and then 35
percent off of that is 35 cents. However, the [Per-Taxable-
Barrel] Credit itself is not impacted by that marginal
additional dollar of spend and therefore this is designed to be
a marginal benefit - the 35 percent Net Operating Loss Credit
equals not so much the effective tax but the tax benefit that
the company receives from its last dollar spent.
CO-CHAIR NAGEAK added that the cost of doing business is much
higher in the North Slope than it is in the south because of the
transportation cost.
MR. ALPER agreed that without question the logistical costs, the
mobilization costs, in the North Slope are very different than
anything else in Alaska.
1:54:54 PM
MR. ALPER concluded his discussion of slide 14. He reiterated
that the credits that would remain after passage of HB 247 would
be the Carried-Forward Annual Loss Credit, the Middle Earth
Exploration Credits, and the Cook Inlet Tax Caps.
MR. ALPER turned to slide 15 to continue his review of the
credits that would remain if HB 247 passes. These credits are
less known, he noted, because there has not yet been production
in Middle Earth. The first of these is the Middle Earth Tax Cap
at 4 percent of the gross value for the first seven years of
production so long as that production begins before 2027. That
is a provision of the "Frontier Basins Credit" bill of 2012
[Senate Bill 23, Twenty-Seventh Alaska State Legislature]. Any
production that begins in, say, Nenana or similar areas in the
state, will pay a 4 percent gross tax regardless of the price of
oil for the first seven years of production. The other two
remaining credits are the corporate income tax credits mentioned
earlier. The LNG Storage Facility Credit and the "Refinery
Infrastructure Credit" [qualified in-state oil refinery
infrastructure expenditures tax credit, AS 43.20.053] would
remain on the books, although the Refinery Infrastructure Credit
is scheduled to go away in 2020.
1:56:06 PM
MR. ALPER drew attention to slide 17, "Credit Cost in
Perspective," to discuss how much the state has spent and what
it has received related to North Slope refundable credits
[between fiscal years 2007 and 2015]. He reiterated that the
state spent $1.45 billion supporting six projects that are now
in production. Production from those six projects equaled 38.5
million barrels of oil in total aggregate. This means the state
spent $37.30 for every barrel of production from these new
fields that have come on in the North Slope. That dollar number
will decline over time because, for the most part, the money is
spent and the oil is going to keep flowing for years to come and
every new barrel from that is going to dilute/reduce the per-
barrel cost. Meanwhile, the lease expenditures for all of those
projects through the end of fiscal year 2015 was just less than
$5 billion for the companies involved. So, the state's $1.45
billion in credits represents roughly 29 percent of the
companies' total lease expenditures; this is the share of the
project that the state has put money into on the North Slope
over the last 8-10 years.
1:57:32 PM
REPRESENTATIVE SEATON understood that the per-barrel dollar
amount is anticipated to go down, but noted that the state is
continuing to pay lease expenditures at 29 percent of the costs.
He asked how rapidly that is expected to go down.
MR. ALPER expected that that number will go down because the
incremental lease expenditures, the operating expenditures to
keep the existing fields going, is less than the start-up costs.
Likewise, this analysis is only looking at refunded credits.
So, the answer to the question is also largely contingent on the
price of oil - are these companies going to be profitable or
not? If they are profitable and they are taxpayers, they are
not going to be getting cash credits. If they are running
operating losses during production, the state will be continuing
to pay them refundable credits on their operating losses and
that will bring up the spend numbers. Therefore, a couple of
different variables are in play here. He said he would expect
this lease expenditure credit to drop, but not as rapidly as the
per-barrel number.
1:58:41 PM
REPRESENTATIVE JOSEPHSON understood from slide 17 that the North
Slope refundable credits for six projects have aided in the
production of nearly 39 million barrels.
MR. ALPER answered that "aided" is a subjective term. He
repeated that the state has given $1.45 billion to the companies
that were involved in six projects that are now in production.
To date, those projects have produced 39 million barrels of oil.
He allowed it is fair to say that the state has "aided" them.
REPRESENTATIVE JOSEPHSON posited that if this were 1988 it would
be the equivalent of 19 days of Alaska North Slope (ANS)
production at 2 million barrels a day.
MR. ALPER replied yes and said 1988/1989 production was about 2
million barrels a day.
REPRESENTATIVE JOSEPHSON, regarding the $37.30 per barrel,
offered his understanding that if the net value was $74 during
the period in question, the tax rate would be applied against
half that because the credit is half the $74.
MR. ALPER responded that the great bulk of these credits were
refunded before there was substantial amounts of production. So
these were under construction - the companies had their capital
credits at the time and then their operating loss credits. It
is therefore hard to answer that question without getting into
project specifics because once a company is in production the
company's spending is far less.
2:00:39 PM
REPRESENTATIVE SEATON observed from slide 17 that previously the
state spent $1.45 billion on these six projects and that lease
expenditures for these projects were $5 billion. He asked
whether the credit support of 29 percent of $5 billion of lease
expenditures was in addition to the $1.45 billion.
MR. ALPER answered that the 29 percent is the $1.45 billion:
the companies spent $5 billion and the state paid them back
nearly $1.5 billion through the state's credit programs.
2:01:27 PM
MR. ALPER turned to slide 18, "Credit Cost in Perspective," to
discuss how much the state has spent and what it has received
related to Cook Inlet Refundable Credits [between fiscal years
2007 and 2015]. He reiterated that the state spent about $450
million on credits that went to six producing projects. Those
projects have produced about 56 million barrel of oil equivalent
(BOE), with the great bulk of that being gas. State spending
comes to $7.80 per BOE or about $1.30 per MCF of gas, with this
number decreasing over time if additional production comes on
from those same fields. The lease expenditures over that time
period for those companies involved in those six projects was a
little less than $1.1 billion. Although the per-barrel state
cost in Cook Inlet is less, the percentage of the cost is
higher, with the state supporting these projects by about 40
percent of the lease expenditures.
MR. ALPER drew attention to slide 19, "Credit Cost in
Perspective," to discuss the benefit of the Cook Inlet tax caps.
He said it is important to remember that there is a delta
between the statutory tax rate and the capped tax rate that is
tied to ELF. The Tax Division's analysis of that will be
available at the next committee hearing, he advised, but the
division estimates that the value of the tax cap to industry is
between $550 million and $850 million over the years 2007-2013.
This amount is the tax savings from not having to pay at the
statutory rate from Cook Inlet and instead paying at the capped
rate. Cook Inlet produces about 250 MCF of gas per day, so over
that seven-year period that is the equivalent of 640 billion
cubic feet (BCF) of gas or 106 million BOE. Cook Inlet also
produces about 10,000 barrels of oil a day (it was lower at the
beginning of the period and a little higher towards the end),
which over that seven-year period comes to 26 million BOE. The
total production of 132 BOE and the $700 million in taxes that
were not paid (using the midpoint of the division's estimate)
equals a tax savings of roughly $5.30 per barrel or $0.88 per
MCF. Adding together the credit support of $1.30 per MCF and
$0.88 per MCF equals $2.18 per MCF in benefit that the state has
given to incremental gas production in Cook Inlet.
MR. ALPER next addressed the specific sections of HB 247, saying
he will be providing additional modeling and explanation as per
the committee's request and that this is not a comprehensive
sectional. Moving to slides 21-22, "Section 7: Interest Rate
Compounding," he began reviewing the evolution of the interest
rate language in Senate Bill 21.
2:05:06 PM
REPRESENTATIVE TARR drew attention to the previous slides to
compare the per-barrel equivalent of $37 for the North Slope
credits and the per-barrel equivalent of about $13 for the Cook
Inlet credits. She asked Mr. Alper whether those numbers
surprised him or seemed about right in terms of relative
favorability for the North Slope versus Cook Inlet.
MR. ALPER replied that it was a little surprising to him.
However, he explained, there are oddities in the data that are
hard to parse out. For example, what is really being talked
about here is by company. There are companies in Cook Inlet
that are producing a lot of oil and gas and all of their
production might not have benefitted from credits, but all of it
fits into the total production that was worked into this
division factor. So, that might lead to some smaller apparent
numbers in Cook Inlet than the reality of what was actually
impacted by the state's contribution. It is hard to separate a
specific company into its component parts in different projects.
REPRESENTATIVE TARR, regarding Alaska's overall competitiveness
relative to other jurisdictions, pointed out that the focus is
often on Alaska's base tax rate rather than the aforementioned
perspective. In terms of comparing Alaska's favorability to
other jurisdictions as a place to invest, she asked whether any
other jurisdiction provides credits of almost $40 per barrel
equivalent or, as in the Cook Inlet, in the range of $13 to $15
per barrel equivalent.
MR. ALPER responded that comparative fiscal systems is a very
complicated art. He said DOR participated in, and drafted, the
document for the Competitiveness Review Board. The most recent
version of the board's report came out in February. It is very
hard apples to apples because every system is different, he
explained. Some jurisdictions count sales taxes and property
taxes differently than does Alaska. Other jurisdictions have
production sharing agreements. In general, it is hard to say.
Alaska's realm of refundable credits tied to expenditure is
relatively unique in the world. There are not a lot, if any,
other jurisdictions that do this to the degree that Alaska has.
2:08:07 PM
REPRESENTATIVE SEATON commented that he is trying to determine a
relative-value chain looking at the Cook Inlet tax caps. He
related that according to the radio recently, the Henry Hub was
less than $2 per MCF, yet Alaska is providing credits of $2.18
per MCF and the sales price [in Southcentral Alaska] is about $7
per MCF. He inquired as to where the $2.18 per MCF would
compare to the development and operational costs of producing
that gas as far as comparing the relative value of gas.
MR. ALPER answered:
We don't know the extent to which our credit regime
impacts the price of gas in Homer or Anchorage,
without question. We can't tell you if these credits
were to change how that might impact the market price
of gas. But, if these numbers are relatively accurate
... as the companies go through their own internal
economics and say, "we're spending this much money and
we're selling this much gas and we have a sales
contract," they are more or less able to build in the
assumption ... that they're going to be getting $1.30
in refunded credits on the average unit of gas and
that they're avoiding taxation of 88 cents on the
average unit of gas. So, if they're comparing that to
... an opportunity they have elsewhere in the country
that should be built into their equations. But I
can't say how any individual company might build that
into their internal modeling.
REPRESENTATIVE SEATON said his reason for trying to figure this
out is because at a hearing in Kenai this last interim, Hilcorp
testified that it has been able to reduce its [Alaska]
exploration and drilling costs to the same costs it has in the
Lower 48. He stated he is therefore struggling with why these
tax and credit supports are necessary with the price
differential that is being seen in sedimentary basins and retail
sales in Alaska versus the same comparisons in the Lower 48.
CO-CHAIR NAGEAK commented that maybe Representative Seaton will
come up with something in thinking about it.
MR. ALPER added that Representative Seaton is right that Cook
Inlet does have among the most generous fiscal regimes in the
world as far as how the state treats production and also has a
substantially higher price than other areas in the U.S.
2:12:02 PM
MR. ALPER returned to slides 21-22 and resumed his discussion of
the evolution of the interest rate language in Senate Bill 21.
He addressed why Alaska does not have compound interest in its
tax right now and noted that this is not just oil taxes but all
of Alaska's taxes. The general tax statute is where the
interest rates are, he explained, so someone with delinquent
cigarette taxes would be working from the same statutory
formulas. When Senate Bill 21 was in the other body, the idea
was to reduce the rate from 11 [percent] to a much smaller
number. When it passed the other body, Senate Bill 21 failed to
pass an effective date vote. This meant that all of the things
that changed a number on a date certain were not applicable and
it couldn't be said that on January 1 the interest rate would be
changed. For purposes of administration one wants to have an
even breakdown on when something begins and when something ends.
Consequently, when Senate Bill 21 came to the House Resources
Standing Committee in the 2013 session, multiple parts of the
bill received what is called applicability language, meaning
production before January 1, 2014, falls under "this" criteria
and after 2014 falls under "that" criteria. It was something of
a work-around to the inability to get a two-thirds vote in the
other body. When that happened, one of the sections to which
that was done was the interest rate section. Meanwhile the
compound language remained. There was a technical error in the
language that came out of the House Resources Standing Committee
that put back some of this 11 percent language that had existed
in prior statute, but the compounded language was there. He
noted that for every major bill, especially in the finance
committee, there is always a cleanup amendment with the chair's
name on it that fixes about a dozen things and that passes
unanimously. In this case, the cleanup amendment from the House
Finance Committee that intended to delete the 11 percent
language also deleted the compounding language, which [the
administration] believes was inadvertent. The sentence from
that amendment stated to delete from page 2, lines 23-25: ", or
at the annual rate of 11 percent, whichever is greater,
compounded quarterly as of the last day of that quarter". The
phrase, "compounded quarterly", means that the state is only
charging simple interest on all delinquent taxes across the
board starting January 1, 2014; that there is no more interest
compounding from that date forward. Restoration of compounding
is one of the things that would be fixed with HB 247.
2:14:42 PM
REPRESENTATIVE JOSEPHSON asked why Mr. Alper thinks this was
inadvertent.
MR. ALPER replied that every version of Senate Bill 21 had
compounding language, there was much debate and discussion about
reducing the interest rate and charging a much less onerous
rate. There was consensus, at least among those who supported
the bill, to do that. There was never any discussion of
eliminating compounding, it was never brought up in any
committee debate. It just showed up in the last amendment in
the last committee as a technical amendment that happened to do
that while it was also doing something else. He said he
therefore believes it was inadvertent because he found no
committee record to show that doing it on purpose was discussed.
2:15:34 PM
MR. ALPER continued his presentation. He moved to slide 23,
"Section 7: Interest Rate Increase," and stated that increasing
the interest rate is much more substantive. He explained that
the current interest rate of 4 percent is a rate that is 3
percent above the federal discount rate. The federal discount
rate changes quarterly and right now that rate is 1 percent. A
4 percent rate, he noted, could actually create incentives to
delay and contest tax payments. When the rate was 11 percent
and the Tax Division informed a company that it owed the state
$100 million, even if the company didn't want to, it would
typically pay it because if the appeals process went another two
years the company would owe 11 percent interest on that $100
million and the company didn't want to have pay the interest.
So the company would pay the money and then if at the end of the
appeals process the company won, the state would pay the company
back the difference plus the interest, so the company got the 11
percent back from the state. At 4 percent, the incentive
structure is flipped on its head a little bit and companies are
more likely to not pay contested taxes. The appeals process is
gone through with the money in the company's bank instead of the
state's because the company is generally able to earn more than
4 percent on its money; if the company loses at the end, it has
actually made money over the time. So, [the administration]
believes that somewhere in between 4 percent and 11 percent is
the right number. Importantly, in a low price environment where
the state is spending its savings to operate the state every
day, every dollar of tax that is not paid is one more dollar
that the state is taking out of its savings. Therefore, when
that tax is eventually paid, it should compensate the state for
what it would have earned had it remained in savings. The
number from the permanent fund's financial advising company,
Callan & Associates, is about 7 percent.
2:17:09 PM
CO-CHAIR NAGEAK requested Mr. Alper to provide correspondence to
tell the committee if it is actually happening the way he is
explaining it.
MR. ALPER responded that the permanent fund publishes an
estimate of returns and also publishes its actual returns as
time goes by. The permanent fund's most recent publication
shows an expected earnings rate for the next 10 years or so as
averaging about 7 percent per [year]. He said he will be happy
to keep the committee up to date as those numbers change going
forward. He clarified that the bill isn't tied to this number;
rather, the bill has a fixed number of 7 percent above prime,
which currently works out to 8 percent. That is an error on
[the administration's] part, it probably should say 6 percent
over the discount rate, which would be 7 percent. A formula
could be built that is somehow tied to the permanent fund's
estimated earnings or its actual earnings and have it change
every quarter. There would be a way to make an adjustable rate
within statute, it's just one step more complex. When putting
the bill together, [the administration] chose to go with a
simpler formula tied to currently expected earnings. But, he
advised, that might not fully compensate if there are broad
swings in expected earnings in years to come.
2:18:35 PM
REPRESENTATIVE JOSEPHSON understood Mr. Alper to be saying that
the intent was really to achieve 7 percent so the bill should
properly say 6 percent. He remarked that this seems like a
multi-million dollar question and inquired whether it is the
administration's preference that the committee adopt 6 percent.
MR. ALPER answered that his understanding is yes, the
administration's preference is to have a number tied to the
permanent fund's estimate, which is 7 percent. The bill, as
written, really says 8 percent, so the administration would
prefer 7 percent in that that is tied more closely to the
permanent fund's estimate.
2:19:16 PM
REPRESENTATIVE OLSON recalled that the last audit completed [by
the Tax Division] on the production tax was 2008. He requested
Mr. Alper to provide a breakdown of the audit amount due on the
interest for 2008.
MR. ALPER replied that the complete set of audits for all the
producers that paid taxes claimed - not all has been paid and
some is being contested - the division assessed $265 million, of
which about $110 million, or almost half, was interest. That
was based on the 11 percent compounded interest for the years
2008 to January 1, 2014. The interest rate did not change until
the effective date of Senate Bill 21. For the last year of it
the interest was a much smaller number.
REPRESENTATIVE OLSON understood it took six years to complete
the audit or to get to the point that the division is at now.
MR. ALPER confirmed that the 2008 audit was completed six years
after the taxes were received. He clarified that the division
was not working on that audit for six years; it was doing lots
of other things during that time, including the 2007, 2006, and
2005 audits. The division used all of the statute of
limitations available to it last year.
2:20:37 PM
REPRESENTATIVE TARR understood that Section 7 would change the
interest rate from 3 percent to 7 percent above [the federal
discount rate], so with the 1 percent that would make the rate 8
percent. She asked whether instead of the cap at 7 percent,
[the administration] would want it to be an either/or scenario,
so the language would give a cap of whichever is greater - 7
percent or....
MR. ALPER responded that this gets a bit beyond his expertise,
but explained that the 1 percent discount rate has some tie to
inflation. If there was a spike in inflation it would be
expected to have a spike in that rate and therefore a spike in
the interest that the state would be charging. Also, the
permanent fund would start seeing higher returns as well. Even
though the real returns might remain the same, the interest
embedded in all of its portfolio would be going up along with
inflation. That 7 percent number assumes about 4.5-4.75 percent
real returns offset by 2.5-2.25 percent expected inflation.
REPRESENTATIVE TARR remarked that it sounds like this is the
scenario that [the administration] would want to avoid if there
was a change in inflation because that would end up getting the
state close to the current scenario of 11 percent, which is what
[the administration] is saying is too high. She said it seems
that maybe the alternative would be to put this plus 1 or 7
percent, whichever is greater.
MR. ALPER responded that the language prior to the passage of
Senate Bill 21 was the higher of 11 percent or of 5 percent over
discount, which would be 6 percent in today's world. So, the
higher of calculation was eliminated and the 5 was replaced with
a 3. Representative Tarr is suggesting a minimum rate of 7 so
that if the state was going 6 above discount, and the discount
rate was below 1 percent for several years, which was an
historical anomaly. If it gets down below that, he said he is
personally not terribly worried about the difference between 6.5
and 7 in the returns. Rather, he is more curious about what
happens if the discount rate gets a lot higher and an 8 or 9
percent interest is starting to be seen; but, on the other hand,
there is a lot more underlying inflation and then the permanent
fund would be growing faster. Ideally they should be balancing
each other. He suggested that if trying to tie this to the
permanent fund, it might wise to find a more explicit way to tie
it to fund performance inside the state's assets.
2:23:49 PM
MR. ALPER resumed his presentation and brought attention to the
chart on slide 24, "Section 7: Interest Rate Increase." He
explained that the chart compares an interest rate calculation
on a standard $1 million assessment under current law and under
HB 247. He said the chart uses a smaller number because these
are general tax statutes, not oil and gas language, and for many
of Alaska's smaller taxes the assessments are much smaller. As
well, most of the general fund money that is going to come in as
a result of this change is going to be in these smaller numbers.
For the major oil and gas settlements and assessments that come
in, almost all go to the Constitutional Budget Reserve and not
to the general fund. If there is a $1 million assessment at the
end of the 2015 tax year it would be the end of second quarter
2017 by the time the Tax Division assesses it, so the company
would owe a year and a half's worth of interest. At simple
interest on $1 million, the total interest would be $60,000 at 1
percent per quarter or 4 percent per year. If an interest rate
of 8 percent is begun on the proposed effective date in HB 247
of July 1, 2016, and if from that date forward that interest was
subject to compounding, the net effect of status quo and changes
by the bill is $42,000 in additional interest to the state. If
instead of $1 million the assessment is $100 million, that
$40,000 becomes $4 million.
2:25:44 PM
REPRESENTATIVE OLSON inquired whether it is delinquent if the
division waits six years to do the audit.
MR. ALPER allowed it is not ideal business practices. He noted
that there have been a few extenuating circumstances, including
multiple tax changes and the implementation of a major software
rewrite that took everyone off task for a long time. The Tax
Division is doing everything in its power to catch up and move
off of that statute of limitations, which was something that he
inherited when he took the job. He said he is extremely proud
of the division's staff in the Audit Group and he believes that
in a year from now there will be substantial catchup.
REPRESENTATIVE OLSON recalled that a few minutes ago Mr. Alper
stated that the division used the statute of limitations fully.
MR. ALPER replied he is unsure what he just said that
contradicted that. He said the division did go up against the
statute of limitations, meaning it took all of the time allotted
to it to get the 2008 audits out. The 2009 audits are due at
the end of March. The audits were expected a month or two ago,
but the division was given a snafu in a court ruling that
affected some tariff rates from 2009; they need to get reworked
through the system and this threw a lot things back into the
work pool for a little while. He reiterated that 2010 and 2011
are going to be completed simultaneously and by a year from now
the division should be at least one full year off the statute of
limitations and by three years from now the division would like
to be three years off the statute of limitations.
2:27:27 PM
REPRESENTATIVE TARR understood Mr. Alper is projecting that a
year from now the division will be more within the three-year
range of the statute of limitation. She understood there is
likely some expected period of delay and that once the division
is caught up a two-year to three-year delay is reasonable.
MR. ALPER responded that three years, possibly four, is probably
reasonable. The old statute before the passage of ACES was four
years. It was extended two years because of the understanding
that the system got a whole lot more complex with the switch to
a net profits tax. The division's work plan right now is to be
five years off the statute one year from now, four years off the
statute two years from now, and three years off the statute
three years from now. The division is going to be doing two
years in one for the next two or three years. He said his hope
is that the division's resources hold out and that no strong
wrinkles get thrown at the division, but the division believes
that it will be able to do that. The new software in 2011 is
making an order of magnitude difference in DOR's ability to
handle data, as well as in DOR's ability to handle data for
every other tax type.
2:29:07 PM
MR. ALPER returned to his presentation and concluded discussion
of Section 7 by moving to slide 25, "Section 7: Interest Rate
Increase." He explained that while he created an example with
$42,000, it is difficult to quantify future revenue impact
because the division cannot know what is going to be assessed
and cannot know what is going to be delinquent because these
things are different every year in every tax type. The near-
term impact would be very small because the difference does not
start accruing until July 1, 2016, but increasing delta would be
seen between that point and years afterwards. In the production
tax, most of the impact is going to be in the Constitutional
Budget Reserve.
MR. ALPER moved to the graph on slide 26, "Section 12: Increase
Minimum Tax." He said Section 12 of the bill increases the
[gross] minimum tax from 4 percent to 5 percent. The grey line
on the graph, he explained, depicts the underlying Senate Bill
21 net tax of 35 percent after credits without any minimum tax.
Currently, that tax would go to zero at an oil price of around
$70 and fortunately the state benefits from the 4 percent
minimum tax depicted by the blue line. Current revenue looks
like the blue line until it crosses the grey line and the grey
line is to the right of the mark for roughly $80 a barrel. A 5
percent minimum tax is depicted by the orange line that is seen
above the blue line and which then crosses over with the grey
line. The delta of revenue is the wedge between the blue line
and the orange line.
2:31:01 PM
REPRESENTATIVE OLSON asked whether any models have been done for
prices up to $135 or $140 a barrel, given that the mistake a few
years ago was stopping at $95 a barrel.
MR. ALPER answered that [the division's] standard modeling is
now using $20 to $130 a barrel. There is now a giant table of
royalty production tax, unrestricted royalty, and restricted
royalty at all oil prices from $20 to $130 for the next 10
years. He said he will provide this table to the committee.
MR. ALPER returned to his review of slide 26 and noted that
while the grey line will continue to go up and larger numbers in
revenue would be seen at an oil price of $130, slide 26 is
illustrating the impact of the minimum tax and the minimum tax
is irrelevant at those prices. Slide 26 looks at the crossover
point between the minimum tax and the net profits tax, which
currently occurs at an oil price of around $80. If that minimum
tax were to be raised to 5 percent, the crossover would move to
a price of somewhere between $80 and $85. If the legislature
were to desire a very large minimum tax of 10 or 15 percent, a
much higher parallel line would be seen on the graph and the
crossover of the grey line might not happen until an oil price
of $100 or higher. The higher the minimum tax, the more a gross
tax paradigm is being introduced over the net tax system that
Alaska has.
2:32:42 PM
MR. ALPER drew attention to the illustrative model on slide 27,
"Section 12: Increase Minimum Tax." He said the model shows
how much money is being talked about if all of the oil were at
the same price and none of the oil was eligible for the Gross
Value Reduction (GVR). The model simplifies the whole system at
a range of prices between $20 and $100, and looks at the net
value (fifth row down) after a per-barrel cost of roughly $46,
which is the cost estimate for the current year in the Revenue
Sources Books. The calculated net value cannot be below zero.
The tax rate is 35 percent of that, and then there is a sliding-
scale credit. Bringing attention to the two lines for "Tax
After Credits" and "Minimum Tax", he explained that these are
calculated in parallel and the companies pay the higher of.
Where the Wellhead Gross Value is $10, the state is getting
$0.40; where the Wellhead Gross Value is $20, the state is
getting $0.80. When the Wellhead Gross Value is $60, the state
is getting $2.40 and the calculated tax after credits is only
$0.40. But, at an oil price of $80, the minimum tax is $2.80
and the calculated tax jumps up to $3.90 because that is where
the crossover is. The revenue from a 5 percent minimum tax
would increase by $16 [at an oil price of $20] on up to $96
million at an oil price of $70. At an oil price of $80 it
[drops to no increase]. That roughly parallels the graph seen
on slide 26. The number in the fiscal note is $50 million, a
number that roughly lines up with DOR's forecasted revenue.
MR. ALPER turned to the bar graph on slide 28, "Section 12:
Increase Minimum Tax," depicting the revenue impact of raising
the minimum tax from 4 percent to 5 percent. He explained that
while slide 27 was a more illustrated and calculated model, the
graph on slide 28 is closer to the actual revenue. This is
because the graph lines up with the state's forecasted price of
oil, the forecasted production, and how the specific
circumstances of the state's individual producers interact. If
the price of oil remained at $30 for all of fiscal year 2017,
the proposed 5 percent tax would only get the state $20 million.
But if the price of oil were to rise to $50, the 5 percent tax
would get the state $50 million. [At a price of $75, the 5
percent tax] would peak at about $80 million and then drop off.
2:35:18 PM
MR. ALPER moved to slide 29, "Section 17(b): Strengthen the
Minimum Tax," to review which credits can break through the
floor under current law. He explained that the slide depicts
the 4 percent tax floor and underneath that floor is the
"basement" of zero tax. He discussed what is and is not limited
by the floor. Limited by the floor is the sliding-scale per-
barrel credit specifically on non-GVR-eligible oil, meaning
legacy oil, and this old oil is limited by the floor. All other
credits under current law can go below the floor and include:
the Net Operating Loss Credits, Per-Barrel Credits on GVR-
eligible oil (new oil), the Exploration Credit that is scheduled
to sunset, and the Small Producer Credit. All of these credits
are being used to reduce tax payments below the minimum tax, he
pointed out, and in many circumstances are being used to reduce
tax payments to zero.
CO-CHAIR NAGEAK requested Mr. Alper to further explain that.
MR. ALPER replied that each one of these is a slightly different
situation. He posed a scenario of a small producer producing
less than 50,000 barrels a day that is a junior partner in a
major oil field that pays at the legacy rate. In other words, a
company that owns a smaller percentage of Prudhoe Bay. This
company's profits would be subject to the 4 percent floor just
as this company's larger partners would be paying at the 4
percent floor. However, this small producer would earn a credit
of up to $12 million that could be subtracted off the top of its
taxes. If this company's minimum tax was less than $12 million,
this company would pay the state zero tax. Mr. Alper posed
another scenario of a small producer operating a newer field on
the North Slope. This company would pay a tax on its production
tax value and would be eligible for the GVR, which tends to
reduce the company's liability, but if the oil price is high
enough the company will have a tax liability. However, the
company's $5-Per-Barrel Credit can offset the company's taxes
all the way down to zero and, if it doesn't, the company could
also be eligible for the Small Producer Credit. So, at a wide
range of prices it is reasonable to say that the smaller
producers with the smaller fields can generally offset their
taxes all the way to zero between the $5-Per-Barrel Credit and
the Small Producer Credit.
2:37:56 PM
REPRESENTATIVE JOSEPHSON noted that industry got a legislature
to pass Senate Bill 21, which then went to a referendum and
industry prevailed in the referendum. He surmised that this may
not have gotten much attention in the debate that occurred in
August 2014 because it is complicated. He inquired as to
whether the "basement" issue was vetted by the legislature in
committee in 2013.
MR. ALPER responded that this condition is not a by-product of
Senate Bill 21, but rather a pre-existing condition going back
to Alaska's Clear and Equitable Share (ACES) and the production
profits tax (PPT) that came before ACES. Senate Bill 21 created
the limited hardening of the floor: the legacy producers with
the sliding-scale credit cannot use that credit to go below the
floor. The comparable large credit earned by the legacy
producers before 2013 was the 20 percent Capital Credit and that
could be used, and was used, to go down below the floor. The
other reality is that until 18 months ago the minimum tax was an
academic conversation. The price of oil had not gone into the
territory in modern history where the minimum tax came into play
in any material way, modern history being since Alaska has had a
net profits. The minimum tax is now suddenly relevant and is
being discussed in greater detail because that is where the
state is getting its revenue from, whereas during the referendum
debate it was not part of the conversation in any material way.
2:39:57 PM
REPRESENTATIVE OLSON said the other major variable that is still
not being talked about is the lack of production over the years.
When he was first sworn into office 12 years ago the price of
oil was $30, but a major difference from now is that a million
barrels a day was going through the pipeline.
MR. ALPER offered his belief that Representative Olson is right
that production has dropped by half during the last 12 years.
He further stated that $30 then is different than $30 now and
that the cost of producing those barrels and the tariff for
moving them down the pipeline are also higher than they were. A
lot of things are working against the state in addition to
reduced production. Many of these incentives were put in place
to do what they could to reverse or at least slow that decline.
The decline has continued. There is geology in place that he
cannot speak to, but there are other people who can.
2:41:15 PM
REPRESENTATIVE TARR recalled that the goal when Senate Bill 21
was passed was to see 100,000 new barrels of production. She
asked what the current Revenue Sources Book forecasts for
production increase.
MR. ALPER replied he doesn't know the numbers off the top of his
head, but said that a number of fields are under development and
under evaluation. He explained that DOR considers the oil that
is currently being produced and adds the oil that DOR believes
to be happening. The department applies probabilities and risk
factors to the oil that is under development and under
evaluation. The Mustang, Nuna, and Point Thomson projects, he
reported, are presumed to be happening within the period studied
in DOR's forecast. He offered to provide the committee with a
comprehensive list of the fields and projects that are in DOR's
forecast.
REPRESENTATIVE TARR said she would like to receive that list.
2:42:59 PM
MR. ALPER resumed his presentation. He brought attention to
slide 30, "Section 17(b): Strengthen the Minimum Tax," and
specified that current law allows all credits to go below the
floor with the exception of the sliding-scale per-barrel credit.
[The administration] is seeking to change the law under HB 247
so that four distinct different credits also cannot reduce taxes
below the floor. The bill would make it so that: small
producers would have to pay the minimum tax level; new GVR-
eligible fields would pay at the minimum tax level; the Net
Operating Loss Credits that are carried forward could not be
used to reduce payments below the minimum tax; and Exploration
Credits, if used against liability, could not be used to go
below the minimum tax.
MR. ALPER turned to slide 31, "Section 17(b): Strengthen the
Minimum Tax." He advised that three very different policy
questions are before the committee and allowed that members
might have a different opinion and a different desired result on
each one. Several things are being done with the minimum tax,
he explained. First, regarding the Small Producer Credit, the
question being asked is whether everyone, not just the major
producers, should pay at the minimum tax level. Under current
law, only the large producers pay that floor. Second, regarding
the Per-Taxable-Barrel Credits for "new" oil, the question being
asked is whether the tax on production from new fields should be
allowed to go to zero. The third question is whether a major
producer that carries a loss forward into the next year should
be able to use that Net Operating Loss Credit to reduce its
payments below the floor or should the company be forced to pay
at the minimum tax level and then continue to carry that credit
forward into a future year when it has more tax liability. And,
if it is made so that the net operating loss cannot be used
against minimum tax payments, the question is whether that
should be made retroactive to January 1, 2016, as proposed in HB
247. Mr. Alper reported that at least one major producer showed
a loss for 2015 and will be offsetting minimum tax payments
beginning this month to the level of zero by using its Net
Operating Loss Credit from calendar year 2015 to offset minimum
tax payments from 2016.
2:45:43 PM
MR. ALPER drew attention to the table on slide 32, "Section
17(b): Strengthen the Minimum Tax," to illustrate how the GVR-
eligible per-barrel credits [can reduce taxes below the minimum
tax] at a West Coast oil price of $80. He explained that the
table includes two parallel calculations of how the minimum tax
treatment applies under current law to legacy oil and to GVR-
eligible new oil. At a price of $80 and a transportation cost
of [$10], the wellhead value (also called the gross value at the
point of production) is $70. The minimum tax is tied to the
gross calculation, not to the market price. The lease
expenditure cost of $36 is subtracted from the wellhead value,
arriving at a net value of $34. If that oil is subject to the
20 percent Gross Value Reduction (GVR), then 20 percent of the
$70 gross is $14; this $14 is then further subtracted from the
net value of $34, arriving at a net value after GVR of $20.
This is where the disparity is seen: the net value after GVR is
$34 for legacy oil and is $20 for GVR-eligible oil. The tax is
then calculated by taking 35 percent of the net value after GVR;
so the tax before credits is $11.90 on the legacy oil and is $7
on GVR-eligible oil. For legacy oil the Per-Taxable-Barrel
Credit is a sliding-scale credit; at a price of $80 this credit
reaches its maximum of $8, which reduces the base production tax
after credits on the legacy oil to $3.90. For the GVR-eligible
oil, the Per-Taxable-Barrel Credit is $5, which reduces the base
production tax after credits to $2.00. At a price of $80, the
minimum tax calculation is $2.80. The tax of $3.90 paid on each
taxable barrel of legacy oil is above the minimum tax. However,
the tax of $2.00 paid on the GVR-eligible oil is below the
minimum tax; this is because under current law the minimum tax
does not count for the GVR-eligible oil. Under HB 247, a
producer in that circumstance would be forced to pay at the
level of $2.80.
2:49:17 PM
REPRESENTATIVE JOSEPHSON surmised that bringing GVR-eligible oil
up to the legacy rate is the parity Mr. Alper was talking about.
MR. ALPER responded correct. He pointed out that because the
taxes are higher, the legacy oil is not impacted by the floor at
$80, but the GVR-eligible oil is. If the floor were in place,
the GVR-eligible oil would be paying $2.80, whereas under the
current statutory rate the tax on that oil is $2.00.
2:49:48 PM
MR. ALPER resumed his presentation. He moved to slide 33,
"Section 17(b): Strengthen the Minimum Tax," and did the same
calculations at a price of $60. At this price, he noted, the
taxable net value goes down to $14. At a tax rate of 35 percent
the base production tax before credits is $4.90 for legacy oil.
The full value of the $8 per barrel credit is partially lost
when applied because the tax goes to zero. The minimum tax then
comes into play: at 4 percent of the wellhead value, which is
$50, the minimum tax is $2.00. So, under current law at a price
of $60, the tax on legacy oil is $2.00 per barrel. For GVR-
eligible oil, the net value of $14 is reduced by the 20 percent
Gross Value Reduction, reducing the net value to $4.00. At a 35
percent tax rate the tax before credits is $1.40. The $5-per-
barrel credit reduces that tax to zero. So, under current law,
GVR-eligible oil is paying a tax of zero. Under HB 247, GVR-
eligible oil would pay [a minimum tax] at the same rate as the
legacy oil - 4 percent of the gross or $2.00 a barrel.
MR. ALPER brought attention to slide 34, "Section 17(b):
Strengthen the Minimum Tax," to discuss the portion of Section
17(b) that is related to the Net Operating Loss (NOL) Credit and
would affect the major producers. This provision would prevent
companies from applying a Net Operating Loss Credit against the
minimum tax. The statutory definition of a loss is when a
producer's total lease expenditures for the year exceed the
gross value [at the point of production]. In plain English,
this is when a producer has negative net income based on Alaska
law. He pointed out that this is for a calendar year, not a
fiscal year. At around $50 and below, some Alaska producers
start experiencing operating losses.
2:51:53 PM
MR. ALPER turned to the tables on slides 35-36, "Section 17(b):
Strengthen the Minimum Tax," to review how Net Operating Loss
(NOL) Credits are earned and used. He explained that the table
on slide 35 is a stylized reality for the aggregate of all of
Alaska's producers for calendar year 2015. The table depicts
each month of the year and how the production tax value, meaning
after all expenses, is calculated. The negative numbers are
shown in grey. Those numbers cannot really be below zero when
calculating them, he explained, but they are calculated when
dealing with Net Operating Loss Credits. This leads to negative
taxation or tax calculations that would be negative if these
operating losses were calculated into the tax. What actually
happens is that the minimum tax is charged and from the minimum
tax comes certain credits. The State of Alaska's actual tax
payments for calendar year 2015 roughly equals the bottom line
on slide 35 - about $187 million. Adding up all of the negative
numbers on the production tax value line will show that the
companies lost $183 million in Alaska last year. So, at the
2015 Net Operating Loss Credit rate of 45 percent, this $183
million loss translates into a Carried-Forward Annual Loss
Credit of $82 million.
2:53:25 PM
MR. ALPER moved to slide 36 to explain what happens to the
Carried-Forward Annual Loss Credit in 2016 if the price of oil
goes to $40 and stays there through December. He noted that the
second to last line on the table is the application of the
carried-forward credits. The third to last line should be the
companies' minimum tax payment. However, the companies are
subtracting the carried-forward credits from the minimum tax
payment and paying zero tax all the way through until September.
By September the companies have used up all their Operating Loss
Credits and are then left with only paying the amount that is in
the last row of the table for the months of October, November,
and December - a total of about $27 million. So, the state only
gets the minimum tax for the last three months out of the year.
More importantly, if these trends continue, and these are well
below the state's forecast, the companies would show a $1.2
billion loss in 2016, which at the credit rate in play at the
time would result in over $400 million in Carried-Forward Annual
Loss Credits. If these low prices continue for another couple
years, that's another two years of zero tax revenue because the
companies would be able to completely offset any minimum tax
payments for two years into the future until they have run
through the $400 million in credits and possibly earning
additional credits along the way. Essentially, the state would
not start seeing any revenue until there is substantial cost
recovery. It is being proposed under HB 247 that this credit
cannot reduce the minimum tax payments. Even if the companies
are losing money, [the administration] wants them to pay the 4
percent gross tax because the state should be getting at least
something. Those credits would then be carried forward and used
in a future year once there was adequate recovery in the price
of oil and adequate tax liability that the companies would be
able to offset it with their credits.
2:55:31 PM
REPRESENTATIVE OLSON inquired whether the companies are doing
anything illegal or unethical in their calculations.
MR. ALPER answered that, to his knowledge, they are not. The
companies are following the law and paying and filing their
taxes the way Alaska's rules and regulations instruct them to.
REPRESENTATIVE OLSON remarked that the companies are paying
approximately 90 percent already and now the state is going to
go after the other 10 percent.
2:56:10 PM
MR. ALPER recommenced his presentation, stating that slide 37,
"Section 17(b): Strengthen the Minimum Tax," talks about the
previous two slides. He said the information on slides 35-36
shows how those operating losses would be used to carry forward.
He reiterated that the net operating loss for calendar year 2015
is $183 million, this loss would generate a credit of $82
million, and this loss credit would start offsetting 2016
minimum taxes beginning in January. If oil prices were to rise
to $40 and stay at that level through all of calendar year 2016,
[the North Slope producers] would see a loss of over $1 billion.
That loss would stack up yet another $400 million loss credit
that would be applied beginning in January 2017. The changes
proposed by HB 247 would not take the credits away from anyone,
he stressed. An Operating Loss Credit is something that has
value and is wanted to be carried forward. He advised that
there are other changes to Operating Loss Credit payback
elsewhere in the bill. He said [the administration's]
expectation is that these would be deferred, kicked forward, to
some future year when the state had more money and higher tax
revenue coming in from production tax. Those Operating Loss
Credits would be used then to reduce tax payments and take money
from the state in the future when it has money instead of in the
present when the state doesn't have money.
2:58:36 PM
REPRESENTATIVE TARR recalled that the negative scenario depicted
on slide 36 was not contemplated during consideration of Senate
Bill 21. She noted she was on the committee at that time and
feels that if this very low price environment and the
consequences had been contemplated the committee may have done
something differently. She asked whether there are other
calendar years that mimic what is being shown on slide 36.
MR. ALPER replied that he can provide other calendar years to
show stylized how it worked. In none of those years was there
an issue of minimum tax. He recalled that there was a price
collapse in the early months of 2009 and therefore that might be
a year to provide the committee. The ACES regime was in effect
at that time. He stated that these issues are not unique to
Senate Bill 21 and said this is not the appropriate time to cast
dispersions at the current tax regime. These are issues that
have been embedded in Alaska statute since switching over to a
net profits regime. They happened to have come to the forefront
now, not because of Senate Bill 21, but because oil prices have
collapsed to such a degree that operating losses are starting to
be seen in the industry.
REPRESENTATIVE TARR requested Mr. Alper to provide the committee
with [the 2009] calendar year for comparison purposes.
MR. ALPER agreed to do so, and added that he would continue his
presentation when he was next before the committee [on 2/24/16].
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB247 ver A.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB247 Sectional Analysis.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB247 Fiscal Note - FUNDCAP-OIL & GAS TAX CREDIT FUND-2-1-16.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB247 Fiscal Note - DOR-TAX-2-1-16.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB 247 Production Tax Credits FY07-FY25 Excel Table_Figure 8-4_Fall 15 RSB.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB 247 Oil Credit Bill - Key Features 2-2-16.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB 247 - HSE RES DOR 1st Presentation- OG Credit Reform Bill 2-2-16.pdf |
HRES 2/5/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM |
HB 247 |
| Senate Oil & Gas Tax Credit Summary Report - December 1, 2015.pdf |
HRES 2/22/2016 1:00:00 PM |
|
| HSE RES 2.12.16 Professor Gunnar Knapp's ISER Rpt Comments on HB 247.pdf |
HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM |
HB 247 |
| HSE RES 2.12.16 ISER economic impacts study-preliminary conclusions.pdf |
HRES 2/22/2016 1:00:00 PM |
|
| HSE RES DOR Response to Representative Seaton - 1 7 16.pdf |
HRES 2/22/2016 1:00:00 PM |
|
| HSE RES DOR Response to Representative Seaton - 2 19 16.pdf |
HRES 2/22/2016 1:00:00 PM |
|
| HSE RES 2.22.16 DOR 2nd Presentation - HB247 - Fiscal Details Part 1.pdf |
HRES 2/22/2016 1:00:00 PM |
HB 247 |
| HSE RES DOR Response to Representative Seaton - 1 7 16.pdf |
HRES 2/22/2016 1:00:00 PM |
HB 247 |
| HSE RES DOR Response to Representative Seaton - 2 19 16.pdf |
HRES 2/22/2016 1:00:00 PM |
HB 247 |