Legislature(2015 - 2016)BARNES 124
02/26/2016 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
1:02:52 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."
1:03:40 PM
JANAK MAYER, Chairman & Chief Technologist, enalytica, and
consultant to the Legislative Budget and Audit Committee, noted
he is before the committee to advise on matters relating to oil
and gas, particularly commercialization and fiscal systems.
Drawing attention to his PowerPoint presentation entitled,
"IMPACT OF HB 247: NORTH SLOPE ASSESSMENT," he continued his
analysis of the projected impacts of HB 247 on the oil and gas
industry in Alaska, which he had begun on 2/25/16, 1:00 p.m.
MR. MAYER turned to slide 13, "MONTHLY GROSS MIN CALCULATION:
NEUTRAL OR TAX HIKE." He reminded members that at the close of
yesterday's presentation the committee was looking at the impact
of the bill's proposed change to move from an annual to a
monthly reconciliation of the tax system in terms of the impact
of various credits, particularly the Per-Barrel Credit, the
Small Producer Credit, the Net Operating Loss (NOL) Credit, and
how those credits interact with the hard gross minimum floor.
He explained that the top row of the chart on slide 13 depicts
this calculation being done on an annual basis [for calendar
year 2014]. The calculation begins with the Alaska North Slope
West Coast (ANS WC) average annual price [$97.74] from which is
subtracted the transportation cost, the operating expenditures
("opex"), and the capital expenditures ("capex") to arrive at
the production tax value (PTV) per barrel [$47.73]. The 35
percent net production tax rate is multiplied against the PTV
[arriving at $16.71], from which is subtracted the sliding Per-
Barrel Credit, which is $0-$8 for an established producer on the
North Slope and which was $8 in the year 2014, to arrive at a
net production tax of [$8.71] per barrel. The $8.71 is higher
than is the 4 percent gross floor [$3.49], so $8.71 would be the
tax paid per barrel using the annual system of current law.
MR. MAYER explained that if the calculation was to instead be
done monthly as proposed in HB 247, then in a year like 2014
when there is a lot of volatility in the oil price, each of the
first 10 months would have used the net tax calculation, but the
final 2 months of the year when oil prices fell to $77 and $60 a
barrel would have used the 4 percent binding gross because the 4
percent gross calculation is higher than the net calculation.
The net effect of a monthly basis would be to raise the amount
of production tax per barrel from [$8.71] to [$9.31]. When this
tax is multiplied by the number of taxable barrels on the North
Slope, it would result in about $100 million in additional tax
that would be taken in by switching from an annual to a monthly
calculation. He described this as a tax hike that happens
because the proposed change is a situation of "heads I the
sovereign win, tails it's a draw". If there is no volatility,
the two things are the same; the more there is volatility in the
oil price, the more this proposed change would work in the
sovereign's favor and the taxpayer's disadvantage.
1:07:17 PM
MR. MAYER pointed out that because the calculation would be done
each month it would mean that each month a taxpayer must really
understand what its costs are for that month and do that entire
calculation. It would be almost like the taxpayer filing its
tax return monthly rather than annually. Some of that would be
trued up at the end of the year, but a taxpayer would need to be
very certain of not understating its costs for the month. The
way the language is written, the sum of the taxpayer's total
cannot be higher than the sum of its monthlies. So, if it turns
out at the end of the year the taxpayer's costs were higher,
those credits would essentially be lost to the taxpayer forever.
Mr. Mayer further pointed out that this analysis is focused on
the sliding Per-Barrel Credit of $8 in the world of the large
incumbent oil producer. However, the floor hardening in HB 247
would apply to both incumbent and new producers by making the
floor binding on oil that is eligible for the Gross Value
Reduction (GVR), as well as binding in that the Net Operating
Loss Credit and the Small Producer Credit could not be taken
away from the floor, which would be a substantial impact on [new
producers].
1:08:57 PM
REPRESENTATIVE HAWKER understood that the numbers on slide 13
are the actual numbers as reported for the year 2014.
MR. MAYER confirmed that to be correct, broadly speaking. He
explained it is a very high level approximation that essentially
treats the North Slope as if it were one uniform taxpayer. The
cost numbers are also fiscal year (FY) 2014, whereas the tax
year is a calendar year; so, it is not a perfect match there.
Those are actual numbers to the extent that a reasonably
accurate picture can be created through "back of the envelope,
high level numbers" versus individual taxpayer numbers.
REPRESENTATIVE HAWKER noted that Mr. Mayer's calculation of an
additional $100 million in liability is basically the same
number as presented by Mr. Alper, Director of the Tax Division.
He requested Mr. Mayer to explain how and why the operating
costs and the capital expense costs somehow managed to be the
same number for every single month.
MR. MAYER replied that in this case it is taking the annual 2014
numbers and spreading them in even proportion across the year.
In practice as a taxpayer there would be variation and one
difficulty as a taxpayer would be the need to understand month
by month what those are. The taxpayer would want to be careful
to err on the conservative side and overstate them and then deal
with that overstatement at true-up rather than be worried about
understating them, in which case the credits that the taxpayer
potentially forewent because of interaction with the floor would
never be able to be gotten back.
REPRESENTATIVE HAWKER said that is not where he was going. He
asked whether the state requires in the calculation that the
taxpayers use a monthly estimate based on a monthly portion of
what the taxpayer estimates its annual expenses to be.
Therefore, he surmised, it would be mirroring the way the tax
calculation actually works in statute.
MR. MAYER, after confirming that Representative Hawker is saying
that the calculation is supposed to take the annual estimate and
divide it by 12, answered correct.
REPRESENTATIVE HAWKER concluded, then, that the numbers seen on
a monthly basis here do not reflect the amount that was actually
being paid by the industry in that month.
MR. MAYER replied that the costs in the chart are simply costs
from the Revenue Sources Book spread evenly across the year, and
not actual data.
REPRESENTATIVE HAWKER asked whether that is not the way the
calculation is done within state statute.
MR. MAYER responded that that is his understanding....
REPRESENTATIVE HAWKER observed that Mr. Alper is nodding, but
said he is going to miss his whole point because he cannot
validate it here.
1:11:59 PM
REPRESENTATIVE JOSEPHSON asked whether Representative Hawker is
saying that if the opex and capex actually reflected what was
really going on in the month, then the tax depicted in the
second to right column would be different.
REPRESENTATIVE HAWKER answered that that is exactly his point,
it would be substantially different.
REPRESENTATIVE TARR surmised that because the ANS WC price is
different on a monthly basis, the chart illustrates some of the
variation in the per-barrel price but not a true reflection of
opex and capex.
MR. MAYER replied that the point being made is that there are
various elements of inter-year volatility in the system, price
and costs being two of those elements. He explained that a big
part of the reason for doing an annual calculation is to reduce
that volatility in the same way a person calculates his or her
entire income over the year rather than what was earned in a
given month. Rather than having a volatility smoothing of an
annual calculation, he advised, this proposed change would
assess month by month and that can only work in the sovereign's
favor. Essentially it can only ever be a tax hike in the event
of price volatility.
1:14:15 PM
MR. MAYER moved to slide 14, "GVR RAISES NOL CREDIT ABOVE 35% OF
ACTUAL LOSS," and specified that HB 247 also raises the question
of how the Gross Value Reduction (GVR) for new oil interacts
with the Net Operating Loss (NOL) Credit. He advised that the
administration has raised an important and valid point that is
useful to debate. Alaska's Clear and Equitable Share (ACES)
[passed in 2007, House Bill 2001, Twenty-Fifth Alaska State
Legislature] had a hugely varying rate of government support,
from 45 percent to over 100 percent. It could vary wildly month
by month depending on prices and costs and all the rest. During
consideration of Senate Bill 21 [passed in 2013, Twenty-Eighth
Alaska State Legislature], the thinking was to have a uniform 35
percent support for government spending in all circumstances.
The Gross Value Reduction was a way to reduce the effective tax
rate that new oil pays by artificially lowering the way the tax
systems treats the value at the wellhead. Because everything in
the calculation flows on from that, it also affects the way the
net operating loss is assessed.
Mr. Mayer demonstrated how the GVR works by drawing attention to
the scenario depicted on slide 14 for an oil price of $30 under
Senate Bill 21. From the price of $30, the transportation cost
of $10 is subtracted to arrive at a $20 gross value at the point
of production (GVPP) before factoring in the GVR. The 20
percent GVR is then subtracted to arrive at a GVPP of $16 after
GVR. The opex [$18] and capex [$18] are then subtracted from
the $16 to arrive at a production tax value (PTV) of a loss of
$20. Had there not been a Gross Value Reduction the actual loss
at the wellhead would have been $16. The tax system would
recognize the $20 loss. That is important at higher prices, and
at all prices, in reducing the effective tax rate. The purpose
of the Net Operating Loss Credit was to say 35 percent support
for government spending at all prices. Because it is not
looking at the actual loss, but rather is looking at the
production tax value per barrel, the effect is to overstate the
loss. So in this scenario, instead of a credit of 35 percent of
the actual production tax value it is 44 percent of that actual
number, because it is based on the number after the GVR has been
applied.
1:18:43 PM
MR. MAYER continued discussing slide 14. He said the aim of the
policy direction set under Senate Bill 21 was to have a uniform
35 percent support of government spending in all circumstances.
Between passage of Senate Bill 21 and now, a number of
investments have been made under the tax regime in place. Any
change such as this would seriously impact those investments.
If it is thought that this is a substantive matter of policy
that should be addressed, the question of how to address that
and the timing and how that applies and when that applies then
becomes critical. This is because numerous investments have
been made under certain assumptions and spending is actually
happening today. Those assumptions included modeling this
exactly as it was, and those investments would be impacted by
any change like this. It is one thing to look at this and ask
whether this was what was intended and should this at some point
change. And then another to think about if that should change,
how that should be enacted, what the applicable timeframe is,
and who is impacted when. Those are all very important
considerations since any change will substantially impact the
economics of ongoing investment.
1:20:19 PM
REPRESENTATIVE HERRON inquired whether it could be created where
the current credit of 35 percent stays with projects that are in
play, and that any future projects would be under a different
tax regime such as that under HB 247.
MR. MAYER responded that there are ways of achieving exactly
that. For instance, small producers currently on the North
Slope could continue to receive the Small Producer Credit and it
could be made so that this credit is not open to new entrants.
1:21:08 PM
REPRESENTATIVE SEATON asked whether Mr. Mayer is aware of anyone
who, during the discussion of Senate Bill 21, was planning a
project and was counting on being able to somehow leverage more
than the 35 percent.
MR. MAYER allowed that this is an excellent question. He said
that when he was first made aware of this issue he was shocked
and surprised because he thought it was very clear amongst
everyone that the intent was 35 percent. When he went back to
his own models he found that they produced exactly the regime as
it exists, which is in effect a higher level of support for
government spending - when the gross value at the point of
production is tweaked, the rest of this falls out. This
oversight is not the result of legislatively polar or a strange
bit of drafting, he said, but rather that it is a complicated
system and when a change is made in one place it affects
numerous things further below. So, whether it was himself, the
administration's consultants, or anyone else building models at
the time, or someone assessing an investment in the meantime,
the pieces of the system would be assembled in a model and the
settings would be created. The economics that flowed out as a
result would then be assessed. In the case of a company
assessing a project, the company would assess things based on
what it sees. While assessing the economics, a company is not
necessarily asking what was the implicit level of government
support for spending and whether that was what the legislature
intended. He said he firmly believes that anyone assessing
their economics on a project on which they took sanction was
doing it on the system that existed and not necessarily on the
basis of legislative intent.
1:23:11 PM
REPRESENTATIVE SEATON surmised that none of the consultants who
were advising the legislature at the time spotted this and that
no one testifying on the projects that were under development
spotted this. If someone had spotted this they might have
figured that they could not address it or could tweak it in and
not understand the legislature's discussions. He said he does
not think [industry] would be surprised if the legislature came
back and assessed the system that it thought it was passing at
the time. He added he is not suggesting that anybody knew about
it at the time and that when talking to legislators about the
system the companies were being forthright in telling
legislators what they thought it did, what the support was, and
what the government take was.
MR. MAYER further suggested that when a company is evaluating a
project to take final investment decision, a lot of things are
being looking at, such as net present value, internal rate of
return [IRR], long-term cash flow, and various risk and non-risk
scenarios. He said he would be very surprised if among those
metrics would be the question of the implicit rate of government
support for spending. In that sense he would be very surprised
if a company assessing this would think there was something a
bit odd here.
1:24:54 PM
REPRESENTATIVE JOSEPHSON offered his understanding that the
prior administration did identify this problem of going under a
tax rate of 4 percent as well as under a 0 percent effective
tax. Two things strike him, he said, the first being that
everyone he has spoken to says that the state is making slightly
more revenue now than under the prior regime. Second, what he
is sensing from Mr. Mayer's testimony, and given that the prior
administration understood this potential problem, is that no one
foresaw this level of [low] price so it was not discussed.
MR. MAYER answered that the point on slide 14 is not about the
gross floor and whether one can go below that. He recounted
that it was a deliberate policy decision to say that because
gross taxes are effectively distorting [the state's] investment,
a binding 4 percent floor was not wanted on new production. A
deliberate and thought-through decision was made to make it
binding on the legacy oil because that is where the revenue for
the state needs to be protected, but on new investment it was
wanted to minimize the distorting impact and so that floor was
not made binding in the same way as on the legacy fields.
REPRESENTATIVE JOSEPHSON concurred.
1:26:57 PM
MR. MAYER continued his response to Representative Josephson.
He noted that in 2013 [as a consultant to the legislature while
employed with PFC Energy Oil and Gas Research Acquisition
(PFC)], he presented analyses over a range of prices from $40
per barrel to $160, the same range he is providing today. The
reason for not going below $40 was because, frankly, the math
did not really work below $40 a barrel. At $40, he explained,
there is no divisible income to split and metrics like
government take do not mean anything as they are all infinite.
When sitting before the committee three years ago as the initial
discussions around Senate Bill 21 were starting, he was asked to
prepare several slides around what PFC saw as the short-term and
long-term likely floor price for Alaska North Slope West Coast
(ANS WC) crude. Seen at that time was unprecedented growth in
North American onshore production, as well as the Organization
of the Petroleum Exporting Countries (OPEC) and Saudi Arabia
being increasingly unable to manage the market in the way they
had in the past. There was rising production from Iraq where
the question of what happened with Iran was unknown. All of
these things, combined with a weak global outlook, meant that
[PFC] saw more risks to the downside than the upside. When
asked what a reasonable floor price might be, [PFC] said in the
short run it could see scenarios of strong oversupply and
failure of management by OPEC, which could reduce prices to $30
a barrel, and that in the long run there would be a strong
supply response, particularly from North America, were that to
happen. In the long run, [PFC] could see somewhere in the range
of $50-$70 for the long-term floor price. A big part of the
reason for some of the testimony he gave back then was that much
of the debate in those times focused on when the price was $140-
$150 a barrel, how much would the state be giving away, and
should the state be taking more. He recalled advising in his
testimony back then, "Remember, the commodity business is
cyclical; remember that times are high now but there will be low
times as well and more than anything else you need a system that
is capable of protecting the state's interests in those times
and that if you have to fight about what are you giving away at
$150 a barrel that's a really nice problem to have." Now, while
at the bottom of the cycle, he said he offers this advice:
Remember, again, take that long-term view. This is a
cyclical business and the problem now is how do you
maintain ongoing investment even when times are rough?
And yes, one needs to protect the state's interest
and, yes, one needs to do what one can to plug a very,
very difficult fiscal hole. But if one does that at
the expense of changes in fiscal terms that say to
investors, "Sorry, this isn't the stable jurisdiction
you were hoping for," that potentially has a long-term
cost that one needs to think seriously about.
1:30:09 PM
REPRESENTATIVE JOSEPHSON posed a scenario in which there is a
defined time for when HB 247's reforms would take effect and
asked whether even leasehold investors could say that they
expected X regime and now the state is giving them Y regime,
even though the lease itself is the birth of the project. He
said it strikes him that the adjustment might not be made for a
decade or more.
MR. MAYER replied it depends very greatly on the specific nature
of the change being made; for example, who it impacts and how,
and what the timeframe that works through the system is. If the
change is around credits, in many circumstances the capital
intensive nature of an investment is in those early years of
constructing facilities and drilling wells. That tails off at
some point, so the impact is much more important in those early
years than it is later on. If the change is around the overall
rate of tax, the overall rate of tax in low price environments
is a change that hurts no matter when in time it is made. It
comes back to the question of changes that are fundamental
questions of policy and wanting to set a sustainable fiscal
system that is sustainable for all parties across a wide range
of prices versus changes that are related to this year and how
does the state get a little bit more revenue. Those are very
different questions that have very different impacts on the
question of how stable the fiscal system in Alaska is seen as
being.
1:32:19 PM
REPRESENTATIVE HAWKER cited Alaska Statute (AS) 43.55.023(b)
regarding the 35 percent Net Operating Loss Credit carried
forward. He said this statute very clearly states, as the
legislature wrote it, that a producer or explorer may elect to
take a tax credit in the amount of 35 percent of a carried-
forward annual loss. The statute is very clear even if the
intent was not quite that. He asked whether it is reasonable
for both [the legislature] and industry to expect that industry
will comply with the law as it is written.
MR. MAYER responded, "Absolutely, industry takes the statute and
turns that into a model and assesses the performance of any
investment they seek to make against what their model says."
Although the statute says 35 percent of carried-forward annual
loss, when thinking about how that annual loss is defined, it
turns out it is defined based on production tax value and that
in turn is defined based on the Gross Value Reduction.
1:34:10 PM
REPRESENTATIVE HAWKER said he understands that at these lower
prices there is a problematic value translation between the net
operating loss and the value of the credit carry forward. The
legislature passed the law, the legislature said go make
decisions based on it. He inquired whether it would not still
be a tax increase from the standpoint of the people being asked
to rely on state statute, even if [the legislature] thinks it is
fixing a mistake it made.
MR. MAYER answered, "Absolutely, it is without question." He
added that the core of his point [on slide 14] is about the need
to balance two things very carefully. The first is the policy
point about what one would like the system to be and what one
intended the system to be. The second is that industry has made
investment decisions based on the system as it is, not as it
might be in an ideal world and any changes have substantial
impact. This needs to be thought about very carefully.
1:35:17 PM
REPRESENTATIVE HAWKER stated that HB 247 is a complex approach
that essentially restructures the tax system. He suggested that
rather than the 35 percent carried-forward, perhaps a more
targeted fix - applied prospectively - could simply be taking
the value of the net operating loss in a given year and
translating it into a carried-forward credit using the marginal
tax rate of the taxpayer. This would provide an equal
translation of value, he posited, so there is not this
circumstance of a tax credit that arguably has a greater value
than the deduction was in the year it was incurred.
MR. MAYER replied he will think about Representative Hawker's
suggestion and get back to the committee.
1:36:31 PM
MR. MAYER returned to his presentation. Displaying slide 15,
"HARDER, HIGHER FLOOR RAISES TAXES ON LOSSES," he said hardening
of the gross floor is one of the biggest of the proposed changes
in HB 247. Under ACES, he noted, the Capital Credit calculation
was applied after the comparison between the net and the gross
systems and therefore was effectively non-binding in most
circumstances. Drawing attention to the graph on the left,
"EFFECTIVE PRODUCTION TAX RATE," he pointed out that at higher
prices the effective tax rate under ACES (yellow line) was
substantially higher than it is under Senate Bill 21 (red line).
The two rates are relatively close [across a broad range of
higher prices], he noted, but under Senate Bill 21 the rate
comes to a peak of about 35 percent at around $150, whereas ACES
went up and up to much higher levels at the higher prices.
However, in the price range of $120 down to $30, the key
difference is that the effective tax rate under ACES kept coming
down and eventually came down to zero, whereas the hardening of
the floor under Senate Bill 21 essentially means that it comes
down to about a 10 percent effective tax rate for legacy
producers, then it bottoms out and starts rising until about $60
where it goes up and very quickly asymptotically approaches
infinity. That comes back to the point about the nature of
gross taxes, which is that as the net value in the barrel gets
smaller and smaller, anything that is a fixed amount of the
total value takes up a steadily larger portion of the value
until it takes up all of the value. Once it takes up all of the
value, the measure of an effective tax rate or of effective
government take, becomes meaningless since it is all essentially
infinite. The chart depicts the price level at which that
happens versus the price levels of today and, he stressed, that
is a really important point to be able to understand. Mr. Mayer
said he has heard far too many people state that the effective
rate of production tax comes down and the producers are only
paying a 4 percent rate at the moment. But, he explained, it is
4 percent of gross and as a share of the net it comes down from
35 percent to around 10 percent and then it very quickly
skyrockets up towards infinity.
1:38:58 PM
MR. MAYER continued addressing slide 15, stating that the effect
of HB 247 is twofold and particularly on incumbent producers.
He said the chart on the right, "PRODUCTION TAX $/TAXABLE BBL,"
looks at the absolute dollars per taxable barrel. He pointed
out that in the price range of $40 [and below] there is
literally no net value left at all and in fact the producer has
a net operating loss. Currently, net operating loss can take a
company down below the floor, the statute is very clearly
written that these were specific provisions. The aim of the
hard floor under the Dollar-Per-Barrel Credit was to protect
some of the state's revenue at the lowest prices while also
being mindful that gross taxes make life very difficult for the
industry when prices are low precisely because gross taxes very
quickly take everything and then more than everything. Once in
an environment in which a company has a net operating loss there
is still the regressive royalty that is taking everything or
more than everything. In that environment the state is saying
that it is not sure it should be adding to it with 4 percent of
the gross and so maybe the Net Operating Loss Credit should be
able to take a company down to zero. Whether to change that is
a policy question about the balance of protecting the state at
the low end versus what the state takes at the high end, and
what a sustainable and competitive regime looks like in how it
balances those things.
1:40:45 PM
REPRESENTATIVE TARR, regarding going to zero, posited that there
are two different scenarios. One would be just zero within that
calendar year. But, she said, the more problematic thing that
the state is experiencing is what is carried forward into the
next year so that "we're 100 plus." She said she has been
researching how Alaska compares to other jurisdictions in
competitiveness and trying to find other examples of a situation
where it goes 100 percent plus. She inquired whether Mr. Mayer
is aware of any other jurisdictions where this has happened or
how other jurisdictions control whether they go beyond zero tax.
MR. MAYER responded that there are plenty of tax systems that
enable a company to carry forward losses. That is a standard
feature of a great many tax systems, with federal income tax
being one. Another is Australia's net profit-based, cash flow-
based production tax system which provides some protection for
the sovereign by saying that outflows, namely the sorts of
things that are credits here in Alaska, are carried forward
against future liability rather than paid out, but that means
that all negative tax items are essentially carried forward.
Thus, the carry forward is not unusual in that sense. It must
also be remembered that unlike many places, Alaska has the fixed
royalty that is already taking a substantial piece of the pie,
in fact a zero or negative pie.
REPRESENTATIVE TARR offered her belief that what is problematic
for the state is having the actual expenditure for the Net
Operating Loss Credits. She posited it would give the state
more protection if the credits were only allowed to be used
against future tax liability, which is contemplated in HB 247.
MR. MAYER answered that HB 247 does not contemplate ending the
cash payout of credits. Currently, cash payout only happens to
companies with less than 50,000 barrels a day of production.
The bill would put some additional restrictions on the cash
payout, including that companies with more than $10 billion in
revenues would not get a payout. The bill would also cap the
amount that any given company can claim. He said there is a
strong case for a sovereign protecting itself through a cap of
some sort at some point. However, whether it should be $25
million, and what timeframe over which it applies, is a much
more difficult question because that has some very serious
impacts, including very serious impacts on investments that are
being made at the moment.
1:44:34 PM
REPRESENTATIVE SEATON asked what the state's tax regime looks
like on federal or private land from which the state does not
receive royalties, but for which the state has a liability.
MR. MAYER replied that Representative Seaton's point is valid,
however he has not done much modeling on that specific question.
He advised that it merits serious analysis particularly in those
instances of new investment projects to which the Gross Value
Reduction (GVR) and other things would apply. In a sustained
period of low prices the value proposition to the state might be
a lot less than it is in places where the state has the royalty.
He said he needs to look at this very legitimate concern before
he offers any detailed advice about it.
1:46:05 PM
MR. MAYER resumed his presentation by turning to slide 16, "HOW
DO CHANGES IMPACT NEW FIELD DEVELOPMENT?" He explained that the
two graphs on the slide, labeled "CASHFLOW AND COMPONENTS" and
"PRODUCTION AND DRILLING," depict a hypothetical North Slope
project that qualifies for the Gross Value Reduction new oil
regime under Senate Bill 21. He outlined the assumptions for
this hypothetical project: cumulatively recovers about 80
million barrels of oil; peaks at about 20,000 barrels a day in
production; total capital spend of about $1.3 billion; average
annual operating cost of about $15 a barrel; 30 wells, of which
20 are producers and 10 are injectors; and the wells are drilled
over 8 years. He noted that an analysis of this sort is built
up from the granular level, starting with what is thought to be
a reasonable well cost to well type curve drilling profile and a
reasonable cost of facilities. The ability to get down to that
level becomes very important in assessing some of the project
economics. He said the blue bars on the cash flow chart are the
process of facilities development. Before a single well is
drilled, about $400 million will have been spent on a gravel
pad, pipelines to facilities, and such. In this model the
drilling begins in year three and the drilling expenses
("drillex") continue for several years. A lot of wells are
drilled up front to get production up, he explained. Once
production is up, drilling occurs at a lower rate for a number
of years and sustains a sort of plateau level of production.
1:48:14 PM
MR. MAYER continued discussing slide 16, pointing out that in
the earlier years the investor is substantially cash flow
negative. It takes a good many years to get back to zero, he
said, and then the project becomes cash flow positive and is
generating value. There is a corresponding difference in the
profile of government take over the course of time as a result.
Government take is effectively negative in the early years and
that is the impact of the credits being paid out. In this case
it is the Net Operating Loss Credits that are being paid out as
cash. In the early years the costs are high and revenues are
low and royalty is probably the only thing being paid. In the
later years there is some ongoing sustaining drilling and from
this point on the main costs are simply operating costs; there
is therefore a lot more value and this is where the bulk of the
production tax is actually harvested. When thinking through
these debates, he advised, it is useful to remember that under
almost any regime there are times when tax is not paid or where
it is negative, as in this example, and there are times when tax
is paid later in the tail. Thinking through the time profile of
that is really important in understanding the impact of all
these sorts of things.
1:49:51 PM
MR. MAYER returned to Representative Tarr's question regarding
Net Operating Loss Credits. He pointed out that a cap on the
reimbursed Net Operating Loss Credits would have a huge impact
on any new investment, particularly any investment that is being
made at the moment. He brought attention to the cash flow graph
on slide 16 and explained that the [dashed] black line is the
after tax cash flow, the cash that the producer receives. The
green color within the bars is the gross revenue, the purple and
blue are the costs, and the red is government take. Netting out
all of these things results in the after tax cash flow.
MR. MAYER moved to slide 17, "CHANGES BOOST CAPITAL NEEDS AND
LOWER IRR," and addressed the graph entitled, "CUMULATIVE
CASHFLOW." He explained that looking at the cash flow on a
cumulative basis tells a company how much it needs to spend
before the project becomes self-financing. In this hypothetical
scenario the company will spend continuously until about 2018
and production will begin about a year before that. In 2018 the
revenue from that production starts to exceed the costs that the
company has in its ongoing drilling and the cumulative cash flow
curve starts to turn around. When contemplating whether to
sanction a project one of the first things a company, the
investor, needs to understand is the capital structure that is
going to underpin the project - how the project is going to be
financed and what the company can afford. In this scenario the
company is assessing what is going to be $1.3 billion in total
spend. But, the company does not actually need to have $1.3
billion ready in the bank to make the project happen. Under
current law [solid black line in the graph], the modeling of
cumulative cash flow for this hypothetical project shows that
the company only needs to be able to recover $300 million of
total outflow before the project becomes self-financing. After
the company has spent $300 million, the remaining $1 billion
will cover itself because from that point forward there will be
production and positive cash flow. The company's cumulative
cash out will switch around and start to come back up. So, when
a company is looking at how much equity does it need, how much
debt does it need, it is not looking at how to finance $1.3
billion but rather how to finance $300 million, and that is a
very big difference. The credits have a big impact there
because they effectively act to reduce that very strongly.
1:52:37 PM
MR. MAYER then explained that the dashed black line on the graph
for cumulative cash flow represents what a cap of $25 million in
reimbursable credits would look like for a company with no other
projects. This line shows the company would need a total outlay
of $400-$425 million, rather than $300 million, before it
becomes cash flow positive, meaning the company would have to
come up with this additional capital. It is one thing if a
company were to just now be starting a project and could take
this into account as it figures out what this investment looks
like and how to finance it. However, it is quite another thing
if the company is a year or two into its spend and has already
told its equity investors how much they would be putting in and
what sort of return they would be getting, and the company has
been to the bank and knows what line of credit it has, and now
suddenly the company needs to come back to all of them and tell
them it needs $100 million more than it previously thought.
That would be a very difficult situation to be in.
MR. MAYER stated that the aforementioned situation would be even
more difficult for a producer that already has another producing
asset that still has substantial costs due to a low price
environment, or the ramp-up drilling being unfinished, or
drilling needed to maintain the production plateau. It would
also be difficult for a producer that may already be claiming a
net operating loss. If a $25 million cap per company were to be
implemented, a producer may already be up against that cap on
its other producing field, in which case effectively the cap
would be zero for a producer's new field. In that case a
producer could go from needing $300 million in capital for
making the project work to over $500 million, a 50 percent
increase in the capital base required. It would be a very
difficult conversation to have if halfway through the spend a
producer must come back to its equity investors asking for more
capital. Additionally, a producer would find that its internal
rate of return (IRR) is worse because the numbers under the new
regime look very different from those under the previous regime.
Therefore, concern over capping credits is very valid, he
advised, and something that needs to be thought about and
addressed. Making a change like this and doing it immediately
could have a potential chilling impact on the ability of
investments to occur and on investments that have already been
sanctioned or are already ongoing.
1:55:34 PM
REPRESENTATIVE JOSEPHSON said slide 17 is very meaningful to
him. He recounted reading in Petroleum News last year that if
everything went well on the North Slope, every project played
out just the way it would, and every permit from the federal
government was received, that perhaps there was an opportunity
for 100,000 barrels collectively. Meanwhile, he opined, the
super-giants are less and less super-giants. When he first met
with Pioneer Natural Resources Inc. he was told that the company
was drilling 6,000 barrels a day at Oooguruk, and what struck
him was that he was used to 2.1 million barrels a day. "Our
department says by 2022 we're going to have 350,000 barrels," he
related. Through no fault of anybody, it is just geology,
Alaska is not producing as much oil. So, he said, his question
is what is he investing in and how can he measure the net value
of that to the people while he measures what is on slide 17.
MR. MAYER responded that more than anything else Representative
Josephson is investing in a series of projects. Each one may be
small, 6,000 to 20,000 barrels a day in initial production, but
each project is a wedge. The Department of Revenue's forecasts
for North Slope production over the next four or five years
versus what the forecasts were a few years ago, show a striking
flattening of the [downward] curve, at lease for the next
several years. The only way in which that flattening continues
to occur is if a series of those projects keeps coming in and
each one is another incremental wedge that takes the state from
a 6 percent annual decline to a 2 percent annual decline to no
decline. In a world of higher prices and higher investment, it
might even ideally see things turning the other way. Those
things require a coming together of the right price environment,
right fiscal regime, and all the rest.
1:58:48 PM
REPRESENTATIVE HAWKER stated that the refundability of credits
is simply a matter of shifting the capital requirement burden
from the state providing investment capital to the private
sector having to provide its own investment capital. He
inquired whether, if applied [prospectively], limiting the
refundability of these credits could have a desirable outcome.
For example, he recounted, some of the investors in the Cook
Inlet did not succeed, were undercapitalized, left the state,
hung bad paper on everybody, and then a bankruptcy court came in
and made the paper even worse. Restricting the refundability
could potentially have the advantage of resulting in attracting
stronger, more capitalized, more qualified investors rather than
those that should not be in the state.
MR. MAYER answered that that is an excellent question. There is
no question, he said, that the North Slope and in particular
Cook Inlet are in the process of evolution that is seen in all
mature basins. A series of large established players for whom
this becomes a less material region are exiting and new players
are coming in. The combination of that basic dynamic with very
generous and frequently refunded credits has meant that some of
the players coming in have been much more thinly capitalized
than they might have been otherwise because the credits so
dramatically reduced the capital requirements. There are many
cases in which refundable credits have meant that people who
otherwise need additional working interest partners have been
able to get away without having them.
[CO-CHAIR NAGEAK turned over the gavel to Co-Chair Talerico.]
2:01:20 PM
MR. MAYER further pointed out that there is also the serious
question of the sustainability of the refundable credits in
numerous environments. He said the nightmare scenario from the
state's perspective is a price environment that is not
necessarily as low as today but is back above $50 and in an
environment where prices have come down. Should a new Kuparuk-
sized field be discovered, there would be the sheer amount of
capital required to develop a resource of that size. It would
potentially be a very, very large outflow to the state if the
people doing that were all eligible for the 35 percent
refundable Net Operating Loss Credit. Everyone should be
worried about that scenario, he advised. He further counseled
that having clear rules is always essential in any system. The
nightmare scenario would be having no clear rules on
refundability. As was seen last year, there is a degree of
executive discretion to try to limit the outflow and that is the
worst possible case because there is this uncertainty of the
credit being there under statute and refundable, but in practice
it is unknown whether the credit is going to exist. That is the
scenario which everyone should want to avoid. It is in
absolutely everyone's interest to have clear rules where the
state has said it knows that there are constraints on its
ability to fund this program and because there are clear
constraints the state wants to set those rules and set them
clearly.
MR. MAYER added that he can see lots of reasons why refundable
credits provide value in enabling investments that might not
otherwise go ahead. There are companies that are not firmly
capitalized that have solid backing, but for whom the
combination of the lower capital requirements and the higher
rate of return that is received make a big difference in
enabling a project to be sanctioned. Other than the question of
simply protecting people who have already made an investment, he
said is a serious question as to whether $25 million is the
right number, whether that could be higher and still protect the
state from some of the worst possibilities that could be
outcomes. A system that makes it clear what is the limit on the
state's exposure is very desirable.
2:03:54 PM
REPRESENTATIVE HAWKER stated it is important that if a change is
made, that it be prospective and not affect decisions that have
already been made. He inquired as to how strongly Mr. Mayer
would counsel committee members to be careful in that regard.
For example, he recalled, last year the legislature passed its
budgets and made the commitment for this capital to these
entities. The governor introduced three separate budgets that
included the reimbursement for those reimbursable credits. So,
when they were vetoed without any warning, a significant amount
of investment capital that was committed to this state went
away. He inquired as to the balance between how to smooth out
such a transition so that the rug is not pulled out from under
people's feet.
MR. MAYER replied that moving forward it would be quite
reasonable to put in place a series of additional restrictions
on eligibility for a refunded credit. It would not necessarily
have to be purely through a cap per company, or if it were a cap
per company it could be higher than $25 million. Another way
could be to require a vetting process by the Department of
Revenue (DOR) or the Department of Natural Resources (DNR) in
the same way that DNR must now approve plans of development
before a development can occur, or in the same way as all the
financials and the models are required to be handed over to DNR
in the case of royalty modification assessments. Looking at the
details of a project and approval would need to occur before any
money was spent.
2:06:33 PM
REPRESENTATIVE HAWKER understood Mr. Mayer to be suggesting some
kind of a front-end due diligence process.
MR. MAYER responded, "Absolutely."
REPRESENTATIVE HAWKER opined that from industry's perspective,
everyone collectively as the state can be held responsible for
the veto of the credits last year. He inquired how, if
legislation is passed that requires a due diligence process,
assurance can be provided that the state is not going to pull
out the rug from under the industry with a veto after the
legislature apparently has made the commitment.
MR. MAYER answered that the most important thing that can be
done in both the North Slope and Cook Inlet is committing to a
regime that the state can demonstrate is sustainable and
sustainable at the prices that are being seen for the future.
That the state has thought through all the potential scenarios
of what could happen and has committed to a one-time policy
decision to create a sustainable regime for the future, rather
than incrementally saying the state is unsure it can afford this
and so the credits might be there but not really.
2:08:10 PM
REPRESENTATIVE SEATON stated his appreciation for the discussion
and opined that once a project is sanctioned a company has a
commitment, not when it is a lease sale and a company is
exploring and has not reached that level of investment. In
regard to a timeframe as mentioned by Mr. Mayer, he agreed it
would be much harder after a project is sanctioned and the
investment acquired, and so going forward from there would be
much more problematic. He said slide 17 is looking at the
economic impact from a producer's standpoint, not the state's
standpoint. He requested that Mr. Mayer develop a slide that
looks at the state's investment via the credits in the early
part of a project and having a reasonable net present value
calculation with a reasonable discount rate so the committee can
see what the state's value is in the project.
MR. MAYER displayed a slide not in his presentation entitled,
"appendix," with two charts: one labeled "NPV 10 to company and
government: ACES" and showing a comparison of the old system of
ACES; and one labeled "NPV 10 to company and government: SB 21"
and showing Senate Bill 21 with a Gross Value Reduction. The
charts are not finished, he qualified, but are for the same
project as profiled [in slides 16-17]. He said the charts
depict everyone discounted at a 10 percent rate value overall to
company, to federal government, and to the state. He related
that under the previous system of ACES there was astronomical
value to the state as prices went higher. Relatively speaking,
things look much more similar at oil prices below $60 because
the effective rate of support for government spending has gone
down from 45 percent to 35 percent, and [in the current regime]
the state is slightly better protected on the low end than it
was under the previous regime. He noted that the charts are
looking at the production tax as well as the entire fiscal
system and assume a 16.7 percent royalty rate. The point of the
charts is to look at the total fiscal system and total value to
the state across a really wide range of prices. Under Senate
Bill 21 there is a fairly even split of value between the
company and the state, and the state is always better off than
is the company. A concern under ACES was that when investments
were looked at on an incremental basis there were times when
investments were value creating for a company and value
destroying for the state. [Under Senate Bill 21] the split is
relatively even and value for the state is higher in all
circumstances, subject to the assumptions he set out, than the
value is for the company. While it can be negative for the
state, it is only in sustained low prices that it is much, much
more value destroying for the company. Overall, Alaska's regime
by and large works pretty well.
2:12:52 PM
REPRESENTATIVE SEATON said the committee is having to look at
the investment of the state and the full field development. He
questioned whether there are many cases where the state has 16.7
percent royalty and requested Mr. Mayer to look at that. He
further requested that Mr. Mayer look at private land where the
state does not receive a royalty. He said it would be helpful
to know in what circumstances the state is making a good
investment and what circumstances the state may be making an
investment that is going to be a net loss to the state.
MR. MAYER replied that to the best of his knowledge, most GVR-
eligible production is on leases that are either a 16.7 percent
lease or a profit-share lease. By and large, the 12.5 percent
royalty rate is in legacy fields. However, he allowed, it is a
valid point about places where the lease is held by an entity
other than the state and this should be looked at further.
2:14:19 PM
MR. MAYER resumed his presentation and continued his discussion
of slide 17. He advised that in addition to substantially
increasing the capital requirement, the other big impact of HB
247 would be either decreasing the rate of return at any given
price or substantially increasing the price level at which a
company in assessing its economics reaches a particular hurdle
rate of return. Depending on whether that $25 million credit
cap is taken or the effective lower bound of many companies
maybe having already claimed their $25 million on other
projects, it would be somewhere between a $5 and $15 difference
in the price range at which at which a company would meet a 15
percent or 20 percent internal rate of return hurdle. This
would have a substantial impact on what projects are sanctioned
and what projects are not.
MR. MAYER moved to slide 18, "CHANGES MAKE REGRESSIVE SYSTEM
EVEN MORE SO," and noted that both charts depict the same
hypothetical new project of 80 million barrels. He specified
that when the proposed changes of the capped credits are stacked
with the more binding harder floor at low prices, the impact is
a series of changes that would make the current system, which is
overall neutral across a wide range of prices but still heavily
regressive when prices are below $60 a barrel, into a more
regressive system. He said each color on slide 18 is a
different component of government take: red = royalty, yellow =
property [ad valorum] tax that goes to municipalities and to the
state, green = production tax, purple = state corporate income
tax, and dark blue = federal corporate income tax. When these
components of government take are stacked together, and as long
as they are all positive, they add up to the dashed black line,
which is the total level of government take. He recounted that
the idea behind the Gross Value Reduction in Senate Bill 21 was
that for new investments a system was being targeted that was
effectively neutral across a wide range of prices at an overall
level of about 62 percent government take.
2:16:53 PM
MR. MAYER pointed out, however, that that starts to change at
the lowest prices because of the royalty's regressive nature.
He explained that there is no production tax at those prices and
at those prices production tax is even effectively negative.
Effectively negative does not mean the state is always paying
out money. It means that across the cash flow cycle of the
project investment, credits were spent up front and production
tax is at the tail. If the price of oil remained at $40 a
barrel for the entire life of this project the value of those
credits would always be bigger than the value of the production
tax that was generated in the later years. At a price of $60
and above the value of the production tax is greater than that
of the credits that were paid up front. But, even when the
effective net impact of the production tax is negative, there is
still at least 62 percent government take under the current
system due to all of the other components, in particular the
highly regressive royalty. Starting at $50 government take
begins curving upward, and once at $40 government take rises as
high as 100 percent. This is because even though the state
effectively contributed to the producer through the production
tax, the state is taking in net through royalty all of the value
that there is at those lower prices. Anyone making an
investment is looking at the overall fiscal system, he said.
So, the impact of the proposed changes in HB 247 is that at $40
it would be more like 150 percent government take rather than
100 percent. Thinking about things in that context will paint a
different and clearer picture, he advised, than simply thinking
about what rate of tax a given taxpayer is paying at a given
price, particularly when those rates are quoted on the gross.
2:18:52 PM
MR. MAYER, in response to Representative Hawker, reiterated that
the dark blue within the bars of the graphs on slide 18 is
federal corporate income tax and the purple is state corporate
income tax.
REPRESENTATIVE HAWKER understood the point of slide 18 is that
production tax is positive and then reaches a point at which it
becomes negative and falls below [zero]. He observed that at a
price between $60 and $45 per barrel there is production tax
both above and below [zero]. He surmised that what is being
shown is the increasing significance of state corporate income
tax and particularly the state ad valorum tax.
MR. MAYER responded that even more than those two is the royalty
itself - royalty is the big regressive element.
2:20:31 PM
REPRESENTATIVE SEATON, in regard to comparing systems, noted
that private royalty in North Dakota is 27-30 percent and said
there are areas in Alaska where the royalty does not go to the
state. He inquired whether who the royalty is paid to would in
actuality change a company's decision.
MR. MAYER answered that royalties are incorporated for the
perspective of fiscal comparisons. This would also be true in
terms of how a company assesses an investment. It is only in
the Lower 48 that the royalties go to private landholders rather
than to the state. Almost anywhere else in the world royalties
go to the sovereign. But, in any of those cases the royalty is
effectively treated as if it went to the sovereign even if it
goes to a private landholder, because it is all cash that goes
to someone else. In terms of a comparison with North Dakota,
North Dakota tends to have high fixed royalties which absolutely
means that at a given cost level in this sort of price
environment a company is bleeding even more there than it is
here. The offset to fixed royalties being highly regressive is
that when prices are better [the company] is also taking a lot
more of the cash. It comes back to the point that in any fiscal
system it is all about balance and what the system looks like
over a wide range of prices. [A sovereign] can be Norway and
take a large share and particularly take a large share when
prices are high. [A sovereign] can be North Dakota and whether
it is the state or the private landholder really protect itself
on the downside by having a very regressive high fixed royalty
and give away a lot on the upside. That is all about risk and
reward. He elaborated:
The high fixed royalty says we the royalty holder
don't want commodity risk or we want as little of it
as possible, and because of that we want to push all
the risk onto the private sector but we're willing to
give away a lot when times are good as a result.
Profit-based taxation is about saying we don't want
the distorting impacts at low prices on investment.
We want to try to enable all resources that should be
developed to be developed and not have our taxation
system be a barrier to that, and we would like over
the course of the commodity cycle to take more. And
the net profit tax is a way that enables us to do
that, and the tradeoff that we make is in doing that
we understand we're going to have more revenue
volatility and that we as a state need to have the
mechanisms in place to manage that volatility. ...
What you can't do is be both at the same time.
2:23:53 PM
REPRESENTATIVE SEATON said Alaska has both systems, royalty and
not royalty. The discussion is looking at government take on
these figures and government take is drastically different
between the two systems. He stated that it seems there is not a
decision point in the analysis that is being presented for
changing investment decisions based on government take when they
are drastically different between those two kinds of projects.
He requested Mr. Mayer to prepare something for the committee in
that regard.
MR. MAYER replied he will think about that and do what he can.
He said that ultimately he will always come back to the idea of
balancing risk and reward. If investing in Norway, a company
does it because the company knows it is going to have less
upside when times are good and knows that things are not going
to look truly ugly when times are bad. If investing in North
Dakota, a company does it because the company knows it takes a
lot of risk. In terms of the federal offshore, a company might
have a huge initial cash bid for a block before it has even so
much as drilled a well. All of the risk in that case is on the
investor. The investor further knows that if it has a discovery
and wants to go through to production it will do it under this
regressive fiscal regime. That means a company is spending
billions of dollars and when prices are low it is going to
really hurt, but the company has run its economics at a really
wide range of prices and has done probabilistic modeling and
thinks it is going to make enough on the upside that across that
balance the project makes sense. In that sense, it is always
about balance of risk and reward.
2:26:05 PM
REPRESENTATIVE SEATON said he realizes the aforementioned, but
pointed out that this is again being looked at from the
producer's perspective. Whether it is a situation offshore and
the state applies the same fiscal terms to it or whether it is a
situation of private royalty that the state does not receive,
decisions are being made and a lot of cash is being put into
credit systems from which the state may never see any basic
return even in a wide range of prices. If the state expends
tremendous amounts on credits and has a very conservative
discount rate, the state may still never recover its investment
over the life of the field. He said he is concerned about that
and therefore as the committee goes forward he would like to see
whether [the legislature's] decision making needs to have a
bifurcation for when something has a full economic return to the
state or when something does not have economic return to the
state but there is a huge liability to the state if it is
extending credits into an area where the state does not get a
fiscal return from royalty. He requested Mr. Mayer to do
modeling of these two regimes within the state.
MR. MAYER responded that if he understands the crux of
Representative Seaton's concern, it is really about the question
of, in particular, new oil under Senate Bill 21 and what that
looks like in places where there is no state royalty but is
either a Native corporation or federal royalty, and what that
looks like in terms of net present value to the state across a
wide range of prices. He agreed that that is an important
concern and said enalytica can do such an analysis.
REPRESENTATIVE HAWKER stated that what the aforementioned is
really getting to is the significant distinction in the state
between private royalty interests, which is privately owned land
as opposed to state land. The state's production tax credit
system provides this whole systemic structure across the entire
spectrum. He pointed out that Alaska has an entirely separate
tax structure in statute for private royalty interest. There is
an entirely separate levy for the separate landowner, which is 5
percent of the gross value at point of production, and that is
the state's sum total production tax.
[Co-Chair Talerico returned the gavel to Co-Chair Nageak.]
2:29:18 PM
MR. MAYER concluded the North Slope portion of his presentation
with slide 19, "KEY QUESTIONS RAISED BY HB 247 RE NORTH SLOPE."
He advised that while HB 247 is not a tax overhaul, it includes
a series of major changes that would have major impacts. There
are some absolutely legitimate concerns, such as: whether the
potential liability from credits should be capped and, if so, at
what level, and how, and how should that be applied going
forward; what the role is of the gross floor; and how to balance
protecting the state on the downside versus the upside that the
state takes by having a net tax-based system. The bill also has
a lot of incremental revenue raising measures that can be
understood in a time of strained finances, but which from an
investor's perspective get very scary very quickly. A series of
things in the bill are incremental revenue raising rather than
putting in place a one-time, thoroughly considered piece that
addresses the question of the sustainability of the system. The
scariest for any investor is when every year the sovereign comes
back seeking to take a bit more here and a bit more there. More
than anything else that is what scares enalytica when looking at
the proposals in HB 247.
2:31:17 PM
REPRESENTATIVE HERRON requested Mr. Mayer to discuss three
examples: something good that Mr. Mayer likes in HB 247;
something bad that should not be considered; and something ugly,
ugly meaning it is not good and it is not bad but is something
that needs a lot of work.
MR. MAYER answered that on the good side he thinks the intention
behind Senate Bill 21 was to say everyone gets 35 percent
support for government spending, not in some cases substantially
higher because of the interplay of the GVR. It needs to be very
carefully thought through about how that is implemented, but
from point of policy it would be wise to find a way to address
in a way that would not disadvantage people who have made
investment decisions assuming that to be the case. On the bad
side are those things that are easy to see as solely incremental
revenue raising measures rather than thought-through pieces of
policy. This is chilling from an investor's perspective. On
the ugly side is anything having to do with the floor. He said
he understands that protecting the state in low prices is always
going to be a key consideration, but that balance between
protecting the state on the low side versus what the state takes
on the high side and the inability to be both Norway and North
Dakota, is a key challenge.
2:33:21 PM
REPRESENTATIVE HAWKER returned to the earlier discussion about
private royalty interests. He said the question raised went to
credits under AS 43.55.023 and AS 43.55.025 that are available
for a producer working on state-owned lands and whether those
benefits would be extraordinary and would completely distort the
state ever getting a recovery back on the "private royalty
interest royalties, which are by statute AS 43.55.011(i), 65
percent." He offered his belief that all of the .023 and all of
the .025 credits are specifically restricted to activities that
are conducted on state and federal lands and are specifically
not applicable to private royalty interest.
REPRESENTATIVE SEATON responded that this is a discussion to
find out whether the state has liabilities, not an argument.
2:34:51 PM
REPRESENTATIVE TARR returned to the chart on slide 13 and
recalled that Representative Hawker had brought up questions in
regard to the opex and capex having been an average for the
year. She requested Mr. Mayer to prepare this same model using
a scenario of a major producer on the North Slope that is not
doing much capital work and that the model have a modest
fluctuation from month to month rather than an average. She
said she is requesting this because in running her own numbers
it appears that fluctuations would have a dramatic impact on the
way that the production tax would work out.
MR. MAYER agreed to do so. He said this is something that
clearly requires getting into the details of the actual process
of filing tax returns and those things that companies have to
get into.
2:36:57 PM
The committee took an at-ease from 2:37 p.m. to 2:41 p.m.
2:41:23 PM
MR. MAYER began the second half of his presentation entitled,
"IMPACT OF HB 247: COOK INLET ASSESSMENT." Drawing attention
to slide 2, "THE COOK INLET OIL AND GAS MARKET: A SCORECARD,"
he explained that he will start with a high level assessment and
will then drill down into the details. He first outlined the
recent history of oil and gas production activity in the Cook
Inlet and noted that enalytica's analysis is based on data from
the Alaska Oil and Gas Conservation Commission (AOGCC) and
others. Oil production has risen substantially, he reported,
from a low of 7.5 thousand barrels a day (mb/d) in 2009 and now
it is as high as 18.0 mb/d. Gas production has not seen the
same turnaround as oil, but has stabilized after years of steady
decline. In many ways it could be said that gas production has
seen the same degree of turnaround because it is a restricted
domestic market that is limited to the demand that is available.
More than that, the Cook Inlet gas market has seen a major
adjustment in recent years. It has gone through a huge
transition in the supply side, the demand side, pricing,
competition between various players, and expectations. Some of
these changes are seen in all mature basins around the world and
some of the changes are specific to Cook Inlet.
MR. MAYER reported that DNR has prepared several studies, one
released in late 2015 and one to be released in 2016 with
updated numbers on potential resources at the Cosmopolitan and
Kitchen Lights fields. According to DNR estimates, just under
1.2 trillion cubic feet (tcf) of proven and probable reserves
(2P reserves) are in the existing mature producing fields, plus
about 400 billion cubic feet (bcf) from Cosmopolitan and Kitchen
Lights. Noting that DNR's estimate is much lower than what the
operators of those fields have stated, he said DNR's total
estimate of 1.6 tcf of gas in the ground is clearly an
intentional conservative estimate. If development occurs at the
Cosmopolitan and Kitchen Lights fields, the current market would
be well supplied for the next decade at the least. This would
be subject to two big provisos: the pace of ongoing drilling
and development and what it might require to develop the
resources that are not currently developed; and what the role of
the credits in all of that is and what impacts that can have.
2:44:56 PM
MR. MAYER pointed out that at current price levels in the Cook
Inlet, brownfield investment in drilling new wells in mature
producing fields is pretty economic and that would be the case
even under a system with substantially less credits. However,
he added, the economics look very different when it comes to
developing new resources, especially new resources that require
major facilities to be built. Potentially, credits have a
strong role to play there, particularly when looking at the
difficult constraints that limited demand places on what those
developments might look like. The current uncertainty around
the future of the fiscal regime exists for numerous reasons.
One is that the regime as legislated expires in the early part
of the next decade. There is a sort of envisioned review
process between now and then to look at what the future would
be. This has been made even more uncertain given the governor's
line item veto last year. But even without that, the sheer
numbers of credits and outflow occurring at the moment raise the
question of sustainability of that system. From an investor's
perspective there would be concern as to whether the regime that
exists on paper today is actually going to be the one that
exists when it comes crunch time. In terms of enabling future
investment, there are places where credits are important and
there are places where they are less so, he advised. But more
than anything else, a long-term sustainable system that is well
thought through is ultimately going to be paramount to seeing
ongoing long-term investment in the Cook Inlet.
2:46:54 PM
REPRESENTATIVE JOSEPHSON remarked that it sounds as if Mr. Mayer
is saying even the investors in Cook Inlet themselves are
questioning whether it is sustainable.
MR. MAYER replied that the sheer amount of credit outflows were
one thing when the state was bringing in billions of dollars of
revenue through the production tax system and there were serious
problems with the future of the Southcentral gas supply. Since
lots of money was coming in through North Slope taxes the state
could afford to incentivize activity that it wanted to spur.
But now, much less revenue is coming in from the North Slope.
Displaying slide 4, "BIG DIFFERENCE BETWEEN NORTH SLOPE AND COOK
INLET," he said that anyone looking at the more than $400
million spent in Cook Inlet credits in 2015 would question how
long that could go on in a constrained budget environment.
2:48:16 PM
CO-CHAIR TALERICO inquired whether he is correct in reading
between the lines that Mr. Mayer is telling the committee the
clock is ticking and the committee will be far better off if it
focuses on this and starts to structure something sooner rather
than waiting until the midnight hour. He surmised it is a good
idea to begin a focus on what legislators will do when that
expires since good decisions are not made while in a panic. A
system would be well out in front so that everyone is aware of
what system will be in place.
MR. MAYER agreed, but recognized that many factors will make a
discussion about the Cook Inlet fiscal system more difficult
this year than in subsequent years. Going back to his previous
comments about some of the effective dates in HB 247, he said
changes that impact July 1, 2016, potentially have very
difficult impacts. Drilling programs have been committed to
that rely on some of the existing credits and some of those are
developments that one would really like to see happen for the
pressing interest of the state. When an investor does not see
this as a sustainable system, it is really hard to make
investment decisions unless the investor runs a range of worst
case scenarios rather than the actual existing statute scenario.
A conversation needs to start as soon as possible on a really
reasoned effort that says not just what happens if a credit or
two here is scratched, but what the fiscal system for Cook Inlet
should be to be both sustainable and stable for the future. The
right balance needs to be struck between incentivizing the
activities the state wants to see incentivized while doing so in
a sustainable way.
2:50:41 PM
MR. MAYER addressed slide 3, "REFUNDED CREDITS REACHED NEW HIGH
IN FY 2015," and slide 4, "BIG DIFFERENCE BETWEEN NORTH SLOPE
AND COOK INLET." He explained that all of this discussion stems
from the credits having grown substantially. In FY 2015 the
bulk of the credits were spent in the Cook Inlet despite Cook
Inlet bringing in a bare fraction of the revenues of the North
Slope, something that will always be the case. While slide 4 is
a snapshot of a point in time and some of those credits may
produce additional revenue in the future, the balance is clearly
off in a way that is difficult to see as sustainable. He
pointed out that in the left bar on the graph the total credit
outflow of minus $628 million was inadvertently omitted (the sum
of the credit outflows depicted for the North Slope and Cook
Inlet).
2:51:53 PM
MR. MAYER turned to slide 5, "ACTIVITY HAS RESPONDED IN RECENT
YEARS," to provide a basic history of the Cook Inlet. He noted
that in 2010 there was real concern about the future of gas
supply in the Cook Inlet, the future of overall activity in
terms of the oil and gas industry as an economic basis for that
region. Key changes related to pricing, storage, and credits
were made and resulted in substantial response. Drawing
attention to the left-hand chart on slide 5 depicting the number
of exploratory wells spudded each year [since 1950], Mr. Mayer
explained that the green bars are the actual number of wells and
the red line is the three-year rolling average. Bringing
attention to the right-hand chart depicting the actual producing
wells in the year in which they first came on line, he noted
that the three-year rolling average shows a substantial uptick
[in recent years] to the level that was seen briefly in the
middle of the last decade. Otherwise, he added, the only other
time that level of activity was seen was back in the 1970s.
That is quite striking and all those things that have happened
have had a substantial impact on activity in the basin.
2:53:26 PM
MR. MAYER moved to slide 6, "COOK INLET OIL AND GAS PRODUCTION:
BASIC FACTS," to look at overall oil and gas production in the
Cook Inlet using data from the Alaska Oil and Gas Conservation
Commission (AOGCC). He stressed the importance of separating
oil from gas because what has happened in each is quite
different. Drawing attention to the chart on the left, he
pointed out that oil production started in 1960, peaked in 1970
at 226 mb/d, fell to 7.5 mb/d in 2009, and after 2010 turned
substantially upward to about 18 mb/d, more than double the
production in 2009. Bringing attention to the chart on the
right, he noted that gas production has not seen a turnaround,
but has seen a stabilization. Explaining that gross production
is metered at the wellhead, he said the red line on the chart is
gross production, the green line is the gas reinjected into
wells, and the orange line is net gas production. Separating
things out this way is striking, because gross gas coming out of
the fields peaked as early as 1990 and declined precipitously
from 1994 to 1998. However, net production plateaued throughout
the 1990s, which was a function of one thing alone - the Swanson
River Oil Field. Swanson River had a lot of associated gas that
was reinjected for many years, and the green reinjection line is
all Swanson River. Then in the 1990s, production of Swanson
River gas began and reinjection steadily decreased. Instead of
a crisis in the mid-1990s there was a temporary plateau of
stable production all the way through to 2005. It was not until
after 2005 that the declines in gas production began to be seen.
2:56:02 PM
REPRESENTATIVE OLSON recalled that a lot of onshore and offshore
flaring was going on during the 1970s and 1980s. He asked
whether flaring was kept track of.
MR. MAYER responded that he will have to look at the numbers to
see how flaring is accounted for. He deferred to his colleague
at enalytica to comment on how flaring is treated historically
in the data.
2:57:16 PM
NIKOS TSAFOS, President & Chief Analyst, enalytica, and
consultant to the Legislative Budget and Audit Committee,
answered he is unsure about how the flaring shows up. He said
AOGCC has two data bases, one on well production and one on well
reinjection, and he is pretty sure the data is for gross well
production and does not take into account whether the gas is
marketed, used at the field, or anything else. There may be gas
that does not find its way to the market due to flaring,
venting, or use at the fields.
2:58:07 PM
MR. MAYER addressed slide 7, "OIL UP FROM WORKOVERS, NEW WELLS
IN EXISTING FIELDS," pointing out that oil production turnaround
in Cook Inlet was a function of new wells and, in particular, a
function of a lot of well workover activity. Drawing attention
to the left-hand chart depicting gross oil production by well
vintage, he explained that each colored line represents
production from a well that came on line in a particular decade.
For example, the green line is production from wells brought on
line between 1991 and 2000, and the red line is pre-1970. The
green line shows a striking turnaround in production: from
about 2,000 barrels a day in 2009 to over 4,000 barrels a day
today. Wells that came on line in the 1990s are now producing
twice what they produced in 2009 due to the substantial well
workovers that were done to make those existing wells much, much
more productive.
2:59:17 PM
CO-CHAIR NAGEAK announced that Mr. Mayer's presentation will be
continued on 2/27/16.
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HSE RES 2.25.16 enalytica Overview + North Slope February 2015.pdf |
HRES 2/26/2016 1:00:00 PM |
|
| HSE RES 2.26.16 enalytica Cook Inlet February 2016.pdf |
HRES 2/26/2016 1:00:00 PM |
|
| HSE RES 2.26.16 HB 247 J Rice Oppose.pdf |
HRES 2/26/2016 1:00:00 PM |
HB 247 |