Legislature(2007 - 2008)BUTROVICH 205
10/22/2007 11:30 AM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB2001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB2001 | TELECONFERENCED | |
SB2001-OIL & GAS TAX AMENDMENTS
11:34:51 AM
CHAIR HUGGINS announced SB 2001 to be up for consideration.
ROBERT MINTZ, Kirkpatrick Lockhart Preston Gates LLP, began his
presentation on SB 2001 tax issues. He said he has been working
with the Department of Revenue on drafting this production tax
legislation. He mentioned that Marsha Davis, Deputy Commissioner
of the Department of Revenue (DOR), would arrive soon. He said
he called this presentation a topical analysis simply because he
doesn't intend to go through in numerical order. He said that
quite a number of sections of the bill are basically conforming
or technical types of amendments. He said that sections 3 - 9,
11, 12, 23, 30, 33 - 35, and 41 are conforming amendments often
with only a paragraph number reference changing. Sections 24,
25, 29, 32, 42, 53 and 60 are non-substantive improvements,
clarifications or corrections in the existing language and
sometimes also conforming amendments.
MR. MINTZ turned to the substantive part of the presentation on
oil and gas production tax.
11:35:28 AM
CHAIR HUGGINS interrupted to ask when he and his organization
became involved in this process.
MR. MINTZ replied that he worked with the Oil, Gas and Mining
Section of Department of Law (DOL), until May 1, 2006 when he
retired. He had worked on drafting production tax legislation
law. He joined the law firm of Preston Gates & Ellis, but at the
beginning of 2007 it joined with another law firm. He had worked
with the Department of Revenue on implementing regulations after
the PPT was enacted. More recently he has been working with the
department on drafting this new legislation.
CHAIR HUGGINS asked when he completed the PPT regulations.
MR. MINTZ replied that phase 1 of the regulations was done and
adopted in March. It encompassed the more urgent regulations so
that taxpayers could calculate their taxes and fill out their
returns by the deadlines. Phase 2, which is still under
development, addresses giving more specific content to
deductible lease expenditures. The initial PPT bill was
retroactive to April 1, 2006. The legislature authorized the
department to make the implementing regulations retroactive
also, which is essential if one is going to implement a
retroactive piece of legislation. He said there is some detail
that may or may not require retroactive adjustments after the
regulations are adopted. There is nothing unusual in that
because it is typical for producers to file amended returns as
they get additional information that relates back to the time
when the initial return was filed.
11:39:33 AM
CHAIR HUGGINS said his interest in the case on behalf of the
committee is how coherent the return factors based on the
timeliness of phase 1 are and how quickly they could be digested
and reported. He asked what the reporting date was for phase 1.
MR. MINTZ replied March 31. He said there is generally a 30-day
lag between when regulations are filed by the lieutenant
governor and when they become effective, but the producers at
least had notice of what the regulations were going to be. He
said, "I think that it's fair to say that they were able to
implement or follow the regs in time to file their March 31
returns."
11:40:19 AM
CHAIR HUGGINS said he portrayed phase 2 as the deduction
criterion and that is ongoing.
MR. MINTZ replied yes.
SENATOR STEDMAN asked if he is representing the administration
as Preston Gates.
MR. MINTZ responded affirmatively.
SENATOR STEDMAN asked why the administration doesn't do its own
sectional review.
CHAIR HUGGINS said that was a good point and he called an at
ease.
11:41:30 AM at ease 12:05:36 PM
CHAIR HUGGINS called the meeting back to order saying that the
committee thought it important to have an administrative
official present at the hearing.
MARCIA DAVIS, Deputy Commissioner, Department of Revenue (DOR),
joined the committee.
MR. MINTZ continued by explaining that Title 43 of the Alaska
Statutes has a number of different taxes and the production tax
is in Chapter 55. He said the production tax is in addition to
other substantial revenue producing mechanisms based on oil and
gas including royalties on state oil and gas leases, oil and gas
property tax and the corporate income tax.
He explained that the state has had an oil and gas production
tax since before statehood (starting maybe in 1955). A
production tax generally imposes a percentage tax rate on some
measure of the value of oil and gas produced - an idea that has
evolved over time. It's important to remember that this is
regarding the taxing authority that applies to oil and gas
produced from land any where in the state - whether that is
state oil and gas leases or private land or onshore federal
leases; it does not include authority to tax on outer
continental shelf (OCS) federal leases that are outside state
water.
12:07:35 PM
MR. MINTZ said the core provisions of the current PPT law have
not been changed by the ACES bill. AS 43.55.011(e) - (i) is the
fundamental provision that imposes the tax that is the
production tax value of oil and gas produced in the state. Under
the current system it is a net value. That value is determined
by deducting upstream costs (exploration, development and
production costs) from a value, which has been an existing
feature of the production tax law - gross value at the point of
production. Gross value has been in the law for a long time and
has a lot of settled interpretation and regulations and
everything else. "We don't fool with that. We start with that
and then deduct the upstream costs."
12:08:51 PM
The PPT law introduced several categories of new tax credits in
AS 43.55.023 - .024 and changed the production tax from monthly
to an annual tax, but with monthly estimated tax payments.
Because it's an annual tax, there is one annual return.
The current PPT has a 22.5 percent rate on the production tax
value of oil and gas. In order to figure out the production tax
value (net value), one must go to AS 43.55.160. Important
exceptions to note are that the tax doesn't apply to the state
or federal royalty share - as has always been the case. It also
does not apply to the land owners' royalty share. In other
words, the PPT does not apply to a private lease, which has a
separate tax provision under AS 43.55.011(i). The reason for the
difference is because a royalty share by definition is a kind of
gross value and it just doesn't make sense to apply a net value
tax to the royalty share.
12:10:23 PM
MR. MINTZ said two other important exceptions are the tax
ceilings on Cook Inlet oil and gas production and the minimum
tax floor on Alaska North Slope (ANS) production, which under
current law is a sliding percentage based on the west coast
price of the ANS.
12:10:41 PM
He recapped that AS 43.55.011(e) establishes a base tax rate of
22.5 percent. Section (g) has the progressivity factor that is
currently calculated on a monthly basis. When the net value of
oil and gas on a Btu equivalent barrel basis exceeds $40/barrel
the tax rate increases by quarter percentage point for each
dollar the value goes over $40. He mentioned that gas and oil
are added together and are referred to on a Btu equivalent
basis.
12:11:33 PM
CHAIR HUGGINS asked if SB 2001 addresses gas versus oil.
MR. MINTZ replied that SB 2001 doesn't change the treatment of
gas versus oil. In general the percentage tax, whatever it is
under the current law or the bill, applies to the total net
value of oil and gas. However, Cook Inlet is treated differently
because it has separate tax ceilings for oil and for gas - but
that is not changed either.
CHAIR HUGGINS said he intended to ask the administration when it
intends to address that - because based on the rationale of
corruption he has heard, if one is tainted, he assumed the other
is tainted too. He said no matter how that is described, the
question remains because the strategic objective is to get a gas
pipeline. The legislature needs to have an expectation of what
time period that will be addressed.
MS. DAVIS responded that he raised a good point. She said, "Gas
is sort of not right in our face. We're not really talking about
gas; we're talking about oil. So what does it mean for gas?"
Because the earlier PPT law dealt with both of them at the same
time, she said her assumption would be that as this
administration and legislature looks at the proposals, it is
still happening for gas at the same time. However, they are not
being given proposals for gas; that's a separate question. She
elaborated:
As we've mentioned earlier, we recognize it's an
important thing we have to do and it is something that
needs to be done because there is some concern that
the way PPT was passed before by treating oil and gas
the same and the way it's being approached now which
is to not carve gas out and treat it any differently
than before, we still have that issue coming down the
pike at us. And certainly the administration wants to
address it, but our recommendation is to wait and get
a little closer - once we've seen what the gas
proposals are. Because what those proposals are is
going to tell us something about what types of gas
projects we would be looking at, needing to insure our
economic, and needing to insure that our tax system
doesn't serve as a deterrent to. So, there is no
question that important dialogue needs to come and
needs to be brought before the legislature. Our
preference is to bring it after we have had a look-see
at the proposals that come in at the end of November
and have a sense of whether there are economic
proposals and what they are - because that will inform
your understanding and your debate about how you need
to adjust the tax system - to insure that we as a
state have done everything we can to insure the
economic viability of whatever those projects or that
project might be.
But I think you raise a very good point that this
assurance to the public that we've looked at it is
half way there in the sense that before PPT dealt with
oil and gas the same way. We're doing the same thing
here, but we recognize there's one more job to do. And
we are putting it off to a little later date.
12:16:01 PM
CHAIR HUGGINS said he understood this to be event-driven and he
agreed with her. But he said they know what the next event is
and it will ask the question of what the state will do about
gas. He said he started asking this question last January and
they need an answer. "I think it's important for Alaskans to
understand that - and for the legislature."
SENATOR STEVENS asked if Ms. Davis was comfortable with waiting
until after the proposals are in to address the gas tax.
MS. DAVIS replied yes:
We are comfortable because the application process is
going to be about building a pipeline or building a
line that includes an LNG plant or it may include a
variety of things. And the economic viability of that
is going to depend in part on what's the price of gas
at the North Slope and part of what is going to be
sold often times, a majority of times, owners
essentially either - they pass through that tax. And
so in looking at what the tax is currently, the only
statements from Commissioner Galvin on this topic have
been that we're not looking to increase tax on gas.
What we recognize is there actually is a sort-of
built-in disadvantage to gas under this system by
treating it the same as oil and gas. At least our
understanding of the economics now are that treating
it on an economic equivalent basis - this Btu/barrel
basis - is not tracking market pricing - that we're
going to have to give some more benefits.
We're going to have to be more favorable - in other
words cutting back on how we approach tax for gas. So
right now as they look at the analysis, it would
probably be a worse-case scenario as far as what they
are looking at for the tax on gas and our intention
would be to look at how we make it more favorable to
insure a project goes. So, they have right now in
terms of their economic modeling what a worse-case
would be, but we're looking to improve that down the
road. With that said, because it's going to be
pipeline companies, at least companies wearing a
pipeline hat, the lion's share of what's going to
happen is going to be how economic is a project to
build a pipeline and they will take some assumptions
and some givens with respect to the commodity price.
Wearing your oil company hat and whether you do or
don't want to sell gas isn't going to necessarily be
the hat you're wearing when you're putting in your
application for the pipeline part.
12:18:53 PM
MR. MINTZ moved on to explain how the bill proposes to change
the current law. He said section 15 of SB 2001 would repeal and
reenact AS 43.55.011(e). Since progressivity is proposed to be
handled on an annual basis, all the department needs is one
single percentage rate that applies to the production tax value
of oil and gas, so section 15 actually makes it quite a bit
simpler. It says you start with the tax value under AS 43.55.160
(under current law) and multiply that by a tax rate that is
determined under AS 43.55.011(g). Subsection (g) says the tax
rate is 25 percent plus the progressivity tax rate, which is
determined under AS 43.55.011(h). The progressivity tax rate is
similar [in SB 2001], but slightly different numerically from
the current formula and starts with a trigger of when the net
value exceeds $30/barrel instead of the current $40/barrel, but
it goes up at a slower rate - 1/5 of a percentage point rather
than ¼ percentage point for each dollar - over the trigger
value. And this is calculated on an annual rather than a monthly
basis.
CHAIR HUGGINS asked why they should like this.
MR. MINTZ replied everything else being equal, it is simpler;
but what should drive the legislature's decision is the policy
behind it.
CHAIR HUGGINS asked if the difference in calculating the two has
nothing to do with the fact that one is so complex they may not
understand it. It's just that one calculation is a bit simpler.
MR. MINTZ replied: "Let's put it this way. It's happenstance
that the policy call that the administration is proposing in
this case also has the benefit of being a little bit simpler in
terms of drafting and applying and understanding it."
12:21:30 PM
He said as with current law, there are two big exceptions to the
general tax mechanism of a percentage of value. One is the North
Slope tax floor. Bill section 16 replaces the current tax floor
with a different one that applies to legacy fields. These are
units for, just to cover all bases, in the case of a non-
unitized reservoir that meets two criteria: total production to
date of at least 1 billion barrels and recent daily production
of at least 100,000 barrels/day. For these units, the minimum
tax is 10 percent of the gross value at the point of production.
The other big exception is the Cook Inlet tax ceilings, which
are dealt with in Sections 19 and 20.
CHAIR HUGGINS asked him to give them an example.
MR. MINTZ imagined legacy field A, which meets the criteria for
the 10 percent floor. In any given year, he supposed that the
progressivity was not triggered that year; so the tax rate is 25
percent of net value.
CHAIR HUGGINS interrupted to ask what circumstance would cause
progressivity to not be triggered.
MR. MINTZ replied if the net value of the oil and gas produced
from this legacy field didn't exceed $30 per barrel.
CHAIR HUGGINS said that is important for the public to
understand.
MR. MINTZ went back to his example and supposed that this legacy
field generated a total production tax value of over $2 billion
in that calendar year. A 25 percent tax rate times $2 billion is
$500 million. That would be the tax that would be paid using the
percentage of value. If you compare that to 10 percent of gross
value and the point of production - hypothetically suppose you
do that calculation - and get $400 million, in this case the tax
paid under the percentage of value formula ($500 million) is
greater than the tax floor so the company would pay $500
million. Now one of the rules to implement the tax floor which
comes later in the bill is that if you're producing from a
legacy field, you cannot apply tax credits to reduce your actual
tax paid below the floor. So in this case, the tax levied is
$500 million. If the producer had $200 million of tax credits
available, he could only apply $100 million that year to bring
the actual tax paid down to $400 million.
He took another example that supposed either prices were lower
or that costs were higher and the total net value of oil and gas
produced during the calendar year from legacy field A was only
$1.2 billion. With the 25 percent tax rate, the tax is $300
million. If that is compared to the $400 million which is 10
percent of the gross value, they have fallen below the floor, so
they have to pay what the floor says - $400 million.
12:25:58 PM
MR. MINTZ went on to the second major exception to the general
tax mechanism - the Cook Inlet tax ceilings, which have not been
changed; there are just conforming amendments. Section 21 has
technical language that is probably almost inexplicable by
itself, he said. It is essentially a conforming amendment to a
later provision of the bill which has to do with the rules on
deducting lease expenditures.
He explained that the existing law has an "anti-double dipping"
provision for use of tax credits in Cook Inlet. It is intended
to prevent, in some cases, exporting tax credits that a company
would otherwise use, but not because of the tax floor. It
prevents exporting those credits elsewhere in the state, because
that would be getting a double benefit from the tax floor or
double-dipping.
Later on in the bill, section 55 has rules how lease
expenditures are deducted, which also implements an anti-double
dipping concept. This technical language in section 21 of the
bill basically is meant to make sure that the anti-double
dipping under section 55 isn't applied twice against a producer.
He clarified:
In other words, if you've used up your excess lease
expenditures on your section 55, then you don't have
to do it again under section 21. It's kind of an anti-
double dipping from the state standpoint and
qualification to the anti-double dipping from the
producers' standpoint. It's just basically a fairness
- a little twist to insure that it works fairly and
doesn't overly penalize producers. And we can go into
more detail if you want later when we get to section
55, but I should mention this basically is already in
the current implementing regulations. But because
there are a lot of unanswered questions in the
existing law about how all these different provisions
fit together, we thought it best to make it explicit
in the statute.
12:28:25 PM
MS. DAVIS said because it was very complicated she wanted to
test this with the Cook Inlet piece and she explained:
What essentially happens at Cook Inlet is if you
calculate their tax under PPT, you would apply lease
hold expenditure deductions of your Capex and your
Opex and draw down your number; and then you would
apply capital credits and then be able to draw down
the number yet again. But we have this other rule on
the side that says 'Oh, by the way, you never ever -
you pay the ELF ceiling.' I mean essentially that will
be the lowest you can drag your tax. So the assumption
is to the extent that you had your PPT up here and it
drew down with expenses and it drew down with capital
credits and somewhere you crossed the line and said
'Whoop, there's my ELF ceiling. I can stop now.' What
it's saying is that you as a producer can't say 'Well,
this was my tax I paid; so now I'm going to go back
and grab these capital costs and these expenditures
and they technically didn't get used because I paid
this rate and now I'm going to take them and throw 'em
up to North Slope or throw them somewhere else.' And
they're saying no; those are considered used even
though you may have ended up paying this rate. So,
that's the theory. But if you had capital credits that
didn't get used to get you down to there, you still
had some more left, then you can still use those and
go throw them up to the North Slope if that makes
sense.
12:30:07 PM
MR. MINTZ moved on to AS 43.55.160 (bill sections 52 - 55) which
tells how to calculate actual taxable value that one applies the
percentage tax rate to. He said the basic principal remains the
same n the bill and explained:
You start with the gross value at the point of
production and subtract your lease expenditures. And
there have been some changes in the wording. First of
all we can throw out half of it because we no longer
need to calculate monthly values because progressivity
is now an annual concept.
And second, the bill expresses a number of rules about
when and how lease expenditures can or must be
deducted. These are rules which are implicit in the
current law, but they're not spelled out. And I think
the reason for that is you go back to the history of
the current law. The initial proposal that the
previous administration submitted to the legislature
was very uniform in how it treated oil and gas
statewide to the extent that if you're a producer in
Alaska, in order to calculate your tax, you could add
up the gross value of all your oil and gas produced
anywhere in the state, get a single number, add up
your lease expenditures incurred anywhere in the
state, get a single number, and subtract one from the
other. That's your production tax value - you multiply
it by a percentage and that's your tax.
Over time, various exceptions and different treatments
were introduced - specifically the Cook Inlet tax
ceilings, the North Slope tax floor and a special
credit for production taxes outside of either the Cook
Inlet or the North Slope. And that required some
degree of what we call ring-fencing - that is
separately calculating the taxable value in these
different areas. And to reconcile those ring-fencing
concepts with the general concept that you want to
basically deduct all your available expenditures in
that year rather than carrying them forward is a
little bit complicated and the rules had to be worked
out and they've been worked out in regulation. But
since we have an opportunity to revisit the statute,
we feel it's much more desirable to state these basic
rules in the bill. And in addition, now that we
realize more what the challenges are of reconciling
these two principles, I think the language has been
made clearer and simpler and that's the other reason
for the change in the language in section 160.
12:33:34 PM
SENATOR ELLIS joined the committee.
12:34:39 PM
MR. MINTZ said as an example of why these rules are needed going
back to the case of the legacy field, you calculate the taxable
value and multiply that by the tax rate and compare the result
to the floor. If you're down to the floor, then you're not
getting any benefit from deducting further lease expenditures.
So if you had your druthers, you would export those lease
expenditures and deduct them somewhere else; that would undercut
the whole point of the floor. So basically you can't export
lease expenditures from a legacy field to somewhere else.
He said another example of one of these rules based on what Ms.
Davis just explained is if you have lease expenditures in Cook
Inlet that you don't need (because you're already down to zero
or perhaps you're still exploring and not producing yet), and
you would rather export those somewhere else and reduce your
taxes, for instance, on the North Slope, but that would
basically constitute double dipping if you're not required first
to deduct them in Cook Inlet.
12:35:12 PM
SENATOR THERRIAULT joined the committee.
CHAIR HUGGINS mentioned that there are some exceptions between
Kuparuk and Prudhoe, for instance.
MS. DAVIS replied that the different treatment for legacy
fields, which are now by definition Prudhoe and Kuparuk (and are
in AS 43.55.160(f), is they have the same PPT rate and the same
productivity rate, but they have a floor. Before there was a 4
percent floor applying to everything and now that has been
contracted to just those two fields and it's a higher floor at
10 percent. The other piece that has changed is that the ring-
fence runs around both Prudhoe and Kuparuk. So now capital
credits can move across those two units. So, the prohibition on
exporting is really a prohibition from exporting outside of
either of those two units.
CHAIR HUGGINS asked if that was the only difference.
MS. DAVIS replied yes.
CHAIR HUGGINS asked the rationale for that change and who
developed it.
MS. DAVIS replied the rationale of that change was when the bill
was first drafted, they analyzed when a field would kick in for
each unit as a standalone unit. So as they ran their modeling on
what the margin tax rate is, and therefore, what the government
take at each unit is, it was found to be too high for their
comfort level. It was too aggressive in terms of applying a 10
percent floor to just Prudhoe or just Kuparuk and companies
needed to be able to move the funds across the units to bring
down the financial impact of having that floor. "That 10 percent
floor wouldn't kick in unless on a blended basis the oil price
on the west coast was $40 or less."
CHAIR HUGGINS asked if industry was consulted on the effects of
this provision.
MS. DAVIS replied that she had one conversation with
ConocoPhillips letting them know that is how she saw it. Her
sense was they were listening to what she was saying and doing
their analysis. She didn't ask them what they thought the cross-
over was. They shared some information on heavy oil in Kuparuk.
12:38:29 PM
MR. MINTZ clarified that the final bill still has ring fencing
separately for legacy field deductions, but what was changed is
that capital credits can be transferred from legacy field to
another. That's in AS 43.55.023(a) and they would get to that in
a minute.
12:38:58 PM
He summarized they had just dealt with AS 43.55.160 that says
that basically to get your taxable value, you subtract lease
expenditures from gross value. AS 43.55.165 tells you what lease
expenditures are and what qualifies and what doesn't. AS
43.55.165 (a) and (b) (bill sections 56 - 59) have been
rewritten and reorganized for more clarity. An example is that
the current law defines lease expenditures as being direct costs
and it defines direct costs as including certain overhead. The
problem with that is just terminologically everywhere else in
accounting and taxing where overhead by definition is an
indirect cost. So it is confusing. They just no longer call the
overhead allowance a direct cost; it's just a separate item.
Substantively there is no change.
MR. MINTZ said the more substantive change is that current law
allows, but does not require, that the concept of lease
expenditure be implemented by regulation. It was the
department's judgment that to insure basically greater control
by the department and greater transparency and predictability
that lease expenditures are expressly provided "that in order to
be deductible lease expenditures, the department must
affirmatively allow them by regulation."
12:40:53 PM
MR. MINTZ said the other substantive change to AS 43.55.165 is
the repeal of current subsections (c) and (d). These provisions
basically provided kind of a second track for determining what
allowable lease expenditures are. He said:
The first track is the general concept as implemented
by the department either by regulation or by case by
case interpretation. But the second track was that -
let's say you have a unit operating agreement under
which an operator sends monthly bills to its partners
for the costs of running the unit. And if the
department under subsection (c) or (d) determined that
the rules in that operating agreement were
substantially consistent with the rules defining lease
expenditures in general, then the department could
allow or require the producers in that unit to
basically substitute the billings or what is allowed
to be billed under the operating agreement for the
general concept of lease expenditures.
There are some advantages and there's some
disadvantages to doing that, but it was the
department's judgment after reviewing this and also
after grappling with the implementation problems in
the course of trying to develop implementing regs that
the disadvantages outweighed the advantages and it is
better to have a single uniform definition - a
specification of allowable lease expenditures in
regulation. So this bill does propose to repeal
subsections (c) and (d).
CHAIR HUGGINS asked for an example of that provision.
12:42:41 PM
MR. MINTZ said sure:
Let's take - let's just call it unit A where you have
several producers that have interest in a unit. Well,
let's go back a step. A unit is basically a group of
oil and gas leases or tracts that have different
ownership. And when you have different ownership over
an oil or gas reservoir, it can basically impede the
efficient development of the reservoir.
The easiest way to see this is to think about
sometimes the most efficient way to produce oil from a
reservoir is to inject water into some parts of it and
drive the oil into other parts of it where it's
produced. Well, if you own leases in the area where
water is being injected, you're not getting any
production, so that's not going to appeal to you. So
in order to overcome that problem, you treat all of
the leases as if they're a single lease and if you own
a lease on the outside instead of getting the oil
that's produced from your lease, you get a share of
the oil that's produced from everywhere in the unit.
So, basically, that's why we have units. Typically,
the lessees, the producers, have one of their group
actually operate the unit and that operator incurs the
expenses and bills the other producers, its partners,
for their share. And the thought was - and the
operating agreement typically defines the costs that
are allowed to be billed. The thought was that the
partners are not interested in paying more than they
need to any more than the state is interested in their
deducting more than they want them to.
And so if the department looked at this operating
agreement - looked at the rules for what costs could
be billed and determined that those rules pretty much
conform to what would be allowed to be deducted, then
the thought was instead of having kind of a two-step
process, where the producers get billed and then they
look - when it comes to determining what they can
deduct for the taxes - they look somewhere else and
see what the department allowed, that the department
said you can deduct what can be billed under the
operating agreement. So that's how it would work.
I say there are implementation problems with that. In
addition, even though once you get to that point of
approving the agreement, you could say there's some
administrative savings, the fact is that you have to
have these two separate tracts in order to administer
the two subsections along with the general definition.
It didn't seem that it was going to be in the state's
interest to implement these separate tracts.
12:45:45 PM
CHAIR HUGGINS asked in his estimation as a professional, if what
is being used as a concept of operation is functional and if he
supported the repeal.
MR. MINTZ replied that is a policy call that he doesn't make.
"But in terms of implementation and what makes sense in tax
administration, that there's no problem in repealing it. I mean,
it's kind of a novel approach, but it's certainly worthy of
consideration."
MS. DAVIS said this is a slightly different view of this issue -
from more of an administrative side - than this body discussed
before. She said she approached the issue from a background of
nine years of working in big oil and when she came to work for
the state, she recognized how dysfunctional the audit
proceedings can sometimes be on the owner's side. The time frame
for resolving these issues can take from one to seven years and
they can be on a item-specific basis.
She said that often operating owners don't agree and their
agreements change as they are resolved. It's such a dynamic
process for the working interest owners that the amount of time
it would take for the state's auditing staff to revisit
challenged issues and rethink whether it is appropriate or not
would be lot. So, she decided to put weight on the industry's
resolution of what expenditures should be in or out of lease
hold expenditures and backed it into a different provision,
section 57, which mandates for the department to consider what
the operating agreement provides is an appropriate expense. That
can be used on a item by item basis. So, the department gets the
benefit of the operating agreement, but isn't "tied whole hog to
the whole process - either in or out." Where it seems fair, they
can lock that in and move on. When new things come up the state
can take its time, let the owners sort it out, and then look at
it and see if it's sorted out and matches reasonable accounting
practices - boom - that's locked in. "It recognizes frankly, the
reality of how much time and how much dynamic changes there are
in the way operating owners work out their costs with each
other."
12:50:39 PM
CHAIR HUGGINS remarked that this is a novel approach and there
are two litmus tests that run through his mind. One is if it is
operationally sound and if it is durable.
MS. DAVIS replied that her approach is more operationally sound
and it's more durable.
MR. MINTZ went on to the list of fraud and wilful misconduct
over gross negligence exclusions in current law and how this
bill adds a couple of categories - costs arising from violations
of law or from noncompliance with lease or permit obligations.
MS. DAVIS noted that this change came from an interested
citizen's note of concern and she hoped this encouraged people
to send in their good comments.
12:53:14 PM
MR. MINTZ continued to the second category of expanded
exclusions in paragraph 15 and said at the end of a field life,
there can be quite extensive costs involved in dismantlement,
removal and restoration and these are typically called DR&R. The
current law allows those costs to be deducted to the extent they
are attributable to future production, but not past production.
Upon revisiting this, the department decided it was not good
policy for the state to, in effect, subsidize shutting down and
what it is really talking about sharing in is the cost of
exploring and producing. This provision would basically say any
DR&R costs are not deductible.
MS. DAVIS added that under the lease, the owners are obligated
to do this from the very beginning. Generally, she said the
state wants to incentivize that which someone isn't obligated to
do. So, in this case the state's dollars are being used to
support something they are already legally required to do.
12:54:16 PM
MR. MINTZ said paragraph 19 deals with issues in SB 80 from last
session. It has to do with whether or not the state should share
in the cost (including in the case of capital costs) giving
credits for repairing or replacing facilities or equipment such
as pipelines that may not have been maintained the way the
department hoped. It addresses that issue in a slightly
different way. Rather than look at the conduct of the producer,
it looks more objectively with the event that is associated with
the need for the repair or replacement. If the repair or
replacement was necessitated by some event which causes an
unscheduled interruption of oil or gas production or if the
repair or replacement causes a unscheduled drop in oil or gas
production, then those repair or replacement costs would not be
deductible. Similarly if the repair or replacement were
necessitated by an oil spill or some other kind of release of a
hazardous substance, then the state would not share in those
costs either.
12:55:38 PM
SENATOR WAGONER asked Ms. Davis if she knows yet how much Opex
BP billed against the state's credits for its work on the
pipeline.
MS. DAVIS replied no. She didn't know yet.
SENATOR WAGONER remarked that BP had sent a letter saying it
would deduct those expenses.
SENATOR WIELECHOWSKI said the difference between this and SB 80
is that a company could have been negligent for decades on the
North Slope and this kind of gives them a pass if they schedule
to fix their negligence.
MS. DAVIS responded:
Unless that negligence rise to the level of gross
negligence whereby it would be excluded under one of
the other provisions. If someone were not grossly
negligent, but simply negligent, then what we're doing
is we're saying - we will not participate in the
repair costs and the replacement costs where that
negligence has caused unscheduled production impacts
or releases - contamination. So, to the extent that
negligence is something that doesn't impact production
or doesn't impact the contamination, then we're still
allowing the credits and the deductions to occur.
SENATOR WIELECHOWSKI asked if she has other examples of how
other regimes treat this issue - as far as placing a strict
liability based on scheduled or unscheduled drops in production.
MS. DAVIS relied that she hadn't asked because it's only
relevant in regimes that have tax and royalty credits. She said:
Production sharing countries generally sort of lock
down all of their provisions in contract, and we can
look at that, but it's not as informative as if we'd
looked at statute in tax and royalty countries. In
thinking off the top of my head, it's really going to
be relevant only in those tax and royalty regimes that
have credits....
She said she would ask her experts about that.
12:58:44 PM
SENATOR WAGONER asked when the department would know how much
expense BP is writing off.
MS. DAVIS replied that the state has a couple of initiatives
going on different tracks - one is a legal enquiry in the AG's
office, which allows the discovery process which would provide
the opportunity to develop that number. BP's 2007 filing is due
with the state on October 15; October 31 is when their federal
returns are due. This allows the state to begin an audit
process. Her goal would be to do one of these pretty quickly -
within a year after that. She said the legal efforts might
produce an answer sooner than that.
1:01:10 PM
MR. MINTZ said the final addition to the list of exclusions is
paragraph 20 that relates to the cost of acquiring, constructing
or operating a crude oil topping plant or refinery. He
explained:
This has to do with the fact that sometimes right in
the field producers want to producer their own diesel
- it would be the best example - for use as fuel or
otherwise and sometimes they choose to obtain that by
building their own little topping plant rather than
just buying the fuel. And it's the department's
judgment as expressed in paragraph 20 that that is
really not is meant by direct costs. That's getting
pretty indirect when you make your own plant to
produce a product that you then use in operations.
Paragraph 20 would exclude deductions for constructing
or operating the plant, itself. However it does allow
for essentially deducting the value of the product
whether or not you build the plant or buy it - because
that does look like a direct cost of producing oil and
gas.
Now there's a little twist on here which I just wanted
to explain for the record. What's allowed to be
deducted is the difference between the market value of
the product and the value of the oil that's going into
it. The reason is because the oil is being produced
from that field and its tax exempt. So, if you allow
the deduction of that value, the tax then - you'd be
double dipping - double counting. So, it's the value
added between the value of the oil that goes into the
plant and the product that comes out of the plant that
you can deduct. If you think about, if you were buying
the fuel on the market then the oil that you'd
otherwise use to refine into it, you'd be selling and
getting the value of that. So, that's why just that
detail is - you deduct the value-added rather than the
gross value of the product.
1:03:06 PM
SENATOR STEVENS asked what the value added is.
MS. DAVIS explained that this complicated language allows an
operator:
to deduct the value of the diesel that they use -
either because the bought it and shipped it up - or if
they go ahead and say even though we don't have a
credit, we're still going to be making our diesel on
the Slope with out crude oil topping plant. When they
reach in and grab the barrel of the oil out of the
ground and throw it into the plant, they're allowed to
take that barrel out and not have to pay tax, because
it's being used on the lease.
So what we're doing is saying since you didn't have to
pay tax on it, when you go to deduct it from your tax
because of the fair market value of what a diesel
thing is, we're going to make you take out the piece
you didn't pay tax on. That's all. So, it's
essentially not letting them get a free barrel and
then deducting it from us.
1:04:38 PM
CHAIR HUGGINS asked if you build a facility or truck it north.
MS. DAVIS replied:
It's whether you build the facility and incur the
cost, build the facility and have the state incur -
what is it - 25 and 20 - 42.5 percent of the cost or
do you truck it - is the frame of reference. And what
we're trying to do is make one of those options, which
is build the facility and have the state pay 42.5
percent of the costs not one of the options.
CHAIR HUGGINS said his concern from a practical standpoint is
that causing more trucking activity might not be the right thing
to do because it requires more road maintenance and carries more
liabilities.
MS. DAVIS agreed that they need to understand the economic trade
off. She said that modifying the Kuparuk plant is estimated to
cost $300 million - let alone what it would cost to build a new
one. She is hearing that they have two plants up there neither
of which conforms for sulphur. Both of those would potentially
create a $300 million bill, plus potentially a third plant as
they step out and do remote work. "These are not small ticket
items."
SENATOR WAGONER said he remembered that Tesoro's plant
modification and expansion for its low sulphur unit was around
$50 million and he thought it was producing enough low sulphur
fuel for the state at this time. He didn't think the North Slope
was taken into consideration and he also didn't understand why
it would cost $300 million to modify the plant up there to give
them the low sulphur diesel.
MS. DAVIS responded that she didn't know, but she did know that
the Slope has environmental challenges relative to air emissions
and other standards.
1:08:53 PM
MR. MINTZ recapped that they had gone through the calculation of
the percentage of value, the question of credits and determining
how much actually tax has to be paid. And so a number of
provisions of SB 2001 amend the current tax credit provisions of
the production tax law.
He explained that AS 43.55.023 (a) is the existing provision
that provides for a 20 percent tax credit for qualified capital
expenditures. A few changes are proposed to it in the current
bill. First, a limitation that no more than 50 percent of a
credit may be taken the first year.
CHAIR HUGGINS asked what the value of this provision is.
MS. DAVIS replied it won't save the state total dollars, but it
smoothes out the lumpiness of the swings from year to year from
a budgeting standpoint. She explained that capital spend may
have peaks every two or three years and under the current system
those peaks can hit in a single year and so the state's
budgeting has to absorb it.
She said that Norway is considered to have a highly accelerated
depreciation schedule at six years and the federal government is
at eight years. Alaska is at one year; so she thought that
spreading it out over two wouldn't make a huge difference in the
state's competitive advantage.
1:11:33 PM
CHAIR HUGGINS asked what "our business partners'" perspective on
this is.
MS. DAVIS replied that she hadn't heard any comments from them
on that one. Probably the smaller companies, like Pioneer, would
potentially care about having the full credit to be able to sell
in one year versus selling half in one year and half the other.
However, the total economic benefit is still substantial for
them.
CHAIR HUGGINS asked if she had looked at the implication to
Pioneer of having a provision that accounted for the size of the
organization.
MS. DAVIS replied that a legislator raised that issue once the
special session started and she would be open to that notion.
CHAIR HUGGINS said he felt that Alaska's future would include
"the Pioneers of the world" and if the state is looking at
incentives, he wanted something that would encourage those
companies.
SENATOR WIELECHOWSKI said the Gaffney Cline testimony from
yesterday was very compelling especially regarding the discount
rate and how industry has 10 percent and the state has 5
percent. It seemed to him that this is one of those knobs that
could be turned to help maximize investment and the internal
rates of return. He thought upfront credit to the industry is
good because it increases investment pretty significantly. He
asked how much the spikes are. Is it hundreds of millions?
MS. DAVIS replied they would have to look at the spikes on a
taxpayer basis, but she would show him a one-year cycle to the
extent she has the Capex for those years. She said her concerns
went into the future with aging fields and infrastructure where
there may be wholesale replacement of systems every three or
four years which could create bigger spikes than the state has
ever seen.
She agreed with Senator Wielechowski that getting capital
returned early makes a huge difference when a company assesses
is deciding whether it wants to invest or not.
1:15:32 PM
CHAIR HUGGINS wanted to know if their quest for information from
the companies included predicting those spikes.
MS. DAVIS replied to some extent it's the unknowable because
unexpected things sometimes create the spikes. If any of the
heavy oil pilot projects take off, they would require
construction of large power plants and some unique systems to
handle sand, for instance. Those will trigger big spikes. The
state will try to anticipate these projects as much as it can,
but the challenge is knowing the timeframe and knowing what they
are.
MR. MINTZ turned to the second change in the capital credit
provision, AS 43.55.023. He said as Kevin Banks explained last
night, there had been a number of changes to AS 43.55.025, the
exploration incentive credits section - one group of which has
to do with additional or clarification of expanded information
submission requirements. He said the current law under AS
43.55.023(a) also provides that if you want a capital credit
rather than an exploration incentive credit under .025 for an
exploration expenditure, you also have to agree to the same
information submission requirements that you would have to
comply with .025. Since those submission requirements under .025
have been changed, there is just a conforming change under
.023(a) to make sure that you have to provide the same
information to the state - whether you do it under .025 or
.023(a).
CHAIR HUGGINS asked him to walk through a scenario.
MR. MINTZ responded that AS 43.55.025, the exploration incentive
credit program, predates the PPT legislation. That was a
separate targeted set of credits with its own sunset provision
and was targeted towards certain types of exploration
activities. And depending on the type of category, there could
be either a 20 percent or a 40 percent credit. When the PPT
legislation was enacted, one of the basic philosophies was not
to try and change parts of the existing law that didn't need to
be changed. So, the exploration incentive credit provisions in
.025 were left alone with the exception of conforming changes.
MR. MINTZ there is a new very broad credit provision under .023
which said:
Any capital expenditure that also is a lease
expenditure - in other words - if you own a current
expenditure for, develop or produce oil or gas and if
it's a capitalized type of expenditure, they can get a
20 percent credit for that.
Well, there's a big overlap between that and the
exploration expenditure. The exploration incentive
expenditures under .025 are much narrower, but they're
a subset of the broad category under .023. So, in a
sense, if you qualify for a 20 percent credit under
.025, the existing exploration incentive credit
program, it's not that different whether you do it
under that program or under the new program, .023(a).
But what we want to make sure if an explorer does it
under .023(a) it's not in order to escape the
obligations to provide exploration data to DNR. So,
when .023(a) was enacted it said basically if you're
an explorer, you're doing exploration, you have to
comply with the same information submission
requirements that you would have to under the existing
exploration incentive program. And since those have
been changed in the bill, they are also changed under
.023(a).
1:20:46 PM
MR. MINTZ said the final change in .023 (a) is something which
basically helps to implement the tax floor for legacy fields and
it provides that if there's a capital expenditure incurred in
the legacy field that the credit for that expenditure can only
be applied against a tax on a legacy field. Other wise they
could get around the floor by exporting the credit to another
field.
He continued:
A second major credit provision of the PPT law, which
is only slightly changed is the carry-forward annual
loss credit. This means if you're a producer, maybe
you're not producing yet, but you're still developing,
so you're incurring a lot of costs or you're an
explorer that incurs costs or you're a producer that's
operating at a loss - there are costs which you would
otherwise be able to deduct, but you can't get your
taxable value below zero. So, if you can't deduct in
that year, instead you can carry them forward. When
you carry them forward instead of being a deduction,
we turn them into a credit. It has the same economic
effect.
And again because of the floor on the legacy fields,
in order to basically make that floor more effective,
if you run a loss in a legacy field, you can't carry
those forward - under this proposed bill.
There actually is a kind of conforming change that I
think I neglected to include in my presentation, but I
should mention it because the tax rate under the bill
is under 25 percent - that when you deduct a cost, in
calculating your taxes, your after-tax cost is 75
percent. You get 25 percent deductible. So when you
turn the cost into a credit for carrying forward, to
get the same economic impact, the credit also is 25
percent of the cost. The current law has kind of an
anomaly in that respect because if the tax rate is
22.5 percent it only provides for 20 percent loss
carry forward. Our proposal is to conform the tax rate
for the loss-carry forward to the tax rate that's
imposed in calculating the tax. So that's changed from
20 percent to 25 percent in the bill.
MS. DAVIS said that provision came from the smaller players.
1:24:43 PM
MR. MINTZ said that AS 43.55.023(d) provides for transferable
tax credit certificates. This is the mechanism by which an
explorer producer that doesn't have tax liability to apply the
credit against can turn it into value by getting a certificate
and then selling it - or in the case of the new provision that
proposes having the state purchase it.
He said the only significant change here is to conform the
certificates to the 50 percent rule that applies to the capital
credits. There is a provision that says basically half of a
credit can be used immediately and the other half cannot be used
until the next year.
MS. DAVIS added that Chair Huggins had requested her to look at
a cap on the size of the credit for small producers and if they
would allow that small a class to do all of theirs in one year,
they would have to modify this slightly so their certificate
doesn't get split in two.
1:25:57 PM
SENATOR WAGONER said he concurred with that because it would be
simpler and because otherwise the smaller operators would be
penalized by the value of the money at issue over one year. He
remarked, "I just can't see doing that. I really can't see doing
that to a big operator either."
MS. DAVIS said she has an evaluation of what the time value cost
is to the state apart from any revenue planning aspects.
1:26:27 PM
CHAIR HUGGINS asked what the value of this is.
MS. DAVIS replied that it's relatively small in terms of the
time value difference.
1:27:11 PM
MR. MINTZ said the next change clarifies that if you're a tax
exempt municipality, you may not obtain a transferable tax
credit certificate and then get money back from the state.
CHAIR HUGGINS asked if they had arm-wrestled over this provision
before.
MS. DAVIS replied no; it's just a clarification.
1:27:50 PM
SENATOR STEVENS asked if this applies only to a municipality or
to other tax entities.
MS. DAVIS replied she checked with the DNR and this is the only
one. "The reason is there's this constitutional issue about the
state taxing municipalities which is what creates this anomaly.
So that's what takes them outside the tax which then we are
finishing by taking them outside the credits."
SENATOR STEVENS asked, "So a Native corporation would not be tax
exempt?"
MS. DAVIS replied they would not be tax exempt under this
language.
1:28:34 PM
MR. MINTZ added that the final change to the AS 43.55.023
credits is very significant. It's short, but it repeals the
transitional investment expenditure credits. It had a number of
nicknames but it basically provided credits for certain capital
types of expenditures that were made during the five years
before the PPT started on April 1, 2006.
CHAIR HUGGINS asked if this is the infamous claw back provision.
SENATOR WAGONER quipped that he called it two for one, but he
has since called it a kickback, but whatever it's called, he
didn't support it.
MS. DAVIS said that Dr. Pedro van Meurs didn't like this
provision either.
CHAIR HUGGINS said it is worth exploring its impact on smaller
organizations.
1:30:49 PM
SENATOR WAGONER remembered how some companies told him last year
that they wouldn't have purchased the equipment at that time to
do that job if they would have known this provision was going to
be adopted; they would have waited five years. And he thought
that was most disingenuous of them.
MS. DAVIS said they won't know about small producers because
they haven't incurred credits yet.
1:32:24 PM
MR. MINTZ said the next slides deal with bill sections 36-44,
which are changes to the exploration incentive credit program in
AS 43.55.025. He noted that almost all of these changes that are
described on the slides were described by Kevin Banks last night
and so he would skip to the ones Kevin didn't mentioned.
MR. MINTZ said the exploration incentive program in .025 has a
relatively limited universe of costs that are deductible. This
bill proposes to add one more, which is costs that are incurred
as a result of gross negligence or a violation of health/safety
environmental laws or regulations.
CHAIR HUGGINS asked what the impetus was for that change.
MR. MINTZ replied that there is some recent experience with
exploration activities that seem to be more expensive than they
should have been - a potential loophole.
CHAIR HUGGINS said he thought that "this business of health" has
a tremendously broad connotation.
MS. DAVIS agreed and explained that it's a little more
constrained than the broad topic in the sense that it is
confined to statutes or regulations that deal with health,
safety or environment.
CHAIR HUGGINS asked for an example.
MS. DAVIS replied probably it will concern the DEC environmental
statutes and regulations and OSHA laws that operators already
know about and allegedly already comply with. The intent here is
that if there is a cost or an expense that arises because an
operator cut a corner violating a DEC or OSHA law and now is
dealing with it, the state wants the legal authority to delete
it. She said it is a mirror provision to what already exists in
the capital expenditure section which disallows these types of
violations.
CHAIR HUGGINS said he didn't want to get into a "lawyerly
playground here."
MR. MINTZ went to section 39 that makes the 50 percent rule to
certificates under the exploration incentive program consistent
with how it's being treated elsewhere. He said this is just the
third place where it comes up.
1:36:47 PM
MR. MINTZ said he was leaving the credit provisions and turning
to the question of how to monetize credits if you can't apply
them against your taxes if you are an explorer or new producer.
He explained that current law has a provision in AS 43.55.023(f)
that establishes some criteria for getting cash refunds for the
state and provides for no more than $25 million in cash refunds
for a particular applicant for a particular year. He said that
limitation is not in the new proposal.
The new proposal repeals that section and replaces it with a new
system, an oil and gas credit tax fund, in AS 43.55.028. It
provides for funding that tax fund with a percentage of
production tax revenues - either 10 percent or 15 percent
depending on the DOR price forecast. Other than the $25 million
limitation, the existing criteria for whether you qualify to get
what's now called a purchase rather than a refund remain in
effect. For example, you can't produce more than 50,000 barrels
a day in order to qualify. You can't be delinquent on any of
your tax obligation and also you have to have used up credits
against your tax liability before you can get a refund. There
are a variety of administrative reasons why this new approach is
believed to be preferable and more effective at accomplishing
the goal of basically giving 100 percent value for the credits
that a producer or explorer earns that the state is going to
bear 100 percent of anyway.
1:39:26 PM
CHAIR HUGGINS asked how big this fund would be.
MS. DAVIS replied that they have looked at the state's track
record so far on the tax credits and they are higher than
predicted. In terms of identifying how much money would need to
be available to have enough funds on hand to fully refund the
credits the department is expecting, said that Cherie Nienhuis
did the analysis and forecast. She saw consistently if the price
of oil is $60 or higher, 10 percent covers it; if it's less than
$60, 15 percent covers it. The administration is comfortable
with that range.
It was also comfortable enough to eliminate the $25 million per
taxpayer in part because they are not having the large companies
come in and have credits, because clearly they have tax
liability that is sufficient to absorb whatever capital credits
they have in the current year. They are seeing that it's the
smaller producers who either do not yet have production and
those were the companies that said the $25 million cap was too
low for the majority of the types of expenses they were
incurring. She said she could bring the committee a number for
the size of the fund.
CHAIR HUGGINS asked for her to bring the mechanism to deal with
the annual cycle as well.
1:41:30 PM
MR. MINTZ said the current system has monthly installment
payments of estimated tax with a final payment on March 31. This
is unchanged. But since the tax calculation is changed in the
proposal, the rules for calculating it - the installment payment
- needs to be changed. One set of changes is basically to
conform to the changes in the tax. The other set of changes
basically corrects what may have been an oversight in the
original law - one of which was that Cook Inlet tax ceilings
were not accounted for in the estimated payments - which means
Cook Inlet producers will be required to overpay. This didn't
make sense, so they fixed that by allowing Cook Inlet oil and
gas to take account of those ceilings in calculating their
estimated tax. Also if you're a legacy field subject to a floor,
you take account of the floor in calculating your estimated
taxes.
The last point is that installment payments do not take account
of the progressivity rate. He said, "There is a practical
problem in requiring that which is simply that we would require
predicting the movement of oil prices in the future, which I
think we all know is not something which you can do with any
confidence."
1:43:30 PM
CHAIR HUGGINS asked him to explain the old mechanism on
installment payments and progressivity rate.
MR. MINTZ replied that the old mechanism did take account of
progressivity because that was calculated on a monthly basis. In
the new progressivity provision, you don't know even if
progressivity is triggered or if it is how much it is until you
know the price of oil over the course of the year. He explained:
Here are the things that go into calculating your
estimated installment payment: one is your monthly
production. Well, you know that every month. The
second is your gross value at the point of production.
You pretty well know that every month because you know
what the price of oil is for that month. And the third
th
is 1/12 of your annual costs. Now that's to some
extent a forecast, but the producers typically have a
pretty good handle on their costs, because they have
to budget in advance. So that's not too much of a
stretch. But those are the things that go into the
installment payment.
A producer, in fact, cannot know exactly what the
right amount is until March 31, but he can get pretty
close.
The fourth element, as I say, involves predicting the
future of oil prices and I think in the department's
judgment that's too much to expect a producer to do
and that's why the progressivity element is not
included in the estimated taxes, but of course, on
March 31 when taxes for the year are calculated,
that's going to be part of the tax due.
1:45:14 PM
CHAIR HUGGINS said, as an example, the producers wouldn't be
held accountable if the progressivity rate caused them to be out
of tolerance.
MS. DAVIS replied yes. She said the policy call behind doing the
progressivity on an annual basis is because of the volatility of
oil price up and down, the administrative time and efficiency
for everyone to try to track it month to month and follow the
spikes and make sure it's all right and challenge if it's wrong
is a lot of effort for not a lot of money. She wanted to
simplify and focus efforts on things that mattered.
CHAIR HUGGINS said that could possibly cause an automatic big
underpayment.
MS. DAVIS said their analysis doesn't show that could be a
sizeable number.
1:47:10 PM
SENATOR WIELECHOWSKI said Dr. van Meurs recommended a penalty
for underpayments to encourage payment of correct taxes. He
asked if she would consider that.
MS. DAVIS replied that they want to have something that someone
views uniformly as having sufficient teeth to encourage people
to not use the state as an ATM. She would be open to what they
thought were adequate penalties.
1:48:14 PM
SENATOR WAGONER asked if they didn't come up with a certain
percentage that was required for each payment with a true up
once a year.
CHAIR HUGGINS said that was true.
MR. MINTZ responded that was in various versions of the bill,
but it wasn't in the final PPT, which has no "safe harbor"
clause.
In fact, he said, interest is required on any underpayment or
refunded on any overpayment - a slightly different approach. He
didn't hear what Dr. van Meurs was referring to on the subject
of penalties, but existing law in AS 43.05 which are the general
administrative provisions for all the tax laws have penalty
provisions that are modeled after the IRS penalty provisions
where underpayments of tax are subject to civil penalties. There
are at least two types: a 5 percent per month up to 25 percent,
which applies unless the taxpayer can show reasonable cause and
not willful neglect for the underpayment. The other is a 5
percent of the total deficiency penalty if any part of a
deficiency is caused by intentional disregard of law or
regulation. There are more substantial penalties in the case of
intentional fraud.
These potentially apply to any underpayments, whether it's
annual or the monthly installment. You have to be more careful
with the monthly installment payments, because everyone knows
they're going to be off - because it involves estimates of what
one will ultimately owe. You wouldn't expect the department to
be particularly harsh in using the penalty authority for
installment payments, but if it was clear that a producer was
intentionally underpaying because the interest isn't that much,
the department has the authority to impose substantial civil
penalties.
SENATOR WAGONER said honest mistakes are made accounting-wise
and asked if companies are allowed a true up without penalty
every month for the last month's underpayments.
MR. MINTZ replied yes if it was not due to wilful neglect. You
always pay interest because that is the time value of money.
1:51:16 PM
SENATOR WIELECHOWSKI asked if the penalty for underpayment is
around 3 or 4 percent.
MR. MINTZ replied that the interest rate for underpayments or
overpayments on the estimated monthly payment imports the IRS
interest rate, which is intended to be a market rate. If there
is an underpayment after the March 31 final date, that is
subject to the regular state interest rate, which is usually
substantially higher, 11 percent compounded.
1:51:50 PM
MR. MINTZ said a number of provisions that deal with reporting
are in the nature of clarifying the department's authority to
avoid potential disputes. It has broad reporting authority, but
there are specific types of reports that are very necessary for
the administration of this law. And the department wants to be
sure there is no possibility for producers to argue about them.
Section 51 gives express authority to the DOR to require tax
payments to be made electronically in a form that will be most
helpful for tax administration.
MS. DAVIS added that they get all types of payments, but
electronically is much faster and easier.
CHAIR HUGGINS asked why that hasn't been done by regulation.
MR. MINTZ replied there is a regulation for modest amounts.
There are two reasons for this proposal - to remove any doubt
that the department has the authority and they want to make sure
that the electronic payments are made in a specific form that
will help the department administer the program more easily.
At ease from 1:55:43 PM to 2:21:27 PM.
MS. DAVIS deferred to Mr. Burnett to explain the mechanics of
the funding.
JERRY BURNETT, Director, Administrative Services, Department of
Revenue(DOR) ,Juneau, Alaska , recapped the question, which was
related to the tax credit fund and how much money would go in
each year. He said he believes the FY08 fiscal note was $1.9
billion. With 10 percent net of expected credit payments, the
money going into the fund in FY08 would be about $200 million.
Whatever credits were paid from the fund in FY08, which are
estimated to be between $125 and $150 million, would come out of
the fund in FY08 and the rest of the money would roll forward.
In FY09 ten percent of the production tax revenue would go into
the fund and the credits for 09 would be paid out of the fund.
In high revenue years it would build a sort of balance to carry
forward for low revenue years. Since it's not a dedicated fund,
the legislature could appropriate some of the money for some
another purpose if the balance got too big, he said.
MR. BURNETT continued:
One thing it does that would be helpful, at this
point, when you look at our fiscal note with revenue
projections, it shows an amount going into the general
fund that's actually lower than the amount that is
expected to go into the general fund in that year
because with refundable credits, we're required to
make then a general fund appropriation under the
current system to pay for the refundable credits.
Revenue estimates are net of those credits so right
now it looks like we're projecting less revenue than
we're actually expecting to get. The general fund
actually carries a larger balance than we estimate and
then we take some out for an appropriation to pay
credits. It creates a little confusion and at this
point we have open-ended appropriations out of the
general fund in 07. In 08 we had an appropriation,
which is limited at $25 million, which will require a
supplemental, which will be made before we know how
many credits are required to be paid. So again, it
will have to be an open-ended appropriation from the
general fund in order to properly pay the credits. I
don't know how much exactly that will be, what we're
estimating, but I think it's between $125 million and
$150 million total credits in 08.
CHAIR HUGGINS asked if those are all interest-bearing accounts.
MR. BURNETT said yes, and if it's not specified in the statute
the interest would go to the general fund.
2:25:31 PM
SENATOR WIELECHOWSKI asked how much the state earns on the CBR
(Constitutional Budget Reserve).
MR. BURNETT said he believes that the annual return is in the 4
percent range. General fund and CBR funds earn short-term market
rates for secure investments. The original $400 million CBR
funds are an exception. Those were invested long and last year
probably earned in the 15 percent range.
CHAIR HUGGINS recognized that Senator Hoffman was present.
MR. MINTZ informed the committee that he would discuss the key
tools for administrating the tax. Bill section 46 deals with the
annual return and clarifies that all oil and gas producers must
fill a return annually regardless of whether any tax is due. He
explained that the substantial tax credits that are available
create a situation where in a particular year a particular
producer may not have to pay tax. Nonetheless, it's important
for DOR to receive the information for verification purposes and
to track potential credits. Thus, actual production is the
trigger. This section also expands the list of specific
information that's required for the returns. He noted that DOR
always retains the authority to require additional information.
CHAIR HUGGINS questioned expanding the list when there's
unilateral authority to require additional information.
MR. MINTZ responded DOR decided that adding relevant things to
the existing list makes sense and potentially avoids the
possibility of a challenge.
2:29:41 PM
MR. MINTZ explained that the bill proposes an additional penalty
that relates solely to late filing whether there's an associated
tax deficiency or not. It's calculated as a percentage of the
tax deficiency. DOR would adopt by regulation standards for
determining the size of the penalty, but it couldn't be more
than $1,000 per day.
MR. MINTZ said bill section 48 requires explorers or producers
to file an annual statement of expenditures even if no oil or
gas is produced during the year. DOR needs to track those
expenditures because they could be deductible or potentially be
turned into credits.
SENATOR STEVENS asked if the form would be complicated and time
consuming.
MS. DAVIS replied the requirements are set out separately under
the statute so the scope of information is narrower in the
instance that no oil and gas has been produced. It's not
onerous, she added.
CHAIR HUGGINS asked if electronic filing is required.
MS. DAVIS said yes, that's included in the bill.
MR. MINTZ added that DOR has ongoing information needs that
aren't adequately satisfied by annual returns and bill section
48 makes it clear that the department has the authority to
require regular monthly reports with appropriate information.
2:33:15 PM
MR. MINTZ explained that bill section 49 adds explicit new
authority for DOR to require reporting of forward-looking
information for revenue forecasting purposes. This is important
because the current tax is dependent on upstream cost
deductions, which is a category where very little information is
available except for producers and operators. He added that now
there's a provision giving express authority for the department
to require electronic filing. There is some question whether the
department could impose the requirement by regulation so this
fills that gap. Also, this new authority allows the department
to specify the format for the electronic report so the
information is readily available.
2:35:42 PM
MR. MINTZ said AS 38.05.035, bill section 2, gives DNR broad
authority to share oil and gas lease information with DOR for
purposes of administering the production tax and AS 38.05.230,
bill section 13, provides DOR broad authority to share
production tax information with DNR.
SENATOR STEVENS referred to Commissioner Galvin's statement
about confidential information that's transferred from DOR to
DNR and asked how that works and who is involved.
2:36:53 PM
MS. DAVIS explained that royalty and tax information is
carefully protected. Specific auditors sign an agreement to
review records and files while they're in the DOR office. "We
rarely allow copying of any record to even leave the floor so
it's very constrained, very limited. It's more of a check and
verify," she said.
SENATOR STEVENS asked if there are penalties for violating that
confidentiality.
MS. DAVIS replied there are very severe penalties including
criminal sanctions and monetary fines. DOR and DNR employees
take this very seriously, she said. She understands that the
same constraints exist with regard to confidential information
that DNR possesses.
MR. MINTZ added that both agencies have a long history of having
access to and maintaining highly sensitive information. He's
sure both have exemplary records for protecting confidentiality.
CHAIR HUGGINS questioned why royalties aren't under the purview
of DOR since they are revenue.
MS. DAVIS replied it's because royalties are a benefit that
flows from a contract that is entered into and administered by
DNR.
CHAIR HUGGINS commented it still appears that it would be an
objective for consolidating effort in managing resources.
2:40:16 PM
MS. DAVIS said one thing we've learned is that different
countries arrange things in different ways. Ideally we want to
make efficient use of people and computer resources and improve
the flow of information for the customers. As we move forward
working with DNR, opportunities to create efficiencies will
occur and this is a first step, she said.
MR. MINTZ added that confidentiality is required under both
aforementioned provisions. He then directed attention to bill
section 61, which deals with public disclosure. He noted that
there's existing authority for DOR to publish statistical
information so long as it doesn't include the particulars of a
taxpayer's business. This clarifies that if the information is
aggregated among at least three producers or explorers then it's
okay for the department to publish certain categories of
production tax information. The idea is to increase public
transparency and the confidence that tax laws are being
effectively administered.
2:43:20 PM
SENATOR STEVENS asked for the rationale for selecting three
rather than two.
MS. DAVIS explained that this bridge was crossed when the
department looked at how to make the fisheries licensing tax
information public. With help from DOL it was determined that an
aggregation of three supplied sufficient anonymity. The driving
goal is to maintain an adequate standard of protection for
individuals and this seems to work, she said.
MR. MINTZ relayed that AS 39.25.110, bill section 10 places oil
and gas auditors in the exempt service. There's a transition
provision in bill section 67 that provides current employees
with the option to remain in classified service if they exercise
the option within a specified period of time. AS 43.05.260 and
AS 43.55.075, bill sections 14 and 50 extend the statute of
limitations for production tax from three years to six years.
DOR believes this is an important change to insure that it can
do an adequate job of auditing and enforcing tax laws, he said.
SENATOR WAGONER commented that seems to be a long time for a
statute of limitations to run.
MR. MINTZ replied it's not uncommon for a considerable amount of
time to elapse when resolving tax matters. Even with a statute
of limitations there are often extensions by agreement. Often
it's in the interest of the taxpayer to do that rather than have
the department issue a blue sky assessment. Also, one reason for
statutes of limitation is the disappearance of memory and
witnesses, but that really isn't much a factor with tax cases.
Everything is documentary so the fairness issues aren't as acute
in this area.
2:45:44 PM
SENATOR WIELECHOWSKI advised that breach of contract is
typically six years.
MS. DAVIS said in Alaska it was amended to 3 years.
MR. MINTZ recalled that if there is no specific statute of
limitations provided, the default is six years.
2:48:10 PM
CHAIR HUGGINS asked Mr. Bullock to give an overview of the
effective dates and any other things that might be worthwhile.
DONALD BULLOCK, Counsel, Legislative Legal and Research Services
Division, Juneau, AK said he's listened to testimony from the
administration and Mr. Mintz as he discussed what the
administration plans to do in terms of policy calls. His opinion
is that the bill as it's been presented would adequately carry
out the proposed policies.
MR. BULLOCK drew attention to the provisions at the end of the
bill related to retroactivity and reported that U.S. Supreme
Court cases have said that after a first return is filed, it's
within the scope of due process to allow changes by the next
legislature. Under that interpretation the first return was
filed last April 1, so the next legislature could go up to this
session. This is a special session so it's a gray area as to
whether this session would count. He believes an argument could
be made that it would not count because the legislature is
limited by the call of the special session and by the time
period. If faced with that kind of challenge he would say it's
unreasonable to have expected the legislature to have considered
the issue during this special session or in the one day session
in June. Under that interpretation, there would not be a problem
applying the retroactive provisions in the bill back to April 1,
2006, he stated.
MR. BULLOCK addressed the question about putting things in
regulation as compared to statute and explained that regulations
are tested for consistency with statutes. Also, there are many
things the department could do by regulation, but if it's a gray
area or involves information somebody doesn't want to part with,
then it'll be litigated. As legislators you're in a position to
identify the information that's critically important to the
state, he said. Put that in statute so it's not necessary to go
through litigation if the regulation is challenged. It's more
efficient. That doesn't take away general challenges of
information that may be subject to the privacy provision in the
constitution, he added.
2:52:16 PM
SENATOR WIELECHOWSKI said he didn't see a severance clause in
the bill.
MR. BULLOCK replied it's redundant; Title 1 has a provision that
every bill impliedly has the severance clause. If a provision is
found unconstitutional, it would fail and if the rest of the
bill can be enforced without that provision, then it would
continue.
CHAIR HUGGINS asked him to describe the schools of thought on
the bill.
MR. BULLOCK opined that several things are going on and some
deal directly with the tax under the PPT. For example there's
the nominal tax rate increase from 22.5 percent to 25 percent
and there's the progressivity. Also there are issues that have
to do with expenditures. Part of the PPT is just like the old
tax because you start with the gross value at the point of
production and then the allowable lease expenditures are
deducted to arrive at the tax value of the oil and gas. The
credits follow a similar line. Once the gross tax is determined,
you figure how much further the net revenue to the state would
be reduced by the allowance of credits. Those are all tax
things, he said.
MR. BULLOCK explained that within the expenditures there are
additional information requirements so this is an appropriate
place for tax policy. If you give a credit for exploration, it's
reasonable to set the condition of getting some of that
information back. The tax rates, the expenditures, and the
credits are all directly related, he said.
MR. BULLOCK said that with regard to issues relating to the
administration of the tax, the bill has several provisions to
address how you know the information that's submitted is
correct. One thing is that if the auditors are exempt, the
increased pay will attract auditors that have the skills to look
in the nooks and crannies to find out what the numbers ought to
be. Also, the information sharing between DNR and DOR will
create a better bank of information so that the auditors on the
royalty side and the tax side can communicate and review their
thinking. Another administrative part is the extension of the
statute of limitations. He said he believes that there is a
statute of limitations for claims by the state. AS 09.51.010
comes to mind, he said. There's already a six year statute of
limitations in place for the state to bring actions, but not in
tax. Over the course of six years things happen, he said. Things
that affect the production may come up in other bodies. For
example these taxpayers are subject to the IRS code and normally
if the IRS makes a change that affects Alaska taxes they're
required to file. This is emphasized for this bill, he said. As
Mr. Mintz said, the state can get agreements to extend the
statute of limitations and often it's in both the state's and
taxpayer's best interest to do that. But by having the longer
time, they won't have to take all those extra steps involving
additional negotiations. This approach is more efficient, he
said.
MR. BULLOCK summarized that most of the issues in the bill
including the tax rates, the conditions for credits, and
allowable expenditures are all policy calls and the
administration has characterized what the calls will be.
2:56:55 PM
SENATOR McGUIRE clarified the statute of limitations statute is
AS 09.10.110 [AS 09.10.120].-Actions in name of state, political
subdivisions, or public corporations-and it is six years.
MR. MINTZ thanked Mr. Bullock for providing many helpful editing
suggestions based on the initial bill version. The
administration tried to incorporate those in the final version.
MR. MINTZ turned to bill section 1, dealing with transportation
and explained that those costs are deductible in arriving at the
gross value of oil and gas for tax purposes. Imagine that in
2000 a taxpayer reported and paid production taxes based on
pipeline tariff, which is a transportation rate that was
deductible. After three years the statute of limitations expires
and in 2004 there's a rate case and the FERC or the RCA orders a
refund of transportation charges from year 2000. That actually
increases the taxable value of the oil that was transported in
2000 and it increases the amount of tax that should be paid. He
asked if the department is precluded from getting that
additional tax because more than three years has passed since
the return was filed or does the statute of limitations begin to
run again because it's a new event when the refunds are made.
The department has had a longstanding interpretation expressed
in regulation that the statute starts to run again. Logically,
how the statute of limitations could have run on something like
that hasn't occurred, he said. But the taxpayer could argue that
if they owed taxes in 2000 and now it's four years later the
statute has run and nothing can be done about that.
There hasn't been a test of this for two reasons: first, most of
the time these retroactive adjustments have been dealt with by
agreement with the taxpayers. The other reason is that in the
tax arena the issue is generally income tax and when there's an
adjustment like that for income tax it's simply treated as
income tax in the year that it occurs so there's no question of
going back in time. Things don't work that way in the production
tax arena because it's not income that's taxed. The value of oil
produced in a certain time period is what's taxed so it's really
a retroactive change. Because this hasn't been settled and
because there should be no room for argument or disagreement,
this interpretation that's been in regulation is being placed in
the statute. Because they believe it's a correct interpretation
of existing law, they don't want it viewed as a change in the
law. They're asking the legislature to recognize that the
intention of enacting this is to confirm the existing
interpretation.
3:02:02 PM
MR. MINTZ directed attention to AS 43.55.110(g) bill section 51,
which gives express authority to the DOR to issue advisory
bulletins interpreting production tax statute and regulations
for guidance to taxpayers and others. He noted that Chair
Huggins questioned why this isn't already being done. The reason
has to do with the very broad definition of the term
"regulation" in the Administrative Procedure Act and the broad
interpretation the courts have given that term. Basically, he
said, whenever the department issues an interpretation of
general applicability, the court says it sounds like a
regulation, but unless it's adopted through the formal
regulation process the court will say it's invalid. That's why
the department is asking for the express statutory authority, he
said.
CHAIR HUGGINS described it as an inoculation.
MR. MINTZ directed attention to the changes in the uncodified
law dealing with the details of applicability, effective dates,
and transition. He noted that most of the substantive changes
that have been discussed, such as changes in tax rate and
credits are prospective under the bill and would begin taking
effect on January 1, 2008. That means they would apply to oil
and gas that is produced and expenditures that are incurred
after December 31, 2007. However, there are some categories of
changes that the department views as mid-course corrections or
changes that should have been made in April 1, 2006. Those
include additions to the categories of exclusions from costs
such as repair replacement to DR&R and costs relating to
violation of law. The second category is repealing the sections
relating to the use of unit operating agreements to define lease
expenditures. Those are going back to April 1, 2006, he said.
CHAIR HUGGINS commented that some people are questioning why
this couldn't be done in the regular session with a retroactive
effective date. A response isn't necessary, he said.
3:05:55 PM
MR. MINTZ explained that another applicability provision is to
apply the extension to any tax liability that's still open even
if it came up in an earlier year. For example for a tax on oil
and gas produced in 2005, the statute of limitations will be
extended up to six years. But if the statute had already run-the
three years had passed-that wouldn't be reopened. It's also
limited back to April 1, 2006. It's viewed as a retroactive
application so it's necessary to specify the retroactivity date,
he said.
MR. MINTZ reminded members that two provisions in the bill
clarify that a tax exempt entity isn't allowed to get a
transferable tax credit certificate. We view that as a
clarification rather than a change, he said, so the
applicability date is the date that each of the respective
credit provisions began. In the case of the section 023 credits,
the date was April 1, 2006. In the case of the section 025
exploration incentive credits, the date was July 1, 2003. Most
of the other provisions take effect immediately. He noted that
MR. MINTZ noted that earlier he referred to authority to make
regulations retroactive to the same extent that they are
implemented. That was provided for in the original PPT bill and
it's provided for in this bill, he said. When the department
implements by regulation the provisions that are retroactive to
April 1, 2006 they likewise can be retroactive to April 1, 2006.
Otherwise, there's authority to make regulations retroactive to
January 1, 2008. That is in the future but by the time the
regulations are adopted and the process is completed it'll be
after that date.
MR. MENTZ explained that a technicality is that although many of
the provisions don't take effect until January 1, 2008,there is
authority to immediately begin developing the regulations even
though they wouldn't be adopted and effective until after
January 1, 2008.
3:09:11 PM
SENATOR WAGONER noted that he had asked about the corrosion
issue and the billings and he would like Ms. Davis' thoughts on
the increase in the capital and operation costs and how that
would relate to the amount that BP initially said it would cost
to replace that line. He recalled it was in the neighborhood of
300 some million dollars.
MS. DAVIS said that's the kind of prospective information DOR
would get under the bill, but it doesn't have access to that
information as yet. She suggested the most immediate way to get
that information would be to ask the parties that will be
testifying.
SENATOR WAGONER said he plans to ask that question.
At ease from 3:12:26 PM to 3:23:42 PM.
CHAIR HUGGINS reconvened the meeting.
3:24:26 PM
DAN DICKINSON, LB&A Consultant, said he had a short presentation
to provide context and a longer one that will go through the
legislation looking at issues that need to be raised. He stated
that he was formerly with the Alaska Department of Revenue and
did considerable work on the PPT.
STEVE PORTER, LB&A Consultant, relayed that he would make a
short presentation on a higher level analysis of the bill and
the associated issues.
MR. DICKINSON delivered a PowerPoint presentation beginning with
slide 4, which was a graph of Alaska's actual oil production
from 1965 to the present and the projected production from the
present to 2020. The largest area is Prudhoe Bay, which produced
1.6 million barrels/day at its peak and now produces around 400
million barrels/day. At the high point in 1988, the aggregated
fields brought the total up to 2 million barrels/day. Production
has been declining since that time and now it's around 700,000
barrels/day or 1/3 of what it was 15 years ago. The focus during
this period was on reinvestment and the issue of decline, he
said. When people talked about taxes, the economic limit factor
(ELF) was discussed and the question was whether changing ELF
would change the investment climate. The consensus was that it
would.
MR. DICKINSIN said that in 2003 some exploration incentives were
brought in, but the decline dominated all thinking. In those
days the production tax was the largest source of revenue for
the state. It outpaced royalties but because of the economic
limit factor, production taxes began a steady march down to the
point that it would become an insignificant tax.
SENATOR WIELECHOWSKI observed that since the taxes were so low
you would have thought there would have been a tremendous rush
of investment. He said he's never understood why that didn't
happen.
MR. DICKINSON replied there was investment. If you look at all
the production except Prudhoe Bay you will see that production
was increasing, he said. The point is, they weren't "elephants."
3:30:00 PM
SENATOR WIELECHOWSKI commented that supports the argument. The
investments were occurring in the areas that had higher taxes
than the taxes on Prudhoe Bay and Kuparuk.
MR. DICKINSON acknowledged that is partially true. The smallest
fields had no tax, but places like Alpine and Northstar came on
with rates that were as high as or higher than Prudhoe Bay. The
atmosphere changed with the change in the price for oil.
CHAIR HUGGINS remarked he's deducted that a challenge in getting
new exploration is that there are no new elephants and the cost
of a discovery for an "ant" is high risk. He asked if it's in
the ballpark to say we're trying to balance that risk with
finding the "ant" a small amount of oil.
Steve PORTER agreed that he's on the right path.
SENATOR WIELECHOWSKI brought up another concept that he's never
fully understood, which is that decreasing taxability will
result in more exploration than we had under ELF.
MR. DICKINSON displayed the slide, ANS West Coast Price from
July 77-Sept 07 that shows the absolute rise in the price of
oil. If people invested expecting returns from selling their
product in the $30 to $50 range there's a good deal on top of
that that's being generated, he said. An observation he'd make
is that the production tax is no longer talked about as a tax.
We're now talking as though we're entering a bidding round and
we're talking about leaving money on the table and promoting
ourselves to partners and wanting to share. That may or may not
be appropriate, but there's definitely a very different sense of
what we're doing here than there was when we were focusing on
the declining issues.
SENATOR WIELECHOWSKI responded the legislature and the experts
including Mr. Van Meurs, Mr. Johnston, Dr. Finizza, and Gaffney,
Cline have all said we could have increased our taxes and we'd
still have incurred investment.
MR. DICKINSON replied he's not disagreeing; his point is that
there's been a real shift in the last seven years.
MR. DICKINSON summarized the next two slides and noted that in
1988 2 million barrels/day were produced at a market value of
$15 for basically $30 million/day. Now production is just
700,000 barrels/day, but at $80 that's $56 million/day. The
point that people designing a system need to consider is what
700,000 barrels/day at $15 would yield. He clarified that he's
not making predictions about price dips, he's just saying that
any system needs to be robust enough to deal with those
variations.
3:36:39 PM
MR. DICKINSON referenced Article 1, Section 1, of the Alaska
Constitution, which is quoted frequently in tax circles and
noted that Chief Justice Marshall articulated that "the power to
tax is the power to destroy" and that "taxation is an absolute
power and like sovereign power of every other description, is
trusted to the discretion of those who use it." Tax is part of
the economic compact made in a society, which is very different
from entering into commercial ventures, he said. Although the
balance can change, the notion is that those are different ways
of thinking about it and as a society our thinking might be
changing.
MR. DICKINSON reviewed slides showing the increasing costs and
the projected $2 billion cost assumptions in the original fiscal
note and then the $4 billion spring 2007 forecast. Those numbers
are relevant because if you'd asked four years ago what the
State of Alaska's costs would be, probably very few people would
have said they would double. This is all part of the perspective
of why we're changing the way we're thinking about these things,
he stated.
3:38:53 PM
CHAIR HUGGINS recognized that Senator Dyson had joined the
hearing.
MR. DICKINSON explained that in 2007 the legislature passed a
budget and the DOR said there would be revenues from oil and gas
of $3 billion and there would be another $400 million of non oil
and gas for a budget of $3.4 billion. General fund
appropriations were $3.2 billion so the surplus was expected to
be $200 million. That was based on the ELF-driven production
tax. Two months later PPT had passed and the fiscal note said in
FY07 there will be an additional $420 million, which will be the
retroactive portion from 2006 that won't arrive until March of
2007 so it'll be counted as fiscal 2007 money. In FY07 the
payments will be $923 million for a total increase of $1.3
billion. Take the original estimate and add $1.3 billion to
arrive at $2.3 billion. Now you're looking at oil revenues at
$4.3 billion and the same non oil revenue for a revenue total of
$4.8 billion so the expected surplus was $1.3 billion.
MR. DICKINSON continued to say that a year later you see,
according to the un-finalized Spring Forecast, that the
projected $2.3 billion actually came in at $2.1 billion. That's
about $200 million off. As a percentage, that was one of the
best projections DOR made, he said. Looking at the figures, he
explained that the property tax projection was $36 million and
after a hearing on the value of the Trans Alaska Pipeline, it
was increased by 42 percent to $52 million. For the income tax,
prices were higher than anticipated so they went up 18 percent.
For the oil and gas production tax, the price forecast, volume
forecast, and cost forecast were all off, but the net effect was
very close to the projection.
SENATOR WIELECHOWSKI questioned if it's projected to be $800
million off next year.
MR. DICKINSON replied he's heard that figure, but he isn't sure
where it's coming from. He offered the belief that the $800
million is the difference between what the governor's proposal
is projected to bring in if that proposal had been applied
retroactively to the first day of the fiscal year. It's fine if
you want to define that as a shortfall, but that's different
from what you've been told in a fiscal note is going to be
available for the fiscal year. He said his point is that what
happened with the PPT is essentially as accurate as other taxes
that were forecast.
3:43:08 PM
CHAIR HUGGINS asked him to do the analysis because Alaskans have
a misconception of what the $800 million really means and how it
was derived.
MR. DICKINSON asked if he should compare what the fiscal note
said for 2008 and what the projection is now.
SENATOR WIELECHOWSKI suggested an apples-to-apples comparison.
MR. DICKINSON responded that would require waiting until the end
of 2008 and then looking back to see what came in. I'm doing
that now, he said.
SENATOR WIELECHOWSKI said DOR has forecast an $800 million
deficit.
MR. PORTER responded they can't figure out how to come up with
those numbers.
MR. DICKINSON added there's no deficit being forecast.
SENATOR WIELECHOWSKI said he understands that; it's an $800
million shortfall from the projection under PPT.
MR. DICKINSON asked, "In the fiscal note?"
SENATOR WIELECHOWSKI replied, "In the fiscal note."
MR. DICKINSON responded he believes he can show that isn't the
case.
MR. DICKINSON continued to say that royalties came in at about
what was projected because the price forecast was low and the
production forecast was high so one offset the other. He noted
that it's interesting that the non oil and gas was more
volatile. It was off by about 50 percent. Overall, the
difference was about $200 million.
CHAIR HUGGINS noted that he gave a number of non oil investment
categories to the commissioner of revenue because it shows a lot
of disparities between the projections and what actually
happened. That gets to the accuracy piece of the projections, he
said.
MR. DICKINSON observed that since 1990 when the Constitutional
Budget Reserve (CBR) fund was established, the issue has been
how much will come out of the CBR. A budget would be passed, the
revenue identified and the difference would be made up from the
CBR. The notion of getting a forecast to be dead on went by the
wayside because it didn't matter relative to how the budget was
being passed, he stated.
MR. DICKINSON questioned how a better forecast or closer
monitoring would have made a difference. He acknowledged that a
big mistake in the PPT legislation was not requiring this
earlier information and he applauds the measures in the current
bill.
SENATOR WAGONER referenced a prior presentation that used
$43.43/barrel oil. The status quo at that price would have
brought in $.9 billion. After credits the tax was going to bring
in $1.7 billion for a difference of $800 million. That's what we
came up with, he said, but that was with oil at $67 plus/barrel.
Where did we go wrong on projecting the credits that were to
come in, he asked.
MR. DICKINSON replied that the state had no experience in
estimating operating costs; and he understands that for 2007
they were off by 70 percent to 100 percent and the capital
investment nearly doubled. His point is that a lot of things
were underestimated. The $800 million likely came from adjusting
the "knowns" and isolating the affect on one thing. That tends
to overwhelm the things you've been adjusted for, he said.
SENATOR WAGONER said maybe we didn't ask the right people the
right questions when making the projections for CAPEX and OPEX.
That's an awfully large amount to be off when the legislature is
relying on the projections to set tax policy, he stated.
3:49:52 PM
MR. DICKINSON pointed out that the legislature did ask a number
of people and Mr. Van Meurs has said that if he'd been asked
directly he would have said they would be higher. A number of
folks looked at the numbers and nobody said they were out of
whack. Using the Matanuska Maid bankruptcy as an example he said
the point is that those sorts of things happen. You can have
some forewarning and sometimes you can get it right and
sometimes you don't. In this case, the cost estimates were
significantly low, as were the price estimates.
MR. DICKINSON directed attention to a one-page model he
developed of the main revenue issues of the PPT versus the
governor's proposal. It gives a sense of the general orders of
magnitude of some of the issues. All formulas are there and it's
not too complicated, he said. You can walk through making
assumptions about barrels and costs.
CHAIR HUGGINS asked him to go through the chart methodically.
MR. DICKINSON continued the explanation as follows:
The first column simply runs things over a range of
prices. Back in September when I first did this, $80
was considered the high end-and that's life in the
food-chain, I guess. We used 2008 estimate of volumes.
Now that was the earlier one. DOR is about to knock
40,000barrels/day off that estimate, but a flat 244
million taxable barrels/year. You multiply what you
sell it for times the number of barrels and so you
come up with a sort value in market. At $30/barrel
that's $7 billion at $80/barrel that's $19 billion.
You then subtract the downstream costs, which the
department estimated at $7.22 and that's tankering and
TAPS-the ones that have always been deductible even
under the so-called gross tax that we used to have.
You then subtract the upstream costs, which are about
$4 billion and I think as Senator Wagoner indicated,
in our initial estimates those were closer to $2
billion. If you look at the document that you're
looking at there [that Senator Wagoner indicated
earlier] it's $1.7 so more like 100 percent off.
They're closer to the downstream costs. Once you
subtract that, you get what's called the production
tax value or the net value. So again, at $30/barrel
you've got just over $1 billion. At $80/barrel you've
got $13.7 billion. And that's going to be the same
under the governor's proposal or under the existing
law.
The first change occurs when you then multiply that
times the tax rate. Under the current law it's 22.5
[percent], the governor's proposed 25 [percent] and so
in column H you get the difference and as you might
expect it's bigger at higher prices.
The next set of calculations between I and N is
progressivity. Again it's not really that complicated.
You simply take the production tax value, you divide
through by the barrels and so you come up with a
dollar per barrel value. … The starting point for
progressivity under the current law is $40, the
governor's proposed dropping that to $30. … Starting
at $60 and subtracting costs, under the current law
there's no progressivity. Under the governor's bill,
at $60 and $36 net, you have $6 worth of
progressivity. So you calculate the number of dollars
that you have and that's what's called the price
index. Under current law you multiply each dollar is a
quarter of a percentage point. Under the governor's
proposal, each dollar would be a fifth of a percentage
point so it'd rise less sharply. Then you simply
multiply that through so if you had $6.15 and 25
percentage for each dollar, that means that
progressivity is 1.54 percent. You mechanically can
add it to the base rate, in this case we're trying to
keep them separated, to show the results of
progressivity so you multiply that 1.54 percent times
your production tax value. And you can see at
$70/barrel, you generate $173 million in
progressivity.
There was earlier discussions today-folks were saying
how much was the progressivity piece. So this gives
you a sense. At $70…it goes up rapidly so at $80 its
$.5 billion.
The third piece down here simply subtracts the
governor's proposal from current law so it shows you
the change. And you can see that there is a couple
hundred million dollars of change in the progressivity
with increases in price levels.
SENATOR WAGONER asked how to calculate the difference when the
governor has progressivity on an annual basis and the original
bill had a monthly calculation.
MR. DICKINSON replied you don't calculate that in this simple
model. That is in his later presentation though because there
are going to be differences, he added.
3:56:54 PM
SENATOR WAGONER commented there will be quite a bit of
difference.
MR. DICKINSON agreed; potentially the differences can be huge.
He then referenced the slide showing ANS West Coast Price to
further demonstrate the point.
SENATOR STEDMAN asked if his model uses the Texas or West Coast
price.
MR. DICKINSON replied that would be ANS West Coast, which is
typically within $1.60 of ANS.
MR. DICKINSON continued to review the model. The next thing sums
up progressivity and the base line to come up with the total tax
before credits. Then you analyze the credits beginning with the
TIE (Transitional Investment Expenditures). The assumption is
that most of the producers paying the tax would have had
sufficient investment to generate TIE credits. They can be
matched 2 to 1 so he decided to make the TIE credit exactly one
half of what the investment credit is under bill section 023(a).
Under the status quo they would subtract $190 million and under
the governor's proposal they wouldn't. He continued:
Because this is looked at as a one year snapshot for
the first year, this is the only year in which you'd
see a substantial financial affect from the notion of
cutting credits in half and requiring to be applied
over two years. I guess in theory the very last year
you'd have the affect as well, but basically this year
you see it. The fact that it's being proposed to be
introduced on a calendar year basis means the fiscal
year affect will be fairly minimal. Again, this is
assuming that that change was in for the entire fiscal
year. Not just half of it.
So I've taken the full investment credit that would be
allowed for $1.9 billion, and that's $380 million, and
cut that in half. … It then shows you there's your
total cost. You then say, what is my tax net of those
credits? At $30, I'm wiped out and of course under the
governor's proposal you wouldn't be wiped out. There
would be a floor there. But I was mainly focused on
the ranges where we see things today and at $40/barrel
we're at $316 million [tax net of credits] and at
$80/barrel we're at $3 billion. Under the governor's
proposal … it's an incremental $200 million as you go
up each $10 of price.
MR. DICKINSON said his intention is to show how easy it is to
sit down with an Excel spreadsheet and play with the concepts to
get some sense of what's happening. Responding to a question, he
agreed to provide an electronic copy.
4:01:11 PM
SENATOR WIELECHOWSKI questioned how $30 versus $40 and .20
versus .25 impacts investment decisions by oil companies.
MR. DICKINSON recalled that Dr. Tony Finizza addressed that
question. Generally there's a company-wide price that all
projects are evaluated against and then there's a stress price
to evaluate against. Each company guards those numbers, he said.
CHAIR HUGGINS asked him to restate the information from the
slide titled FY 2007 comparisons because this bill is based on
projections.
MR. DICKINSON relayed it's easy to be critical of the
projections but it's difficult to come up with better methods.
What we do is take a set of knowledge and plug in a bunch of
assumptions that we don't have any particular insights into, he
said. He stated that the notion behind a revenue system is that
it needs to be robust and cover a wide range. Also, it made
sense to have a regressive system when Alaska was a young state
because money was needed every month to do things like maintain
roads and pay teachers. If there was a boom in the market the
state was content not to participate because with a regressive
system it was getting a baseline amount of money. The state's
more mature now and it has a savings account that has billions
of dollars in the unrestricted portion that is available for
appropriation. For lots of reasons the state can look at its
fiscal system and opt for a progressive system so that when
everyone is making a large profit the state gets more. But it
also means that when profits are smaller, the state gets less.
Under ELF the state got a larger piece when people were making
less. He said he believes that a lot of hard work goes into the
estimates, but they can't be guaranteed. They're simply the best
numbers that are available at the time.
4:06:51 PM
SENATOR STEDMAN asked how many barrels/day the model used.
MR. DICKINSON said he believes it was 760 barrels/day. All the
numbers came from the DOR Spring Forecast, he added.
SENATOR STEDMAN said he believes the Spring Forecast shows 995
barrels and the model shows 1.4 billion net of credits. The
general concept is to be conservative on forecasting revenue.
MR. PORTER advised that the administration has agreed to go over
the assumptions to explain how the results were achieved. The
idea is to create a public model that's within a percentage.
MR. DICKINSON clarified that the 2008 Spring Forecast price is
$54.72 and he believes they're at 983 barrels.
SENATOR STEDMAN questioned whether there's opportunity for a
surplus at the end of the year.
MR. DICKINSON directed attention to page 81 of the revenue
forecast and calculated that 700,000 barrels/day at $70 and a
general fund budget of $4.1 billion would bring a surplus of
$300 million. That gives a sense of movement with price, he
said.
4:11:35 PM
MR. PORTER began his presentation and advised that he would
touch on stability, Alaska's prospectivity, ACES incentives and
a general summary. Beginning with the issue of stability, he
noted that Pedro Van Meurs warned that you begin to look like an
unstable regime if you change the tax for what is arguably the
third time. Daniel Johnston has disagreed with that while
industry has repeatedly said you're moving in that direction of
instability. He said he tends to agree with Mr. Johnston in
terms of impact because stability is related to what happened at
each particular time.
MR. PORTER relayed that the oil industry continues to argue that
there was a tax change several years ago, prior to PPT. Pointing
out that to change taxes it's necessary to change the law, he
emphasized that there was not a change in either statute or
regulation. Basically, industry changed the way it managed wells
and oil on the North Slope and captured an additional benefit
under ELF. That's all that occurred; we simply applied the tax.
Oftentimes that's been interpreted as a change in tax and we've
politely not challenged that interpretation. But everyone knows
that wasn't an issue of stability, he said. It was an
application of law that happens all the time. Over time the
industry and the state have lots of issues over the application
of the regulations and the statute and this is just one more. It
was just a bit more public, he said.
MR. PORTER said the PPT came next. The situation was that over
time ELF didn't pick up enough tax, particularly in a high-
priced environment. That didn't make sense and everyone realized
that ELF was broken. The recognition that the tax would need to
change merged with industries need for stability, a stranded gas
contract, and a reasonable tax. They lost on all three counts,
he said, and that wasn't expected. That is the first change, he
said.
4:16:32 PM
MR. PORTER described the current situation as the second point
in time. According to the governor, a cloud on the decision-
making occurred during the PPT change of tax and so it's
necessary to go back and see if the right decision was made.
There are a number of ways of looking at the tax and the $800
million, but ultimately it doesn't matter. We're here so let's
figure out what to do from here. Figure out the right answer,
get it done and move forward, he said. But if you do work
through this process and make a change you will be moving into a
more unstable world if you immediately make another change, he
cautioned.
MR. PORTER turned to Alaska's Prospectivity and said he'd walk
through oil and then gas. From the Colville through the Canning,
the state land with oil underneath is a mature region.
Referencing page 5 of Mr. Dickinson's presentation, he said
we've found the elephant and all that's left is puddles. Move
out into NPRA where the wells cost considerably, more and you
see a changing economics factor for drilling wells. From the
standpoint of attracting people, he said we're not the most
prospective state in the world. Nobody is going to drill,
regardless of the incentives unless you're willing to pay over
100 percent and at this point the state isn't willing to do
that.
With regard to competition he said we have three sets. First
there's the Coleville and Canning competition, which is a mature
field that only has puddles in remote regions so the costs are
high. A second competition region is NPRA. That's what he calls
the Alpine type region. Those are pretty good size fields but
the oil is expensive. A rough estimate is between $30 million
and $50 million, which is a lot of money if the hole is dry. He
noted that when you shift from state lands you lose the royalty
and that's not exactly prospective to the general fund budget.
He elaborated that you get half the value that goes to the
federal government, but it goes through a gauntlet to get
anywhere. If anything is left after paying impact funds to the
five communities in the North Slope Borough, then you go through
a formula for funding PCE. Then you go through the next funding
formula that pays for some type of credit fund for education. If
anything is left, there's a possibility that some of the money
will go to the general fund. He doesn't recall that ever
happening. Most of it has stayed on the North Slope. You do get
tax out there though so that is a benefit and that's why capital
credits make sense there. Those puddles are much bigger than the
ones between Colville and Canning, he said.
MR. PORTER noted the difference between the industry models and
state models. If you model a prospect from either standpoint
there are lots of bells and whistles in terms of taxes, risk
factors and other sensitivities, but take the reserves component
alone and if you spread it to a bell curve, it really fattens up
the economics. Geology is king, he said. If you have the
geology, you will have the players because with big geology and
big elephants, industry is willing to take big risks.
MR. PORTER said the third region of competitiveness is the OCS.
It truly does compete with elephants simply because there hasn't
been enough drilling out there to know if there are still any
elephants. Shell Oil is there and ready to spend billions on
drilling in the OCS. The only problem is the state doesn't get
any tax or royalty money from drilling on the OCS and that
represents more than 50 percent of the potential oil and gas
discoveries on the North Slope. That isn't the deal in the Gulf
States. Those states have figured out that since they are
carrying the risk, the federal government ought to pay a portion
of the funds. He suggested that Governor Palin ought to be back
in Congress working with the delegation to get a proportionate
share off the OCS before Shell Oil drills the first well.
4:26:03 PM
SENATOR WIELECHOWSKI asked if the state could capture some value
by taxing the oil once it comes on shore.
MR. DICKINSON recalled some cases and said he believes the main
tax area will be the facilities that are on shore. It is
something that needs to be negotiated with the federal
government. The state can't assert a tax on something outside
the realm and it can't assert a tax on the passage of offshore
oil or gas through the realm.
CHAIR HUGGINS commented everyone can't take a piece of the pie
simply because it crosses the border.
MR. PORTER said the next thing to look at is the huge resource
of heavy and viscous oil. Because the oil industry will tap that
resource, he cautioned members to ask if things in this bill
will negatively impact that ability. He emphasized that the
taxing structure should positively encourage the development of
those resources because producing the reserves dwarfs everything
else. Clearly it's more important than the tweaking we're doing
here. Tweaking is within you purview but don't take some of
these options off the table, he cautioned. He said later he
would touch on how he thinks this may be impacted by the current
proposed tax.
SENATOR WAGONER questioned why it isn't possible to measure
heavy oil that's going into the system to come up with a
percentage and then a different tax system to encourage further
development of heavy oil. He asked if that's unreasonable.
4:30:53 PM
MR. PORTER suggested looking at the units Orion, West Sak, and
Ugnu because you can almost identify the complexity and the cost
of the well by what the unit is producing. He continued to say
that the net basis and the 20 percent capital both work well if
industry spends capital money on infrastructure and if they
spend money on new development for places like West Sak to bring
on additional reserves. Also you want industry to spend money on
exploration. All three elements are important and right now the
market is working and they're doing all three. It doesn't mean
we've hit the sweet spot, but it's functioning.
SENATOR WAGONER clarified that's at $80 or the higher rate of
oil.
4:32:48 PM
MR. PORTER responded that goes to his next statement, which is
what happens when oil is at $40. He noted that Field A that was
discussed yesterday had problems with the 10 percent gross tax
and at $40/barrel oil it was right on the margins. He reminded
members that when an oil company runs an economic analysis, each
company uses a single price for consistency between divisions.
Also they run economics on a stress price. Although it was said
that the stress price is $40, he's more conservative because
he's seen the world at lower levels. He emphasized that we don't
know what the future holds, but we do know that you must cover
the high, middle, and low to ensure that the state is positioned
properly to encourage development at a particular time. Allow
for uncertainty to occur and encourage development to occur over
time, he said.
MR. PORTER shifted to gas and said that in Alaska gas is not
mature. The Foothills, NPRA, and OCS haven't been explored
largely because you can't market the gas. Mr. Van Meurs said the
gas pipeline is uneconomic, but he would describe it as
indeterminate because of three elements that apply to a fourth.
First, the cost of the pipeline is undetermined and that won't
change much until you've spent closer to $1 billion and have
certainty enough to know if you should go forward. Nobody will
spend that amount by November, but they will have an estimate.
Second, we don't know the future price of gas. We don't know how
the gas play will come out in the future so that's risk. The
third element is tax stability. Industry has always been afraid
that the state will raise taxes and remove the profit after
starting to build the pipe. All this rolls into an internal rate
of return and basic project evaluation criteria to determine
whether you think it'll be economic before building the pipe.
You won't know if it is truly economic until well after the pipe
is built. By 2030 you'll have a pretty good idea of whether or
not you made a good decision, he said.
4:39:06 PM
SENATOR WAGONER said he asked Chair Huggins to contact Mr. Van
Meurs to define what he was talking about. In another
presentation he said he was basing his statement on the line
that was discussed in 2000 and 2001, which was the 52 inch
producer-line using new steel and new technology and running to
Chicago. We'll look at a lot of different scenarios before we
reach that point, he said.
MR. PORTER added that Mr. Van Meurs was also basing his
statement on today's price with estimated increased costs, but
that's based on assumptions that may or may not occur in the
future.
CHAIR HUGGINS recalled Mr. Van Meurs said liquids would work.
The committee needs to hear from him to understand his
rationale. We've also asked the administration to analyze his
statement, he added.
MR. PORTER said his second recommendation relates to what to do
with a gas pipeline from here. He relayed that when he worked on
the gas pipeline project, every day he asked himself how to best
move the project forward. It wasn't how to move stranded gas
forward or how to move the Canadian pipeline forward. To him,
the project was monetizing the 36 tcf on the North Slope. With
that in mind he suggested members ask if the activity today will
enhance that potential. In his view it's the legislature's
responsibility to review all the information and figure out the
best path for moving forward. Don't lock down on a specific
process; allow the facts to change your direction if it's
appropriate. That's what you should do in November after the
applications come in, he said.
4:43:43 PM
MR. PORTER turned to the issue of timing the development and
said the faster you can bring on development the better. It
takes time to bring on oil after discovery. Six to eight years
is probably a reasonable timeframe if you use the major
facilities, but it there are environmental difficulties or local
issues that timeframe gets extended. For this gasline it'll take
ten years easily, he said. Any estimate that's less than that is
probably skipping steps and creating additional risk. He
clarified that's for the Canadian project.
4:45:42 PM
MR. PORTER commented there's a lot of rhetoric about how ACES is
an incentive to exploration and development and that it brings
incentives because of capital investment. But, he said, ACES
didn't create the capital investment, PPT did. If you look at
the differences the only thing you can say is it hurts some
parties less than others. When you take money out of someone's
pocket, you make it less economic for them, but that doesn't
mean that decision-making will necessarily change. He said he
does know that the gross tax of 10 percent on the bottom,
definitely is a big burden on West Sak and Orion and some heavy
and viscous oils because their cost of doing business is in the
$40s. Don't take money out of industry pocket in a low priced
world, he cautioned. It won't encourage exploration and
development in the future.
MR. PORTER encouraged the committee to remove the minimum tax
from the bill, but said the other elements of progressivity and
changing the 22.5 percent to 25 percent are policy calls.
4:48:10 PM
SENATOR WIELECHOWSKI referred to a presentation Mr. Van Meurs
made, which was 25 percent with a gross at $50 and .25. He asked
if that could be done without hurting investments.
MR. PORTER said he hadn't modeled the impact of that because he
hadn't seen that curve. You're trying to create a sharing curve
and a lot of economists like a net sharing curve versus a gross
sharing curve. Look at the curve and figure out how much more
you want to pick up, he said. Only do it once though and then
walk away for about 15 years. Take time, do it thoroughly, and
make your decision.
MR. DICKINSON noted that slide 8 illustrates that model.
SENATOR WIELECHOWSKI asked if the state could increase the
valuation of oil and not discourage investment.
MR. PORTER said there is room.
SENATOR WAGONER commented he didn't agree with the PPT but he
voted for it because he wanted a bill. The problem here is
there's a 2011 review date. He asked if having a clause like
that in a tax bill isn't more dangerous than changing from one
year to the next.
4:51:19 PM
MR. PORTER opined that industry isn't worried so much about the
tax review as the fiscal stability and long-term fiscal plan. If
you want to make a stable environment, then figure out how to
put a lot of the surplus money in the CBR and pay back the $5
billion you owe, he said. Then you'll begin to develop a fiscal
plan that shows you're stable, conservative and responsible with
the money you make in taxes. Do that and these companies will
drop their risk factors, he said. That's what they're looking
at.
SENATOR WAGONER thanked him for the perspective.
CHAIR HUGGINS thanked the participants, outlined the schedule
for the following day, and adjourned the meeting at 4:53:04 PM.
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