Legislature(2013 - 2014)BARNES 124
02/20/2013 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB72 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 72 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 72-OIL AND GAS PRODUCTION TAX
1:04:35 PM
CO-CHAIR FEIGE announced that the only order of business would
be HOUSE BILL NO. 72, "An Act relating to appropriations from
taxes paid under the Alaska Net Income Tax Act; relating to the
oil and gas production tax rate; relating to gas used in the
state; relating to monthly installment payments of the oil and
gas production tax; relating to oil and gas production tax
credits for certain losses and expenditures; relating to oil and
gas production tax credit certificates; relating to
nontransferable tax credits based on production; relating to the
oil and gas tax credit fund; relating to annual statements by
producers and explorers; relating to the determination of annual
oil and gas production tax values including adjustments based on
a percentage of gross value at the point of production from
certain leases or properties; making conforming amendments; and
providing for an effective date."
1:06:12 PM
THOMAS K. WILLIAMS, Senior Royalty and Tax Counsel, BP
Exploration (Alaska) Inc., presented a PowerPoint titled "BP
Testimony to House Resources" and paraphrased from a prepared
statement:
Thank you for inviting us here to testify on House
Bill 72, which has been introduced by Governor Parnell
and proposes to amend the so called "ACES" production
tax on oil and gas produced in Alaska.
There are three primary changes that HB 72 would make
to ACES: one, repeal progressivity, which we think is
good; two, change the system of tax credits that now
exists, which threatens to harm some producers even if
it may help others; and three, create a new "gross
revenue exclusion" for new production that we view as
innovative but largely misdirected. My testimony today
will review these changes in the context of the tax
issues that my employer faces under the present tax,
which the Governor and apparently the entire
Legislature, with the introduction of Senate Bill 50,
agree needs to be reformed.
First, progressivity. As you know, progressivity is a
sliding-rate tax that runs quickly up to a 25 percent
rate and then rises more slowly above 25 percent. It
is in addition to the basic 25 percent tax that is
also levied on the "production tax value" of a
producer's taxable production. Repealing progressivity
is a good idea for a number of reasons, which AOGA has
identified in its testimony on Monday and which other
taxpayers will probably present to you as well. Many
of those objections are for effects from progressivity
that were intentional as part of the way progressivity
was designed. What I'd like to do today is to describe
two significant, unintended effects of progressivity
that seem largely unknown and even less understood. I
have eight slides to present that will show you
exactly what these unintended consequences are.
1:08:01 PM
MR. WILLIAMS directed attention to slide 3, "How ACES works,"
and continued:
To begin, let me quickly review how the tax is
calculated for the example I will use.
If you look at this first slide, you will see the tax
calculation for a hypothetical producer with 10,000
barrels of oil who sells it on the West Coast for $100
a barrel and receives a million dollars. It cost
$150,000 - or $15 a barrel - to transport that oil
from the field in Alaska to the West Coast, which
leaves $850,000 as the gross value at the point of
production or "GVPP." The producer had $300,000 of
allowable lease expenditures, or field expense, to
produce the oil, which leaves a taxable production tax
value, or "PTV," of $550,000 or $55 a barrel. The base
tax is 25% of the PTV, or $137,500. The progressivity
rate equals four tenths of a percentage point times
the difference between $30 and the producer's PTV per
barrel. Here the difference between $30 and $55 is
$25, and $25 times four tenths of a point per dollar
equals 10 percent. Ten percent of $550,000 is $55,000
of progressivity tax. That plus the base tax of
$137,500 equals a total tax of $192,500. So far there
is nothing here that is new to you.
So now let me begin to show you something you probably
have not seen before. This scenario is not about what
the producer has actually produced, but about an
evaluation of what could happen from the development
of a new reservoir or field if the investment is made.
And let's suppose that this producer sees three
different ways that she could potentially improve this
investment. One is that she knows of a buyer willing
to pay a premium of a dollar a barrel for the oil
delivered on the West Coast, the second is a way to
save $20,000 in transportation costs, and the third is
a way to cut the costs for field operations by
$30,000. If she can do all three, what is the change
in the tax?
1:10:08 PM
MR. WILLIAMS presented slide 4, "Example - The three changes
together, and continued his explanation:
In this slide we see the three changes. The extra
dollar a barrel in the price increases the sales
revenue from the oil to $1,010,000. The transportation
savings reduces that cost from $150,000 to $130,000.
Between the increased price and the transportation
savings, the GVPP of the oil back in the field is
$880,000 instead of $850,000. And the reduction in
upstream lease expenditures raises the taxable PTV by
another $30,000, for a total increase in PTV of
$60,000 from $550,000 to $610,000.
The 25% base tax is now $152,500 instead of $137,500.
And with PTV per barrel now $61, the progressivity
rate is $61 minus $30, or $31, times four tenths of a
percentage point per dollar, or 12.4 percent. Twelve-
point-four percent of $610,000 is $75,640, and the
total tax is $228,140 instead of $192,500. This is an
increase of $35,640.
I have highlighted this change in yellow and recorded
it in the upper right corner of the slide in order to
keep it on screen so we can remember what it was,
because in this scenario the producer next asks what
the tax change is separately for each of these
improvements to the investment. This next slide shows
the change resulting only from the extra dollar in the
West Coast price.
1:11:48 PM
MR. WILLIAMS pointed to slide 5, "Price change only," and
described:
The higher price increases the sales proceeds by
$10,000 to $1,010,000. And as you go down the "As
Revised" column you see this $10,000 flowing down into
the $860,000 GVPP and then into the taxable PTV,
raising it to $560,000. The 25% base tax on $560,000
is $140,000. The progressivity rate is $56 minus $30,
or $26, times four tenths of a percentage point per
dollar, which is 10.4 percent. Ten-point-four percent
of $560,000 is $58,240 and the total tax is $198,240,
an increase of $5,740 from the base case. Again, I
have recorded this at the right side of the table so
we can remember what it is without having to flip back
and forth between slides.
The next slide shows the change in tax from the
$20,000 savings in transportation costs.
1:12:44 PM
MR. WILLIAMS summarized slide 6, "Transportation cost savings,"
and informed the committee:
The $20,000 again flows straight down into the taxable
PTV, increasing it from $550,000 to $570,000. The
progressivity rate is now $57 dollars minus $30, or
$27, times four tenths of a percentage point per
dollar or 10.8 percent. That plus the 25 percent base
rate on $570,000 of PTV yields a total tax of
$204,060, an increase of $11,560 from the base case.
This, too, I have recorded on the right side of the
table.
1:13:24 PM
MR. WILLIAMS furnished slide 7, "Whole is greater than the sum
of its parts," and indicated:
Finally, this next slide shows the effect of saving
$30,000 in field expense. The PTV increases by $30,000
to $580,000, the progressivity rate is 11.2 percent.
The base tax and progressivity add up to $209,960 - an
increase of $17,460 from the base case.
And here at last, this slide shows what it is that you
probably have not seen before. The sum for the three
changes separately is $34,760, which is in bold font
to make it easier to spot. This is less than the
$35,640 change in tax when all three are factored in
at once (also in bold font). In other words, with
progressivity, the whole is greater than the sum of
its parts. And that's not all. The amount of tax that
is calculated for each individual part changes,
depending on what order you look at them.
1:14:24 PM
MR. WILLIAMS directed attention to slide 8, "ACE's continuously
changing tax effect," and continued his discussion:
Here's a slide that looks at the $20,000 savings in
transportation cost and the $30,000 reduction in field
expense together.
The two cost reductions together increase PTV by
$50,000, to $600,000. The base tax on that is
$150,000. Progressivity for $60 of PTV per barrel is
$60 minus $30, or $30, times four tenths of a
percentage point per dollar, or 12 percent, times
$600,000, which is $72,000. The total tax change from
the two is $29,500. From the previous cases where we
considered each cost reduction separately, the tax
increase with transportation only was $11,560 and for
field BP expense only was $17,640, and these appear in
the upper right of the slide.
If we look at transportation first, it is equivalent
to looking at it standing alone, and we have already
calculated what that is - $11,560. So $11,560 of the
combined $29,500 tax increase is from the change in
transportation cost, and the rest - $17,940 - is for
the change in field expense. But this means the field
expense is almost $500 greater than what it is when
it's standing alone. And if you reverse the order,
then the field-expense tax increase is the same as
when it stands alone, but now the tax increase for the
transportation savings is different -$12,040 instead
of the $11,560 when it stands alone or is taken first.
What we have done here on this [eighth] slide is to
look at the pair of cost savings for downstream
transportation and upstream lease expenditures, and
we've looked at that pair first, ahead of the change
in market price. If we go back to the previous slide,
we see that if we take transportation first and
subtract its $5,740 from the total $35,640 tax effect
for all three, then that leaves a different number -
$29,900 - for this pair of changes instead of the
$29,500 we have here on slide six when we calculate
that pair back first.
There is nothing special about this particular pair of
changes that creates this difference. There would be a
similar difference if we pair price with
transportation or price with lease expenditures. With
either one, we'd get one set of tax effects for this
pair if we calculate them first, and a different set
of tax effects if we calculate the effect of the
unpaired change first. And, as here, within each pair,
there is a different cost for each change in that
pairing depending on whether its effect is calculated
first or the other's effect is first.
These examples involve a triplet of categories of
change that could be made to improve the economics of
the project: an increase in price, a reduction in
transportation costs to market, and greater efficiency
in field operations. But I have simplified these
examples by using lease expenditures generically as a
single cost category. In the real world a would-be
investor would look at capital expenditures separately
from operating costs because the timing for when the
two kinds of cost are incurred is different and -
especially important in the context of analyzing tax
effects - the capex generates a 20 percent Qualified
Capital Expenditure tax credit in addition to changing
the PTV and the progressivity rate. So there are
really four categories of change to look at: changes
in sales price, changes in transportation costs,
changes in operating expense, and changes in capital
expenditures.
For each one of these four categories, its respective
tax effect can be calculated separately from the other
three, either ahead of them or after them. And each
such triplet of changes has the same analysis and the
same variations in tax effect for individual changes
that we have seen in the entire analysis that we have
just gone through in this and the four earlier slides.
1:19:35 PM
CO-CHAIR SADDLER asked for clarification to the same change in
tax, $29,500, for both the revised and change in tax on slide 8.
MR. WILLIAMS explained that when they were paired together it
was $29,500, but if the previous slide was reviewed, he noted
the total of $35,640, which, when $5,740 was subtracted, would
leave $29,900 as the difference. He clarified that this was
different than the $29,500 on slide 8, the result of calculating
the pair. He declared that the point was that "even for a pair,
its value changes depending on the order that you do with
respect to the unpaired one."
1:20:32 PM
REPRESENTATIVE SEATON compared this calculation to the education
funding formula, as the regulations for both dictated the order
for the calculations. He expressed his presumption that the
Department of Revenue (DOR) had regulations for the order of the
calculations for the production tax value. He pointed out that
this was a "step-wise calculation" and he asked for the
difference of this to any other important sequential formulas
used by the state.
MR. WILLIAMS responded that DOR had regulations about the order
in which to take the tax credits, but there were not regulations
for the order in which to calculate the tax. He declared that
the aggregate amount was being used in this sensitivity analysis
to compare the effects of changes on other parts, and that there
was not a correct answer for the amount of tax on a particular
parameter in the equation.
REPRESENTATIVE SEATON opined that, as there had not yet been an
audit, DOR needed to specify the order of calculations to allow
an answer.
1:23:18 PM
CO-CHAIR FEIGE pointed out that this assumption was not so much
for the actual payment of the tax, but rather for the "what if"
analysis when determining the effect on the company of an
investment.
MR. WILLIAMS agreed and explained that the tax calculation was
simple, as it was all three components taken together, and it
was affected by the sequence. He clarified that these were
examples of investment scenarios when it was not possible to
make all the individual changes. He stated that these "what if"
analyses would not offer a clear answer, and could vary greatly
when applied to many components. He noted that these
differences were small until applied on a large scale.
1:25:14 PM
CO-CHAIR SADDLER directed attention to slide 7, and asked for an
explanation to the $35,640 total for all three taxes, which was
different than the $34,760 when each was added together.
MR. WILLIAMS replied that this was a result of the three numbers
being calculated separately.
1:26:02 PM
MR. WILLIAMS declared that the point of slide 7 was to show that
for each of the categories, its respective tax effect could be
calculated separately from the others. If you looked at one at
a time, the effect for each triplet would vary, and the
complexity would compound on itself, especially when the fourth
category for capital expenditures was added. He stated that
"each triplet will again have the same effect that the sum of
the individual components will be smaller than the tax effect
from looking at all three of them together... and if it sounds
complicated, that's the problem." Directing attention back to
slide 8, he stated:
the tax effect for the entire triplet being greater
than the sum of the effects for the individual
categories in it; the different amount for the
unpaired category in each triplet relative to the pair
of other categories, depending on whether the effect
of the pair is calculated first or second; and within
each such pair, the different amount depending on
which category in that pair is calculated first. Each
of these numerous variations and combinations will
divide the $35,640 total tax effect up into a
different set of amounts calculated for the four
categories. Yet even with all those sets of calculated
amounts for the categories, none of those sets will
add up to the tax effect for all the changes taken
together as a whole. And all this complexity doesn't
begin to reflect the likelihood that there may well be
several different changes that could be made within
one or more of these four basic cost categories. These
bizarre effects are not mere abstract curiosities. If
you are an investor and you have a variety of ways to
try to improve the performance of an investment, these
effects from progressivity mean there is no single
correct answer about how much each one changes the tax
and improves the investment. The more ways you have to
improve the investment, the more the change in tax for
each one depends on where you put it in the sequence
of calculating the changes for all of the
opportunities. This is because each opportunity in
that sequence not only increases the PTV, but it also
increases the progressivity rate applicable to the
base case PTV plus all the PTV that has been added by
the prior opportunities in the sequence.
Interestingly, the Department of Revenue has exactly
the same problem when it audits a taxpayer and makes
multiple changes to figures reported on the tax return
and increases the amount of tax. The auditor can
quantify the whole tax increase from all the changes,
but he or she cannot make a definitively correct
determination of the amount of any one of those
changes.
A taxpayer might have an interesting time in an appeal
having an auditor admit, issue by issue, that there is
no correct amount for each one.
1:29:44 PM
MR. WILLIAMS briefed the committee on slide 9, "Flat price
scenario."
There is a second unintended consequence of
progressivity that is also important. I call it a tax
on price volatility because it increases the tax when
prices change during a tax year even though the total
PTV is exactly the same as if the prices had stayed
constant at the average price for the year.
On this slide we see such a "flat price" scenario. To
fit conveniently within the space available in a
slide, the table omits columns for West Coast prices,
transportation costs and field expenses, and starts
instead with the PTV that is calculated from them.
Here the PTV is $61.25 per barrel, and with 2 million
barrels of production a month, the amount of the
taxable PTV is $122.5 million a month. Progressivity
starts when the PTV per barrel exceeds $30, and it
reaches 25 percent at a PTV Progressivity starts when
the PTV per barrel exceeds $30, and it reaches 25
percent at a PTV per barrel of $92.50.
I have chosen $61.25 as the PTV per barrel in this
base case because it is half way between $30 and
$92.50. The progressivity rate at this price is $61.25
minus $30, or $31.25, times four tenths of a
percentage point per dollar, or 12.5 percent. This
also is half way between the zero rate at $30 and the
25% rate at $92.50. As you can see, each month the PTV
is $122.5 million, the progressivity rate is always
12.5 percent, and the progressivity tax is exactly the
same for each month as $15.31 million. Total
progressivity for the year is $183.75 million.
1:31:22 PM
MR. WILLIAMS moved on to slide 10, "Progressivity increases
taxes with fluctuating price even when the economics don't
change."
In this next slide the left half is exactly the same
as the previous one with the flat-price scenario. The
right half of the table shows what happens when there
are six months in the year when the PTV per barrel is
$30 and six when it is $92.50. In this case the first
three months and the last three have the $30 PTV per
barrel, and the middle six from April through
September have the $92.50. This price profile
resembles what actually happened with West Coast
prices for North Slope oil during 2008, when they
peaked at the all-time record of $144.59 a barrel on
July 3rd.
For the six months when the PTV per barrel is $30, the
progressivity tax rate is zero because $30 of PTV per
barrel minus the $30 threshold for progressivity is
zero. So, as you can see, there is no progressivity
tax for the first three months of the year and the
last three. In the middle six, the PTV per barrel is
$92.50. That is $62.50 higher than the $30 threshold,
so the progressivity rate is four tenths of a
percentage point times 62.50, or 25.00 percent. At
$92.50 a barrel, the progressivity tax on two million
barrels a month is $46.25 million, so the total
progressivity tax for the six non-zero months is
$277.5 million.
The progressivity tax under the changing-price
scenario is 51 percent higher than the $183.75 million
of progressivity for the flat-rate scenario.
This tax increase is entirely the result of the fact
that prices changed during the year instead of being
flat. You can see this for yourselves. The total PTV
for the year in the right-hand column is 1,470
millions of dollars, or $1.47 billion - exactly the
same as in the flat-price scenario on the left. Total
production for the year is exactly the same - 24
million barrels. Dividing $1.47 billion of PTV by 24
million barrels equals $61.25 per barrel, exactly the
same. But progressivity is 51 percent higher. And if
you look at the monthly calculations in the changing-
price scenario, you can see that the monthly
progressivity tax will be exactly the same for each of
the $30 months no matter what order you put those
months in. The same is true for the $92.50 months. So
this phenomenon is different from what I showed you
earlier about the whole being greater than the sum of
its parts, because here there are no changes in the
actual progressivity calculation for a $30 month or a
$92.50 one.
1:34:31 PM
MR. WILLIAMS continued:
The bottom line here is this. The year under the
changing-price scenario is just as profitable as the
flat-price one, and for the same amount of production.
The tax base to which progressivity applies is exactly
the same for the year. Yet the tax is 51 percent
higher when prices change during the year.
Now, I have chosen these PTV-per-barrel figures so
they would show the greatest amount of tax increase
resulting from prices that are not flat all year long.
I did this because, if I showed you an example with a
smaller effect, someone would surely ask me what the
maximum effect could be. My example gives you that
answer at the same time it explains the phenomenon.
1:35:05 PM
CO-CHAIR SADDLER asked to clarify that this reflected one real
scenario.
MR. WILLIAMS replied that it resembled what happened in 2008, as
the year started out with lower prices, spiked in mid-year, and
then declined later in the year.
1:35:37 PM
REPRESENTATIVE SEATON noted that the monthly calculation was
specifically designed as a windfall profits tax calculation. He
asked to clarify that the objection was for the windfall profits
section to progressivity which was calculated monthly to take
into account this scenario of a huge spike, and not to the
mechanics.
MR. WILLIAMS clarified his objection, stating that there was no
windfall for the year, as it was a yearly tax with estimated
monthly payments. He stated that part of the reason was that
the source was the calculation of progressivity with monthly
prices and an average for the annual cost.
1:37:08 PM
REPRESENTATIVE SEATON questioned whether this was a yearly tax
or a monthly tax calculation with an annual true-up.
MR. WILLIAMS agreed that it was part of the design, but he did
not know if the intent was for the tax to add up for the year,
without a windfall. He declared that the tax was potentially 51
percent higher because prices changed, and that the tax worked
as if there was a windfall, even if there was not one.
1:38:31 PM
REPRESENTATIVE HAWKER declared that it had been a conscious
policy call of the legislature.
MR. WILLIAMS recalled it had been intended to avoid tax payment
when prices fell at the end of the year, instead using higher
price estimates that had occurred earlier. He opined that there
was not an intended effect for taxes merely because prices
changed, but there was intent to provide tax relief for the
installment payments at the end of the year if prices were going
down. He offered an apology if he had misunderstood or
mischaracterized the intent.
REPRESENTATIVE HAWKER agreed that there was not a point to
debate, although he emphasized that this was the way it was
intended to work, "right or wrong, good or bad."
1:40:51 PM
CO-CHAIR FEIGE expressed his belief that Mr. Williams' point
that "it is the way it is" made a forecast much trickier.
MR. WILLIAMS repeated that for one scenario there was still a 51
percent higher tax on the same production.
1:41:14 PM
CO-CHAIR SADDLER offered a metaphorical comment that
progressivity treated "the peak of a storm surge as the mean
high tide level in taxes accordingly."
MR. WILLIAMS agreed.
1:41:28 PM
REPRESENTATIVE P. WILSON reflected that, with all the activity
and amendments on the floor at the time of ACES, some members
did not understand the ramifications. She offered her belief
that there had not been adequate discussion for the
relationships.
1:42:21 PM
DAMIAN BILBAO, Head of Finance, BP Exploration (Alaska) Inc.,
affirmed that, whatever the intent, there were unintended
consequences from this policy, one of those being that it was
not possible to fix just one piece, as another piece would
impact the model. He declared that it was not just
progressivity, but the fundamental effect of each piece on each
other, including the credits and the base rate. He emphasized
that it was important to understand the effect of each factor on
each other.
1:43:23 PM
REPRESENTATIVE SEATON offered some background on the early
decisions regarding progressivity. He stated that, as the
original PPT bill was designed, progressivity was reviewed and
established as a windfall profits component in the first
committee of referral, the House Resources Standing Committee
(HRES), and not on the House floor. He reported that, although
the numbers may have changed, progressivity was included in
ACES. He clarified that HRES had designed progressivity as a
"fundamental building block" of the original PPT legislation,
and it was ultimately included in ACES.
1:45:05 PM
REPRESENTATIVE P. WILSON reflected that there had been
discussion about a windfall tax.
1:45:18 PM
CO-CHAIR FEIGE suggested a continuation of the presentation.
1:45:27 PM
MR. BILBAO pointed out that this was an attempt to illustrate
the impact of that intent, whatever that intent was, and how it
affected the decision making. He declared that, as there was
not a flat price, the average price produced a significantly
different yearend tax, which had consequences for business
decisions.
1:45:56 PM
MR. WILLIAMS announced that, in light of this discussion, he
would modify somewhat from his written testimony. He stated
that progressivity had at least one unintended consequence, and
another consequence that was larger than originally intended.
He summarized:
First, when you are analyzing combinations of steps to
take to improve an investment opportunity, the whole
is greater than the sum of its parts. Second, if you
do not take into account the effect from price
volatility during each year in an investment's life,
the progressivity could turn out to be 50 percent
higher than what you have estimated. Both of these
unintended effects promise to increase the risks and
reduce the competitiveness of an Alaskan investment
relative to a comparable one elsewhere.
These negatives of progressivity complement what AOGA
told you during its testimony last Monday. Without
repeating that testimony here, I will only list AOGA's
main points. One, progressivity sacrifices the one
advantage Alaska has from its economic remoteness -
namely, the greater improvement in financial
performance for investments here if prices turn out
better than projected - because progressivity taxes
away more and more of that improvement the better it
turns out to be. And two, progressivity makes the tax
extraordinarily complex and inconsistent to compute,
and to analyze.
For these reasons BP fully endorses the proposed
repeal of progressivity that House Bill 72 proposes.
1:48:17 PM
MR. WILLIAMS addressed slide 11, "Production Decline is Real,"
and continued with his testimony:
Let me now turn to the second main feature in this
Bill - the changes it proposes to the present system
of tax credits, and in particular to the sunset of the
credit for "qualified capital expenditures" or "QCE"
at the end of this calendar year.
The first, and probably most important observation I
can offer about tax credits in general is they would
not be so significant for the economics of oil and gas
production here if the production tax were not so
high.
Second, the QCE tax credit depends solely on how much
a company invests for oil and gas exploration,
development and production in Alaska. Period. If you
want to address the North Slope decline curve, there
have to be investments here leading to more production
- not just by finding and developing new fields and
new reservoirs, but also by getting more recovery out
of fields already in production. The QCE tax credit is
a direct incentive for making these investments. And
it costs the State nothing unless there are
investments: if investment is zero, then 20 percent of
zero is zero. The QCE tax credit arises only when it
succeeds, and costs nothing if it doesn't.
The QCE tax credit is not affected by oil prices, the
costs of transporting oil and gas to market, nor the
operating costs of the field. Consequently its value
to a business like BP's is the same for a given amount
of QCE expenditure, regardless of the price and the
transportation and field operating cost scenarios that
the business estimates in its investment decisions.
And it is the same regardless of how prices and those
other costs actually turn out. Progressivity, on the
other hand, is dependent on prices and costs in a
twofold way: once in determining the amount of PTV
that is subject to tax, and again in calculating the
tax rate that progressivity will apply to that PTV.
Thus, the point where the cost of losing the QCE
credit year begins to outweigh the benefit from
repealing progressivity depends both on the price of
oil and, for each individual producer, on that
producer's own unique portion of the lease
expenditures for the North Slope.
1:50:23 PM
CO-CHAIR SADDLER, noting that this was a key point, requested it
be repeated.
MR. WILLIAMS repeated that "the point where the cost of losing
the QCE credit year begins to outweigh the benefit from
repealing progressivity depends both on the price of oil and,
for each individual producer, on that producer's own unique
portion of the lease expenditures for the North Slope." He then
continued with his presentation:
For BP's own business and expenditures, this crossover
comes at a higher price level - in the mid to upper
90s - than that which Econ One and others are
presenting for North Slope producers as a whole. So
the improvement to our investment economics from the
repeal of progressivity stands to be substantially
undone by the sunset of the QCE tax credit. Since I am
a tax man who is here to testify about this tax, I
would ask, please, for your patience for just a few
minutes if you have questions regarding this point, so
I can quickly finish up and Mr. Bilbao can testify.
The third major feature in HB 72 is its proposed
"gross revenue exclusion" or "GRE" which is something
new. It would exclude from the taxable PTV (production
tax value) a percentage of the gross value at the
point of production for additional or new volumes of
oil or gas being produced. This concept could have
significant potential, and indeed it may prove very
valuable for explorers and others who can bring new
fields and reservoirs into production.
Unfortunately, the proposed GRE aims away from the
significant opportunities for new production that BP
has identified for its business. HB 72 would allow a
GRE only for production "from a lease or property that
does not contain land that was within a unit on
January 1, 2003[,]" or if it does have land that was
in a unit before 2003, "the oil or gas is produced
from a participating area established after ... 2011
[that] does not contain a reservoir that had
previously been in a participating area established
before ... 2012." BP's business centers primarily
around units that were established before 2003 - the
Prudhoe Bay Unit, Kuparuk River Unit, Duck Island Unit
and Milne Point Unit. These units are fully explored,
and the likelihood is small that any significant new
participating area will be established in them that
"does not contain a reservoir that had previously been
in a participating area established before ... 2012."
So these units are unlikely to receive any GRE, as the
Bill reads now.
1:52:56 PM
CO-CHAIR FEIGE asked if this indicated that there were
reservoirs within the unit and that a previous participating
area was contracted.
MR. BILBAO asked to clarify that the question was whether BP
expected to see any producing areas extended in the future.
CO-CHAIR FEIGE referred to the statement, "does not contain a
reservoir that had previously been in a participating area
established before ... 2012." He asked if there were reservoirs
that had previously been in a participating area, but were no
longer.
MR. BILBAO, offering a short answer, stated that BP did not
envision the necessity for expansion of any producing areas for
the ongoing development of the fields.
MR. WILLIAMS mused that the confusion could arise from his quote
of the statute, rather than a paraphrase for clarity.
CO-CHAIR FEIGE expressed his understanding.
1:54:38 PM
REPRESENTATIVE TUCK, noting that some previously explored units
would not qualify for the GRE, asked if BP planned for any new
exploration.
MR. BILBAO replied that the BP focus in Alaska was in the
existing units, as these had more resource opportunity than
anywhere in the world, other than the Lower 48. He stated that
the concentration would be on development of those resources,
not in exploration for new units, either on or off shore.
1:55:28 PM
REPRESENTATIVE TUCK asked to clarify that the GRE would not
benefit BP, specifically for the already explored units.
MR. BILBAO expressed agreement that there was not an expectation
for expansion, or creation of new producing areas, that would
fall under this characterization.
1:56:02 PM
MR. WILLIAMS, continuing with this presentation, stated:
The present focus of the proposed GRE is misdirected.
Econ One a week ago told you that an estimated 29.1
billion barrels of oil and barrel-equivalents of gas
on the North Slope and offshore in the OCS is
"Economically Recoverable @ $90/bbl". But, as AOGA
pointed out it its testimony on Monday, only 10
percent of that resource is in an area that Alaska has
any direct economic stake in and control over - the
central North Slope. Of the 3 billion barrels there
that Econ One identified, AOGA's testimony (in which
we and the other members of AOGA all concurred)
estimated that "2.5 billion barrels or more stands to
come from Prudhoe Bay, Kuparuk and other legacy fields
already in production" that have little or no chance
of getting any GRE under the Bill.
If you're going to hunt for eggs, you have to look
where the hens nest. The same is true for oil. If you
are going to provide an incentive to increase
production rates and ultimate recovery, offer it where
the oil is.
There are several problems with the present ACES law
that HB 72 does not address, and I will quickly brief
you about them.
The first is the disallowance under AS
43.55.165(e)(19) of "costs incurred for repair,
replacement, or deferred maintenance" of production
facilities "in response to a failure, problem, or
event that results in the unscheduled interruption …
or reduction in the rate of … production … or in
response to … an unpermitted release of a hazardous
substance or [natural] gas[.]" This was enacted in
2007 in response to the partial shutdown of Prudhoe
Bay in 2006 after two corrosion-caused leaks were
discovered. BP is not seeking change to the substance
of the disallowance itself, but we think the statutory
language should be improved to establish clarity about
its applicability. There are minor hiccups in
production operations almost every day in fields
around the world, and Alaska's fields are no
exception. The present statute sets no standard of
materiality for an "unscheduled interruption .. or
reduction" in production. If production at a facility
is "interrupted" for five minutes because of a
temporary hiccup in operations, does that cause a
disallowed expense? If production is "reduced" by five
barrels a day for a field producing over 400,000
barrels daily, does that cause a disallowed expense?
If production is interrupted for a material period of
time, but ultimately it turns out to cost only $10 to
respond to it, is it worthwhile to identify and
quantify this $10 so it can be disallowed? There is no
answer to these and similar questions in the statute,
and the Department of Revenue has not adopted
regulations that answer them. We are not asking you to
try to write the answers to these questions in the
statute, although you certainly could if you want do
to all that work. But we suggest, instead, that you
expressly give the Department of Revenue not only the
authority, but the duty, to adopt regulations that set
reasonable thresholds for materiality about how long
an "interruption" has to last, about how large a
"reduction" in production has to be, about how much an
unauthorized release has to be or in what
circumstances must it occur, and about how much the
cost "incurred … in response to" such situations has
to be, in order to trigger the disallowance.
As you know, I worked in the Department of Revenue
some 30-odd years ago, and if I had to administer this
statute in light of the circumstances and controversy
that led to its enactment, I would be reluctant to
adopt regulations on my own initiative to establish
such thresholds unless I had some kind of go-ahead or
permission from the Legislature. Perhaps the
Department is waiting for such a sign from you.
The second unaddressed problem comes from the changes
that ACES made to AS 43.55.150, the statute that
determines the gross value at the point of production
on the basis of destination prices or values minus the
costs of transporting the oil or gas to those
destinations from the point of production in the
field. As amended, the actual cost that a producer
pays to a regulated pipeline carrier to ship the
producer's oil could be set aside if the producer and
carrier are "affiliated." The Department has adopted
regulations calling for "cost-based" tariff
calculations in lieu of the actual regulated tariffs
that are paid. But under those regulations these
calculations of the "cost-based" tariffs are made by
the Department, not the taxpayer, and there is no
deadline in the regulations or in AS 43.55.150 for the
Department to make its calculations and share the
results with the taxpayer. The only deadline is the
six-year statute of limitations under AS 43.55.075(a).
We concur with AOGA's testimony about the interplay
between this six-year statute and interest at 11
percent APR, compounded quarterly, for any tax
underpayment that, in this regulated-pipeline
situation, might result from the Department's
calculation of a lower tariff than the one allowed by
the governmental regulatory agency having jurisdiction
over that tariff. Six years at 11 percent almost
doubles-up the amount of a tax increase from such a
"cost-based" tariff.
Further, the tax laws of the State are not an
appropriate place for Alaska to try to regulate
pipeline tariffs. That is a function of the Police
Power, and the Regulatory Commission of Alaska has
been established as the executive agency to exercise
that regulatory power. The Federal Energy Regulatory
Commission has similarly been created by Congress to
regulate pipeline tariffs for interstate shipments
under the Congressional power created by the United
States Constitution power to regulate interstate
commerce. State tax authorities have no business
trying to supplant either of these agencies.
Any further matters regarding HB 72 that we would
bring to your attention have already been addressed by
AOGA in its testimony to you on Monday.
2:03:46 PM
MR. BILBAO added that the testimony had gone into detail for the
committee to better understand the impacts when modeling for
business investments.
2:04:12 PM
REPRESENTATIVE SEATON, directing attention to slide 4, asked
about the criteria for analysis which included a $30,000
reduction in field expense, and its impact through
progressivity. He declared that the purpose of progressivity
was to incentivize investment, yet the analysis portrayed a
reduction in investment. He asked if lowering the investment in
Alaska would cause a higher tax.
MR. WILLIAMS expressed his agreement, stating that an incentive
was not useful if its worth was unknown. He cited this as the
point, that it was not possible to calculate the tax benefit for
this investment.
2:05:40 PM
REPRESENTATIVE SEATON pointed out that the slide indicated a
lowering of a $30,000 investment in field cost operations,
instead of increasing the investment.
MR. WILLIAMS replied that the reduction had not been classified
as a capital expense, and could be for efficiency, although the
same problem still existed. He stated that efficiency should be
encouraged, yet, in this instance, there was a penalty.
2:06:29 PM
CO-CHAIR FEIGE suggested that efficiencies in the field could be
attained through investments, yet he agreed that if it was
difficult to quantify a savings, it would be difficult to
justify an investment.
MR. WILLIAMS expressed agreement that the calculated tax effects
had to be quantified for certainty.
MR. BILBAO added that efficiency and new technology both allowed
for more economic production, and that this was beneficial to
both the producer and the state.
2:08:38 PM
REPRESENTATIVE HAWKER shared his concern that the axiom, "the
power to tax necessarily involves the power to destroy," was
being proven true by the State of Alaska.
2:09:15 PM
REPRESENTATIVE TUCK reflected on the increase of the original
Prudhoe Bay production estimate from 9 billion barrels of oil to
12 billion barrels, and asked how efficiency had produced more
oil.
MR. BILBAO replied that the efficiency was on a broad spectrum,
and offered an example of rigs drilling more wells and doing it
more efficiently, so that cost savings would be leveraged. He
pointed out that the management of inflation to maintain the
same production as the previous year was also a means for
efficiency.
2:10:37 PM
REPRESENTATIVE TUCK asked for a forecast for the oil production
in Prudhoe Bay.
MR. BILBAO replied that, first and foremost, "the resource
opportunity in Alaska is tremendous, unparalleled" and that BP
did not see many other greater opportunities for oil and gas.
He declared that the challenge was above the ground surface, and
he offered that the current forecast for recoverable oil in
Prudhoe Bay was now 14 billion barrels. He pointed out that the
fiscal policy would ultimately affect the amount of oil
recovered in all the fields.
2:12:02 PM
REPRESENTATIVE JOHNSON offered his belief that Alaska was
penalizing companies for "doing good business," declaring that
efficiency was not a bad thing.
2:13:13 PM
REPRESENTATIVE SEATON pointed to the difficulties for the design
of taxes which work to align interests on the North Slope. He
referred to testimony by an engineering company that a project
to enhance oil projects had been cancelled because one investor
had declined to invest. He asked if it was possible to
incentivize investment when there was misalignment between the
three producers in Prudhoe Bay.
MR. BILBAO declared that his experience in Alaska and elsewhere
dictated that when a project made economic sense, everyone would
quickly align. He reported that tax policy had a very clear
impact on this, and suggested that there had not been enduring
misalignment on specific field projects if the policy encouraged
good projects. He stated that both the oil producers and the
state would benefit.
2:15:04 PM
REPRESENTATIVE SEATON clarified that he was not talking about
alignment between the state and the producers in Prudhoe Bay,
but rather between the operators themselves. He asked if tax
policy would help drive the investments.
MR. BILBAO emphasized that this legislature had the opportunity
to make Alaska competitive for investment, which would affect
the decisions of the working interest owners in any of the
fields. He affirmed that if a fiscal policy allowed a project
to be economic, then the working interest owners would agree to
move the projects forward. He observed that a policy which
tried to pick winners had the unintended consequence of creating
misalignment.
2:18:06 PM
SCOTT JEPSEN, Vice President External Affairs, ConocoPhillips
Alaska, Inc., offered to discuss the Alaska tax framework for
oil and gas production on the North Slope. He reviewed slide 2,
"Topics," which listed the topics that he would discuss.
MR. JEPSEN stated that he would start with the first topic, and
he indicated slide 3, "Alaska Decline Continues While Lower 48
Production Continues to Increase." He pointed to the top line,
which reflected oil production in the Lower 48 over the last 8
years, noting that the incredible resurgence driven by
production increases in Texas and North Dakota correlated to the
decline in Alaska. He observed that it was a natural question
to ask what was happening. He explained that the Lower 48 had
resources which included the shale and resurgence in the
conventional drilling. He pointed that many of these were now
viable as oil prices and technology had improved, both of which
had tremendous economic impact on production.
2:20:44 PM
MR. JEPSEN indicated that the other favorable point for
production and investment in the Lower 48 was the tax framework,
as there was a more equitable split of revenue between producer,
investor, royalty owners, and government. As the prices went
up, everyone shared. He pointed out that Alaska was different.
There were resources, specifically in the legacy fields.
Technology would always play a role in Alaska, and, although
costs were a challenge, the technology helped make oil
production economic. He noted the challenge for cost, as oil
was far from market, in a remote, hostile environment. He
observed that the current tax framework in Alaska was not an
incentive for investment, and, although some aspects of ACES had
merit, these did not offset the high progressivity and tax rate.
2:22:11 PM
MR. JEPSEN introduced slide 4, "Alaska - A Challenging
Investment Climate Investment Criteria: How Alaska Ranks." He
stated that this addressed some of the investment questions for
a company. He pointed to the arrows, either red or green, which
rated each of the categories as favorable or not favorable. The
first category, exploration potential, was not favorable as the
average field size discovery was now only about 100 million
barrels, which did not compare with the multi-billion barrel
prospects found elsewhere. He addressed the next category,
costs, and reported that this was challenging in Alaska, as the
transportation costs were high, and the North Slope was a
hostile environment for business in the winter and
environmentally sensitive in the summer. He compared this to
the simplicity of operating in Texas. He pointed to the next
category, cycle time, noting that it took a much longer time to
bring a well into production in Alaska, and that this was also
an unfavorable rating. He offered an example of the more than
10 years to bring on the new drill site at the Alpine Field,
stating that it took "pretty deep pockets, a lot of staying
power, in order to do business in an environment where you have
those kinds of cycle times."
2:25:25 PM
MR. JEPSEN moved to the next category on slide 4, Taxes,
offering his belief that Alaska's tax environment did not
encourage investment. He reported that ACES took away the
upside, even with the tax credits to offset some of the costs.
He declared that long term cash flow was a criterion for
investment, and that ACES did not incentivize investment.
MR. JEPSEN summarized the last category, Legacy Field
Opportunities, which he declared to be a very big positive for
Alaska, as there was tremendous resource potential. He
announced that investments for near term production to stop the
decline would focus on these fields. He affirmed that the
legislature could "do something about taxes if it so chooses,"
which would help to equalize the investment playing field by
making taxes comparable to other places that were attracting
large amounts of capital. He encouraged the legislature to
consider providing investment incentives, and to spread them
across the board, which would include investment in the legacy
fields.
2:27:00 PM
MR. JEPSEN indicated slide 5, "Alaska Legacy Fields Still
Provide Significant Opportunity." He reported that this graph
was taken from the 2009 DOR production forecast data for 2010 -
2050. He pointed out that the majority of the resource lies in
the legacy fields: Kuparuk, Prudhoe, and Alpine areas, with
more than 4 billion barrels of expected future production, which
offered the "greatest bang for the buck for investment."
MR. JEPSEN considered slide 6, "Alaska's Days of 'Easy Oil' Are
Gone: High Costs and High Government Take Present Challenges,"
which had been prepared by PFC Energy, and compared costs
between Alaska and the Lower 48. He pointed out, as it cost
half as much to drill in the Lower 48 than Alaska, with lower
taxes, that it was a simple equation for where to invest.
2:28:55 PM
MR. JEPSEN explained slide 7, "Easy Oil In the Legacy Fields Is
Gone," and stated that the first wells were relatively straight
forward. He affirmed that this had changed, and although there
was still a lot of oil, it was trapped in isolated fault blocks
and other places, which required complicated high cost wells.
He agreed that the complicated new wells in the legacy fields
were still cheaper than drilling new grass root wells. He
stated that the reserve targets were smaller, and they were
pursuing the satellite fields, which had added a lot of
production to the North Slope. He noted, however, that
development of the satellite fields often required new
infrastructure, new pipelines, and long cycle times, which was
all more expensive than drilling in existing facilities. He
reported that viscous oil was also being developed, with almost
15,000 barrels each day online in Kuparek. He said that this
will be a long term continuous evolvement of technology before
this viscous oil resource can be fully developed. He
acknowledged that wells were also producing water, as water was
often injected to push oil out of the reservoir, and this
increased the cost for oil production. He summarized that the
days of low cost, straight forward well bores for 100 percent
oil were gone, and the focus was now on oil production that
required good prices, good technology, and a good tax
environment.
2:32:03 PM
MR. JEPSEN reported that the initial Alpine development cost
about $1.4 billion in 2000, with 92 wells, 2 satellite drill
sites, connecting roads, pads, an airstrip, pipelines, and
facilities and had initial production of about 80,000 barrels
each day. He compared this to a similar CD-5 type development
which would have 16-22 wells, with small test facilities, and
pipelines, and would produce 15 - 18,000 barrels at peak rate,
and noted the increase in the cost of doing business on the
North Slope.
MR. JEPSEN concluded that progressivity was "really a big
disincentive for investment here in the state." He reported
that proposed HB 72 did address this, but the elimination of tax
credits would still disadvantage Alaska, as the cost of doing
business was so much higher. He suggested that incentives for
investment, specifically in the legacy fields, would be a
necessary key component in a tax policy.
2:34:15 PM
REPRESENTATIVE P. WILSON asked about the cost for the CD-5 type
development.
MR. JEPSEN replied that the new development would cost about $1
billion.
2:34:43 PM
BOB HEINRICH, Vice President Finance, ConocoPhillips Alaska,
Inc., began with a review of the positive elements of Alaska's
Clear and Equitable Share (ACES), slide 8, "ACES Observations."
He stated that the tax credits were an important aspect of the
structure of ACES, as they offset a small part of the high tax
rates which resulted from the calculations. He declared that a
large amount of the credits had gone toward exploration,
although the producers also used them to offset the high cost
environment. He pointed out that the tax credits also applied
to both the new fields and the legacy fields. He explained that
these tax credits were not enough to offset the high average and
high marginal tax rates which resulted from progressivity. He
noted that the gross minimum tax also demanded a tax, often when
the revenue did not cover the cost. He directed attention to
the graph of marginal shares on slide 8, which depicted the
industry, federal, and state shares per barrel of oil from a
range of prices under ACES. He reported that, under the current
price environment of $110 per barrel, the marginal tax rate was
about 80 percent. He referred to the lower chart on slide 8,
representing the ConocoPhillips earnings per barrel, which
ranged from $22 - $25 per barrel, even as the price had ranged
from $60 - $110 per barrel. He stated that the majority of the
upside had been paid to the State of Alaska.
2:37:17 PM
MR. HEINRICH presented slide 9, "ConocoPhillips Capital
Allocation," which graphed investments in Alaska and the Lower
48. He declared that, although there were "great new
opportunities" in the Lower 48, the reason for significant
investment there was for the cash return, more than a 50 percent
greater return than in Alaska. He stated that the trend of
investment for the greatest profit opportunity would continue.
He reported that ConocoPhillips had invested more than $20
billion since 2000 in Alaska activities, however the current
investments were "into liquids rich oil plays, which generates
substantially better margins." Alaska was still an important
part of the portfolio, but ACES was preventing a greater capital
investment.
2:38:35 PM
MR. HEINRICH offered slide 10, "Producer Share under HB 72,"
which analyzed the difference between ACES and HB 72 on a
producer share basis, defined as "the available cash after cost
and taxes that are retained by the producers." He declared this
to be the inverse of the state or government share. He
explained that the producer share was affected by assumptions on
capital spending and operating costs, which could vary from
field to field and from producer to producer. He reported that
this graph used 2012 revenue sources data, which represented all
the producers with a tax liability on the North Slope. He
clarified that the graph was projected for the single year FY
2014, and was not a field life or a five year calculation. He
opined that the first year of a forecast was the most reliable.
He pointed out that the crossover point for the two tax systems,
HB 72 and ACES, was about $93 per barrel and that above that
price, HB 72 produced a higher percentage share from the
producer perspective. Below this price line essentially
resulted in a tax increase for the producers. This had forced
the producers to analyze the effects of the proposed bill, which
would trade off the benefits of a better tax environment at
higher prices with a worse tax environment at prices slightly
lower than the current price per barrel. He declared that it
was important for project analysis to review a probable range of
prices. He noted that the shape of the curve was similar to
that in many of the Lower 48 states, but that Alaska's high
operating cost environment did not tilt the equation toward
Alaska investments. He suggested that a flattening of the curve
would lower the tax increase at lower prices, and that expansion
of the incentives for legacy fields would also "improve the
likelihood of the state achieving its goals."
2:41:46 PM
MR. HEINRICH summarized his observations of proposed HB 72,
slide 11, "Recap of ConocoPhillips Perspective." He reported
that, under ACES, progressivity took away the price upside, and
discouraged investment; although the tax credit structure did
reduce the overall effective tax rate, it was not enough to
offset the negative effects of progressivity at higher prices.
He declared that proposed HB 72 was a positive step toward an
improved investment climate, as the elimination of progressivity
resolved the problem of the high marginal tax at increased
prices and made Alaska more competitive at those higher prices,
which he defined as more than $100 barrel. He noted that the
proposed bill made Alaska less competitive than ACES at lower
prices, and it represented a tax increase to the producers. He
declared that the gross revenue exclusion was not broad enough
to incentivize new production, as it did not include the legacy
fields, where the vast majority of future production was
expected.
2:43:02 PM
REPRESENTATIVE P. WILSON asked how many years after investment
would it take for an increase in production.
MR. JEPSEN recognized the necessity for the producers to respond
to a positive tax structure. He shared that it was possible to
more quickly bring on a new drill rig than to build a new drill
site, although there were plans and ideas for projects after a
change in the tax environment. He offered his belief that the
closest differential time frame would be 1 - 2 years, with other
projects coming on line at later dates. He pointed out that
there was already a high demand for drilling equipment, given
the high price of oil, but that an incentive for investment
would be actively pursued.
2:45:00 PM
CO-CHAIR SADDLER directed attention to the investment criteria
on slide 4, and asked which was the most important consideration
for investment.
MR. JEPSEN replied that these criteria were in order of
occurrence, as each determined the next stage.
CO-CHAIR SADDLER asked which was the most important to consider.
MR. JEPSEN, in response, stated that there was not an absolute
answer as it was a function of the fit for all the variables.
2:46:57 PM
REPRESENTATIVE SEATON identified slide 10, and asked why the
projected oil price of $93 per barrel differed from the Palantir
projection of $120 per barrel as the crossover point. He asked
if this price was production tax value.
MR. HEINRICH responded that the price depended on the
assumptions made for cost of capital. He declared that these
prices represented the undiscounted cash flow for FY 2014. He
stated that he was not aware of the presentation, noting that it
was important to make sure both were for the same time
durations.
2:48:57 PM
REPRESENTATIVE SEATON asked to clarify that it was for the full
life cycle of a capital intensive project by a producer.
MR. HEINRICH replied that it was based on a portfolio
perspective from DOR sources.
2:51:02 PM
DAN SECKERS, Tax Counsel, ExxonMobil Corporation, directed
attention to his submitted written testimony, [Included in
members' packets] and he invited any questions to that
testimony. He offered to summarize the ExxonMobil perspective
for proposed HB 72, and declared support for the earlier
testimonies from BP and ConocoPhillips. He endorsed the efforts
of the governor and the legislature for examining the Alaska
investment climate, specifically ACES. He emphasized that
Alaska was no longer competitive hence it was not attracting the
necessary investments. For ExxonMobil, it was necessary for any
effective tax policy to address two main components of ACES,
progressivity and the overall high government take. He noted
that the producers agreed that these were a major disincentive
to move any investment opportunities forward. He affirmed that
proposed HB 72 offered significant progress toward making the
Alaska investment climate more competitive. He stated that
progressivity created complexities, and it took away a lot of
the upside potential that other tax jurisdictions allowed the
producers to retain. He assessed that this was important in
Alaska, as the costs were high, and the investments long term,
high risk, and capital intensive; therefore, mitigation for this
was the upside potential. He stressed that the elimination of
progressivity was a significant improvement, and would allow
Alaska to be more competitive and increase investment. He
reported that the gross revenue exclusions did not apply to the
legacy fields, and that it was important to incentivize both new
production and existing fields. He pointed out that a small
increase in the recoverable reserves at Prudhoe Bay would dwarf
any new field on the North Slope. He confirmed that, although
proposed HB 72 offered significant progress, there were still
some concerns. He noted that the base rate was still too high.
Benchmarking government take against other regimes was
important, but it did not tell the entire picture, as Alaska had
some of the highest costs. He offered his belief that Alaska
should strive to make companies want to invest in Alaska, as the
other factors were all deterrents.
2:57:09 PM
MR. SECKERS addressed the issue for tax credits, recognizing the
necessity to balance long term state needs with wide band price
scenarios. He stated that tax credits offered investors that
opportunity, as it downsized risks, and mitigated the costs for
capital investments. He suggested consideration for the
maintenance of the tax credits. He stated that the gross
revenue exclusions should be expanded to cover all the fields,
not just new fields, and that the base tax rate should be
reviewed and compared with other states. He conveyed that
Alaska was important to the ExxonMobil long term investment
portfolio, and they looked forward to staying in Alaska. He
cited that it was critical that Alaska continue to exam its oil
tax policies. He asked if the Alaska legislators were
comfortable with "the path Alaska's currently on." He
summarized that any encouragement for investment in Alaska
should be examined to improve the investment climate, and he
declared that proposed HB 72 was "a good step in that
direction."
2:59:16 PM
REPRESENTATIVE SEATON asked if a change for the base tax rate to
an equivalent of 17 percent would be less complex than broad
application for the gross revenue exclusions.
MR. SECKERS replied that this was a part of the necessary
analysis for the legislature. He offered his belief that
taxation was just math, and could be made to work in a number of
different ways. He shared that the question should be for
competitiveness, with a goal to make Alaska attractive for
investors.
3:00:49 PM
REPRESENTATIVE SEATON, referring to the call for the elimination
of progressivity, asked whether, if the upside potential was
eliminated for the state, the floor amount should be changed so
that the oil industry had some downside risk as a balance.
MR. SECKERS agreed it was a difficult challenge to balance the
tax structure across all prices. He opined that the floor, as
it was based on gross, could be exceptionally harsh, and could
lead to a tax situation even though there was not any profit.
He stated that progressivity was the most punitive aspect of
ACES, and to address that issue was a step in the right
direction.
3:02:24 PM
CO-CHAIR SADDLER asked to what degree ExxonMobil Corporation
would require durability for tax policy.
MR. SECKERS replied that stability was very important to Exxon
Mobil, although it was only as good as the cost it came under.
He said that investment decisions were impacted by continual
regulatory changes. He commented that any changes had to make
Alaska more competitive.
3:03:50 PM
REPRESENTATIVE TUCK asked how long ago Texas and North Dakota
had changed their tax policies in order to have the current
level of production.
MR. SECKERS stated that he did not know the historical tax
treatments for either of those states, or how often either had
changed its system. He opined that neither had made many recent
changes, but their systems were "a lot more favorable." He
added that the dynamics of new technology and the increase in
oil price had made both places more attractive.
3:05:31 PM
REPRESENTATIVE TUCK asked how much more quickly was the
turnaround time for unconventional oil development to production
in Texas and North Dakota.
MR. SECKERS offered his belief that the turnaround time would be
quicker in the Lower 48.
3:06:31 PM
REPRESENTATIVE SEATON detailed that some consultants had stated
that the return on capital employed was the most important
factor, and asked what the most important factor was for
ExxonMobil.
MR. SECKERS explained that the decision making process, for
ExxonMobil, was confidential, although they reviewed a wide
spectrum. He expressed agreement with ConocoPhillips that there
was no one lynchpin factor for decision making.
[HB 72 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES HB 72 ExxonMobil 2.20.13.pdf |
HRES 2/20/2013 1:00:00 PM |
HB 72 |
| HRES HB72 BP 2.20.13.pdf |
HRES 2/20/2013 1:00:00 PM |
HB 72 |
| HRES HB 72 BP Written Testimony 2.20.13.pdf |
HRES 2/20/2013 1:00:00 PM |
HB 72 |
| HRES HB 72 ConocoPhps 2.13.20.pdf |
HRES 2/20/2013 1:00:00 PM |
HB 72 |