Legislature(2013 - 2014)BARNES 124
03/25/2013 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB21 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 21 | TELECONFERENCED | |
| + | TELECONFERENCED |
SB 21-OIL AND GAS PRODUCTION TAX
1:05:42 PM
CO-CHAIR FEIGE announced that the only order of business is CS
FOR SENATE BILL NO. 21(FIN) am(efd fld), "An Act relating to the
interest rate applicable to certain amounts due for fees, taxes,
and payments made and property delivered to the Department of
Revenue; providing a tax credit against the corporation income
tax for qualified oil and gas service industry expenditures;
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; establishing the Oil and
Gas Competitiveness Review Board; and making conforming
amendments."
1:06:03 PM
BARRY PULLIAM, Economist & Managing Director, Econ One Research,
Inc., Los Angeles, California, as consultant to the
administration, provided a PowerPoint presentation comparing the
differences between CSSB 21(FIN) am(efd fld), SB 21/HB 72, and
Alaska's Clear and Equitable Share (ACES). He first compared
the differences in the key features of the aforementioned [slide
2], saying the base tax rate in SB 21/HB 72 of 25 percent was
changed to 35 percent in CSSB 21 (FIN) am(efd fld). No credits
were included in SB 21/HB 72, but a credit of $5 per barrel was
added in CSSB 21(FIN) am(efd fld). Under SB 21/HB 72, a
producer without tax liability could carry forward its net
operating losses (NOLs) at a 15 percent increase and then take
the NOLs once the producer did have tax liability. However,
CSSB 21(FIN) am(efd fld) allows for monetization of NOLs so
producers that do not have tax liability as they are developing
new projects will receive a boost to their economics.
1:08:42 PM
MR. PULLIAM, continuing his comparison of the key features, said
SB 21/HB 72 provided a gross revenue exclusion (GRE) at the rate
of 20 percent applicable to units formed after 2003 or new
participating areas (PAs) [formed after 2012]. Under CSSB
21(FIN) am(efd fld), this provision remains the same but the
applicability is expanded to also include certified new oil from
existing fields. Under SB 21/HB 72, the small producer credit
of $12 million per year was extended to the year 2022, but under
CSSB 21(FIN) am(efd fld) this credit expires in 2016.
1:10:28 PM
REPRESENTATIVE SEATON, referring to certified new oil from
existing fields under CSSB 21(FIN) am(efd fld), inquired whether
Mr. Pulliam is just presenting the provisions of CSSB 21(FIN)
am(efd fld) as currently written or will be offering
recommendations on whether these changes make sense.
MR. PULLIAM replied his intention with slide 2 is just to
highlight the differences between the original bill, SB 21/HB
72, and CSSB 21(FIN) am(efd fld), the bill that came out of the
Senate. As he goes along he will be talking about the impacts
on investment generally.
REPRESENTATIVE SEATON reserved his question on the expansion of
the GRE until such time as Mr. Pulliam discusses it.
1:11:26 PM
MR. PULLIAM returned to his presentation and compared the
government take and effective tax rates of ACES, SB 21/HB 72,
and CSSB 21(FIN) am(efd fld) for all existing producers for
fiscal years 2015-2019 [slide 3]. He pointed out that at a
[($2012) West Coast Alaska North Slope (ANS)] price of $80 per
barrel the government take under all three systems is the same
[about 64 percent]. As prices rise, the government take under
CSSB 21(FIN) am(efd fld) approaches 65 percent [versus about 62
percent under SB 21/HB 72 and 75 percent under ACES].
1:12:34 PM
REPRESENTATIVE HAWKER, noting Mr. Pulliam is engaged in this
effort by the administration, inquired whether Mr. Pulliam has
reconciled his modeling with the existing producers so there are
no "dueling modeling" questions.
MR. PULLIAM responded he has had considerable back and forth
with the producers and believes he is on the same page as far as
the models go. One difference, however, is that producers may
present numbers during this time period in nominal dollars,
while the numbers he is presenting here - as he has done in all
of his presentations - are in 2012 real dollars.
1:13:34 PM
MR. PULLIAM, in response to Representative P. Wilson, confirmed
that the black line in the graphs on slide 3 labeled "CS SB21
(FIN)" is the bill before the committee [CSSB 21(FIN) am(efd
fld)]. When referring to "CS SB 21 (FIN)" or to "the Senate
bill," he is meaning the bill that came out of the Senate.
1:14:02 PM
MR. PULLIAM, in response to Representative Tuck, confirmed that
royalty received by the state is included in the comparison for
government take on slide 3. He said government take encompasses
all forms of government take, including taxes and royalty. Some
of the royalty is at 12.5 percent and some is higher.
1:14:30 PM
MR. PULLIAM, continuing his discussion of the comparisons shown
on slide 3, said the bottom graph shows the effective tax rate
for severance that taxpayers would pay at different price
levels. The effective tax rate equals the nominal rate minus
the credits that are received. At a price just above $80 per
barrel, the effective tax rate for all three systems is the same
at about 22.5 percent. As the price increases the effective tax
rate under CSSB 21(FIN) am(efd fld) rises to about 30 percent;
due to the manner in which it is calculated - starting with a 35
percent base rate and then subtracting the fixed $5 per barrel
allowance - the tax rate at higher and higher prices would
approach 35 percent asymptotically but would never actually
touch 35 percent. That is because as the $5 credit is deducted
from the taxes, the tax rate on a percentage basis is lower and
lower as prices go up.
1:16:07 PM
MR. PULLIAM, in response to Representative Tuck, stated that
royalty would not be included in the effective tax rate depicted
on slide 3.
1:16:26 PM
REPRESENTATIVE SEATON asked whether the effective tax rate
depicted on slide 3 is a combination of production tax and
corporate income tax.
MR. PULLIAM replied the effective tax rate includes just the
production tax.
1:16:42 PM
MR. PULLIAM moved to slide 4 and compared the effective tax
rates on gross value for legacy production under ACES, SB 21/HB
72, and CSSB 21(FIN) am(efd fld) with that of other large oil-
producing states with production taxes at a wellhead value of
$100 ($2012). Most other states in the U.S., he explained, have
a gross tax while Alaska's current tax is on the net. Thus, for
comparison purposes on this graph, he converted Alaska's tax to
a percentage of the gross value and, because Alaska's tax varies
with price, he chose for this comparison the 2012 wellhead value
of $100 per barrel, which is about today's value. For
comparison on the chart he chose states with production of
100,000 barrels or more per day. On a gross basis, ACES
provides an effective tax rate of about 30 percent, SB 21/HB 72
provides about 17 percent, and CSSB 21(FIN) am(efd fld) provides
20 percent [compared to effective tax rates of about 12.5
percent for LA, about 11 percent for ND, about 8 percent for OK,
about 7 percent for NM, about 6 percent for WY, 5 percent for
CO, and about 4.5 percent for TX]. Thus, he pointed out, while
CSSB 21(FIN) am(efd fld) would lower the rate seen under ACES,
the proposed rate would still be higher than those of the other
major producing states in the U.S.
1:18:38 PM
REPRESENTATIVE SEATON, referring to the wellhead value of $100,
calculated that "to get to ANS" would be approximately $10 of
transportation. With Alaska's production taxes based on gross
value at point of production, he asked what Mr. Pulliam
subtracted from this as the actual taxable value.
MR. PULLIAM responded he is starting here with $100 at the
wellhead, so that would be the gross value of the production.
1:19:17 PM
REPRESENTATIVE SEATON noted that production tax value subtracts
out the cost, which is basically $26.
MR. PULLIAM answered correct, under any of the Alaska scenarios
the cost must be subtracted out and then the tax is computed.
To calculate these percentages he divided the tax by the gross
value of the oil as opposed to the net value of the oil.
1:19:51 PM
REPRESENTATIVE SEATON asked whether that is by the gross value
at the point of production, the taxable value, or this wellhead
value, meaning subtracting just the marine transportation and
the cost of the Trans-Alaska Pipeline System (TAPS) to get the
effective tax rate.
MR. PULLIAM replied that, in his view, gross value at the point
of production is the same as wellhead value. There is taxable
value, which then would subtract capital and operating costs
from the gross value. But gross value and wellhead value are,
in his mind, one and the same.
1:20:42 PM
REPRESENTATIVE SEATON said his understanding is that the
production tax value is the gross value at point of production
and that is what Alaska taxes, which is minus transportation
minus costs.
CO-CHAIR FEIGE said his interpretation is that gross value at
the wellhead is the West Coast price minus the transportation.
Alaska taxes the net production value, which is the gross after
subtracting the expenses, royalties, and capital and operating
expenses. He understood Mr. Pulliam to be saying that after
taxing it the way Alaska normally would, then based on the gross
this is how Alaska compares.
MR. PULLIAM confirmed Co-Chair Feige's interpretation.
1:21:31 PM
REPRESENTATIVE SEATON understood, then, that the effective tax
rate is based on looking at the ANS West Coast minus $10 and
what percentage of that is paid in tax.
MR. PULLIAM responded correct. So, at a wellhead value - gross
value - of $100, and a 20 percent effective tax rate under CSSB
21(FIN) am(efd fld), the State of Alaska would receive about $20
in taxes. Under ACES at a wellhead value of $100, the state
would receive about $30 in taxes, even though the taxable value
is not $100, but something lower subtracting capital and
operating expenses. To be able to compare Alaska's tax rate
with the other tax rates in the U.S., one or the other must be
converted, and it was much easier to convert Alaska's to a gross
equivalent and then compare.
1:22:32 PM
CO-CHAIR FEIGE surmised this effective tax rate would not
include the application of any gross revenue exclusion (GRE).
MR. PULLIAM answered some GRE would be included because this is
based on production that is forecast over the next five years.
Thus, there would be a little bit, but not a significant amount.
[See timestamp 1:25:15 p.m. where Mr. Pulliam corrects this
answer, saying the graph on slide 4 is for legacy production
which has no GRE and therefore no GRE is included in the
effective tax rate depicted in the graph.]
1:23:04 PM
CO-CHAIR SADDLER inquired whether slide 4 is a snapshot in time
now or looking forward.
MR. PULLIAM replied it is looking forward.
CO-CHAIR SADDLER asked whether the difference between Alaska and
other states would increase or decrease if the wellhead value
was at $80 per barrel and if it was at $120.
MR. PULLIAM responded as the price is lowered, in Alaska the tax
as a percentage of the gross value will drop; and as the price
is raised, the tax as a percentage of the gross value will
increase.
1:23:42 PM
REPRESENTATIVE TUCK understood [the effective tax rate] does not
include royalties. He understood royalties in North Dakota and
Texas are around 25 percent. He asked whether his understanding
is correct and if it would affect the graph on slide 4.
MR. PULLIAM answered the graph is simply severance taxes. In
other states the royalties with state and private landowners
vary between a low of one-eighth and up to 25 percent for more
recent leases in some of the more productive Lower 48 areas.
REPRESENTATIVE TUCK asked whether royalties should be included
when comparing total government take.
MR. PULLIAM replied those pieces are included when looking at
government take. He said he will provide slides later in the
presentation that look at total government take.
REPRESENTATIVE TUCK surmised Alaska would look better in those
slides than it does in slide 4.
MR. PULLIAM agreed Alaska is a little bit closer when looking at
total government take.
1:25:03 PM
REPRESENTATIVE SEATON inquired whether the graph on slide 4
depicts a five-year look forward.
1:25:15 PM
MR. PULLIAM first corrected his answer to [Co-Chair Feige's]
question of 1:22:32 p.m., saying the graph on slide 4 is for
legacy production which has no GRE and therefore no GRE is
included in the effective tax rate depicted in the graph.
MR. PULLIAM then answered Representative Seaton's question,
saying it is a projection over a 25-year period. However, he
added, he did look at it over a 5-year period and it does not
look any different over a period of 5 years than it does over 25
since the analysis uses the real 2012 price.
1:25:54 PM
REPRESENTATIVE SEATON surmised, then, that this calculation is
counting on oil being $185 per barrel by year 25, and about $163
by year 20, and these are all rolled into the calculation.
MR. PULLIAM replied in nominal terms he does not know what the
number would be in year 25, but said these are all done in terms
of 2012 real dollars, so an inflation of 2.5 percent per year is
included in the calculation.
1:26:38 PM
REPRESENTATIVE SEATON understood, then, that everything is
inflated at 2.5 percent, including the costs, and therefore the
costs in the graph are not inflated at the 6.5 to 8 percent
history of the fields.
MR. PULLIAM responded that is not correct, the costs in his
calculation are inflated at higher than 2.5 percent.
REPRESENTATIVE SEATON requested Mr. Pulliam to provide the
committee with those figures.
1:27:12 PM
MR. PULLIAM resumed his presentation, providing a sample of how
the tax would be calculated under CSSB 21(FIN) am(efd fld) with
no production qualifying for the GRE at the per barrel prices of
$80 West Coast ANS, $100, and $120 [slide 5]. He said his
assumptions included 100,000 barrels in gross production at 12.5
percent in royalty barrels, resulting in 87,500 net taxable
barrels. Focusing on the price of $100 a barrel, he subtracted
$10 in transportation costs, arriving at a wellhead value of $90
per barrel. He then subtracted $30 in lease expenses, arriving
at a taxable value of $60 per barrel for a total production tax
value of $5,250,000. A 35 percent tax rate is next applied,
arriving at $1,837,500. The $5 per barrel production allowance,
totaling $437,500, is subtracted to arrive at a tax due of
$1,400,000. This tax as a percentage of the net value of
production is 26.7 percent, and as a percentage of the gross
value of production it is 17.8 percent. At a price of $80, the
tax percentages drop [to 22.5 percent for net value of
production and 12.9 percent for gross value of production]. At
$120, the tax percentages increase [to 28.8 percent for net
value of production and 20.9 percent for gross value of
production].
1:29:14 PM
MR. PULLIAM provided another sample tax calculation, this time
for production qualifying for the 20 percent GRE [slide 6].
Focusing on a West Coast ANS price of $100, he calculated that
20 percent of the $90 wellhead value is $18, which is subtracted
from the wellhead value, as is the $30 in lease expenses,
arriving at a taxable value of $42. Multiplying $42 times the
taxable volume equals $3,675,000 in production tax value. At a
35 percent tax rate, the tax is $1,286,250. The $5 per barrel
production allowance, totaling $437,500, is subtracted, arriving
at a total tax of $848,750. This tax as a percentage of the net
value of production is 23.1 percent, and as a percentage of the
gross value of production it is 10.8 percent. [At a price of
$80 per barrel the percentages are 15.8 percent and 5.9 percent,
respectively, and at $120 the percentages are 26.4 percent and
13.9 percent, respectively.]
1:31:30 PM
MR. PULLIAM next summarized how state support, or credits, for
capital spending work under ACES and under CSSB 21(FIN) am(efd
fld) at a West Coast ANS price of $100 ($2012) and a capital
spend of $1 billion [slide 7]. Under ACES, an incumbent would
get a 20 percent qualified capital expenditure (QCE) credit,
which would amount to $200 million. An incumbent would also
have a tax reduction because of the higher per barrel
expenditure and the effect of buying down the tax rate on
existing production. The total value of the credit and buydown
to an incumbent would be about $780 million. A new participant
under ACES would have the same 20 percent QCE credit of $200
million and would also be eligible to monetize its net operating
loss (NOL) at 25 percent, for a total credit of about $450
million. Thus, ACES provides a higher value to the incumbent
than to the new participant. Under CSSB 21(FIN) am(efd fld),
the values to both the incumbent and the new participant would
be equal at an upfront credit of effectively 35 percent for
$1 billion in capital spending. For the incumbent, the credit
will be in the form of a tax reduction because the incumbent
will be able to immediately expense its capital spending. A new
participant without a tax liability will be able to monetize its
capital spending in the form of a credit with the state.
1:34:54 PM
MR. PULLIAM reviewed the $5 per barrel production credit from
the perspective of its worth when thought about as replacement
of the current capital credit [slide 8]. He explained the chart
depicts the relationship between capital spending and the
percentage on a net present value (NPV) basis of that $5 credit.
Under CSSB 21(FIN) am(efd fld), each barrel of oil gets $5 of
credit as it comes in over the years. A field producing 50
million barrels over 25 years would get a total of $250 million
from this allowance. Since it would be coming over the life of
the production of the field, that $250 million is brought back
to the time that the capital is spent to develop the field; the
sum arrived at is the net present value of it, let's say $150
million. Looking at that sum, that net present value of the $5
credit, as a percentage of the producer's capital expenditure,
gives a sense of what this credit is providing, what kind of
offset it is providing if it is looked at relative to the
capital being spent - that is what is done in this chart. For
example, at a per barrel capital spend of $20 the NPV is about 8
percent. So, if spending $20 per barrel to develop a field, the
production credit would translate to about 8 percent of the
amount of that capital expenditure on a net present value basis.
1:37:33 PM
MR. PULLIAM, in response to Representative Seaton, said he is
using a discount rate of 12.5 percent in this example.
1:37:44 PM
REPRESENTATIVE SEATON asked whether an inflation of 2.5 percent
per year is used over time.
MR. PULLIAM answered he does inflate that by 2.5 percent for
each of the years. However, he pointed out, that spending is
going to all occur pretty much in the first five years. The $5
per barrel credit does not inflate; it remains just $5 in
nominal terms across the time of the production because the
credit is structured such that it has no inflation aspect to it.
In further response, he posed a scenario of spending $20 per
barrel to develop a field of 50 million barrels, for a total
upfront expenditure of $1 billion. Against that $1 billion, if
50 million barrels is produced, the producer will get cash of
$250 million over time. That $250 million divided by $1 billion
is 25 percent. This chart brings back that $5 a barrel that is
received over time and looks at it on a net present value basis
- how a producer might be looking at this as the kind of support
it is getting in a credit. From that standpoint, it is
appropriate to look at that $5 value, the present value of that,
at the time the capital is spent. What the value is of that $5
essentially at the time the capital is spent.
1:40:19 PM
REPRESENTATIVE SEATON understood, then, that this calculation is
based on the expenditure occurring at the start and nothing is
spent through time that calculates into this.
MR. PULLIAM replied this is assuming the capital is spent up
front during the first five years of developing the field.
CO-CHAIR FEIGE interjected that this is when all the wells are
drilled and the pipelines put in.
MR. PULLIAM confirmed it is when the facilities are put in.
1:41:06 PM
MR. PULLIAM resumed his presentation, turning to slide 9 to
discuss the effective tax rate for a new participant with and
without the GRE under CSSB 21(FIN) am(efd fld) on both a gross
and a net basis. He first posed a scenario of a new development
with no GRE at a $20-per-barrel cost of development. In this
scenario, the effective tax rate on the gross, or wellhead,
value would be a little over 0 percent at a West Coast ANS price
of $60 per barrel in 2012 dollars, rising to just below 20
percent at $110, and approaching 25 percent at $160. The
effective tax rate on the net, or taxable, value would be about
5 percent at a per barrel price of $60, rising to about 30
percent at $110, [on up to about 31 percent at $160].
1:43:02 PM
CO-CHAIR SADDLER requested a definition of "asymptotically."
MR. PULLIAM explained something approaching "asymptotically"
means it gets closer and closer but never exactly touches. For
example, the effective tax rate under CSSB 21(FIN) am(efd fld)
will approach 35 percent, but it will never touch it and that
relationship can be seen in the charts on slide 9.
1:44:33 PM
MR. PULLIAM continuing his discussion of the effective tax rate
depicted on slide 9, posed the same new development scenario
under CSSB 21(FIN) am(efd fld), but this time with the GRE. On
a gross basis, the effective tax rate would be above 0 percent
beginning at a per barrel price of $70, rising to about 15
percent at $130. On a net basis, the effective tax rate would
be above 0 percent at a price of about $70, reaching 20 percent
at $120 per barrel. Thus, the GRE has the effect of reducing
the effective tax rate on production. At very low prices with
the GRE, he noted, it can go into a negative tax rate situation
due to the 35 percent monetization of the net operating loss.
1:45:35 PM
REPRESENTATIVE TARR inquired how low the price would have to go
for that negative situation to happen.
MR. PULLIAM responded in this example it would be at about $70
per barrel West Coast. He pointed out this is currently
happening under ACES, just at a higher level of 45 percent as
opposed to a 35 percent level. Elaborating, he said it is
happening at least at a 45 percent level for a new producer and
at a higher level for an incumbent.
1:46:11 PM
CO-CHAIR SADDLER understood Mr. Pulliam to be saying that at
prices below $70 a barrel with the GRE, the state would be
losing money.
MR. PULLIAM answered for a new development it could be a
negative tax situation for the state if prices did not go up
above $70 a barrel. In other words, the state would expend more
in monetizing the net operating loss up front than it would get
back in taxes over the life of the field. Just the tax take
would be negative, he added; the state would be getting
royalties, so the total take to the state would not be negative.
1:47:09 PM
MR. PULLIAM resumed his discussion of the effective tax rate on
gross and net value, reviewing the rates under ACES [slide 10].
Under ACES, he said, the effective tax rates on the gross and
net values are generally higher for a new participant than for
an incumbent. This is because the incumbent has the ability to
buy down its rate on its other production by having the new
investment.
1:48:08 PM
REPRESENTATIVE SEATON requested Mr. Pulliam to elaborate further
on the effective tax rate.
MR. PULLIAM stated that with GRE under CSSB 21(FIN) am(efd fld),
the tax is negative at a price of about $70, whereas under ACES
it would be negative at $60.
1:48:58 PM
REPRESENTATIVE SEATON recalled that when ACES was being
constructed the thought was that some good years would give
quite a bit of revenue to balance that, allowing the state to
take that liability on the low end. [Under CSSB 21(FIN) am(efd
fld)], he observed, the low end is moved out so the state has a
liability but is not getting the relative counter-balance on the
high end to put something in the bank to be able to absorb those
losses. Therefore, he asked, how does CSSB 21(FIN) am(efd fld)
with the GRE make the state more secure when looking at $70 and
below and the state is subsidizing production taxes.
MR. PULLIAM agreed the state would be in a negative situation
with the GRE. The way it makes the state more secure, he said,
is that the state is more apt to get the development of those
additional barrels with the rates that have been proposed with
the GRE. If prices were below $70, the state would find it hard
to get much activity because that is a pretty challenging price
range for development on the North Slope.
1:50:47 PM
CO-CHAIR FEIGE pointed out that in the near term most of the
production would not have the GRE applied to it.
MR. PULLIAM concurred, noting that at lower price ranges the
effective tax rate on gross and net value under CSSB 21(FIN)
am(efd fld) with no GRE pretty much tracks the rate under ACES.
Above a price of $80 the two diverge.
REPRESENTATIVE SEATON remarked it is a question of whether the
state wants a design where it subsidizes production development
out of royalty; it is a question as to what kind of long-range
liability that produces for the state.
1:52:18 PM
REPRESENTATIVE TARR commented the third way to qualify for the
GRE is not as well understood as the first two ways, plus the
third way is at the discretion of the commissioner. She asked
Mr. Pulliam how he determined what oil development would qualify
for the GRE under CSSB 21(FIN) am(efd fld) when he developed the
graphs on slides 9-10.
MR. PULLIAM replied he is looking at it as being either one
situation or another, so he did not try to draw the graphs to
say the percentage that would or would not. The lower line on
the graph represents that 100 percent of the barrels qualify for
the GRE and the higher line on the graph represents that 0
percent of the barrels qualify for the GRE. The actual mix of
oil over time is going to be some combination of those two.
1:53:36 PM
MR. PULLIAM commenced his presentation, turning to slide 11 to
compare the investment metrics for a new participant for a 50
million barrel development scenario at a mid-range cost
assumption under ACES and under CSSB 21(FIN) am(efd fld) versus
benchmark areas in the U.S. and around the world. At a 12.5
percent royalty rate, the net present value (NPV) at $100 per
barrel under ACES is $3.09 while under the Senate bill it nearly
doubles to $5.93. Under the Senate bill this would all be with
the GRE because it is new development, he pointed out. For
offshore Gulf of Mexico [the NPV is $6.22]. He directed
attention to the other measures of profitability index, internal
rate of return (IRR), and cash margins, stating the cash margins
are better under the Senate bill than under ACES. He noted
government take is nearly 14 percentage points less under the
Senate bill than under ACES, bringing it out of the unattractive
range and into the attractive range relative to the
opportunities that producers would have elsewhere.
1:56:44 PM
MR. PULLIAM moved to a comparison of these same economics for an
incumbent [slide 12]. Under the Senate bill, he pointed out,
the columns for 12.5 percent royalty rate and 16.67 royalty rate
look pretty much the same as they do for the new participant.
On these incremental investment analyses, the ability of an
incumbent to buy down its existing tax rate increases the NPV
and IRR relative to a new participant. So, for an incumbent,
there is not much of a change when going between ACES and the
Senate bill on an incremental basis.
1:57:52 PM
REPRESENTATIVE SEATON inquired what the number of years is for
this scenario.
MR. PULLIAM believed most of the production here would go over
25 years. Two thirds of the oil, he added, is going to be
produced in the first 10 years.
1:58:19 PM
REPRESENTATIVE SEATON requested these charts be prepared for the
committee in nominal dollars because inflating it to 2.5 percent
changes completely the calculations where there is or is not
progressivity. At a price of $185 per barrel the calculation
completely changes, he said. Both the legacy producers and new
entrants have testified that they make their calculations and
decisions on nominal dollars, not 2.5 percent inflated dollars.
If these charts are prepared in nominal dollars, then a price of
$100 per barrel will be $100 throughout the calculation.
MR. PULLIAM responded he can produce charts that way if the
committee likes, but he strongly cautioned members against
drawing any meaningful conclusions from that kind of analysis
because he does not think it is correct. He said he does not
think it will provide an appropriate way to look at the problem
and he does not think it is the way industry would look at the
problem either. In particular with a system like ACES, it would
be problematic to ignore that inflation over time pushes a
company's tax rates higher. He further noted that going all the
way back to 2006, all the charts and presentations for PPT and
ACES were done this same way.
2:00:58 PM
MR. PULLIAM, returning to his presentation, said the charts on
slides 13-16 are the same as the last two slides except they
change the cost assumptions [which can be found at the bottom of
each slide]. He therefore left the charts for members to study
on their own.
2:01:33 PM
MR. PULLIAM next looked at the cash flows to the state and to
new and incumbent producers under ACES and CSSB 21(FIN) am(efd
fld) using a scenario of $100 West Coast ANS ($2012) and a 50
million barrel oil development at mid-range cost [slides 17-18].
He said the relationships between these two bills do not change
relative to what he presented to the committee at an earlier
hearing [January 24, 2013, slides 59-60].
2:02:08 PM
MR. PULLIAM then reviewed the annual producer cash flows to a
new participant and to an incumbent under ACES and CSSB 21(FIN)
am(efd fld) using the same aforementioned scenario of $100 West
Coast ANS ($2012) and a 50 million barrel oil development at
mid-range cost [slide 19]. For both an incumbent and a new
participant, spending occurs up front with revenues starting
about year five. Under ACES, the incumbent's spending is lower
than that of the new participant's because of the increased
subsidy upfront through the effect of the buydown of the tax
rate. The result of this difference is that the incumbent has a
higher net present value [$277 million] than does the new
participant [$131 million]. Under CSSB 21(FIN) am(efd fld), the
upfront spending and revenues are virtually identical for an
incumbent and a new participant because these two different
classes of producers are now being treated identically under
this proposed tax system.
2:03:43 PM
CO-CHAIR SADDLER observed that under ACES in year four, a bar is
seen for the new participant but none is seen for the incumbent.
MR. PULLIAM said the bar [for the incumbent] cannot be seen
because it is probably right at the zero line.
2:04:11 PM
MR. PULLIAM turned to discussing what he calls the "break-even
analysis" [slide 20], which addresses how much new development
it would take to offset the revenue being lost by going from
ACES to CSSB 21(FIN) am(efd fld). He pointed out that the
fiscal notes put out by the [Department of Revenue (DOR)] assume
there is no change in production; the fiscal notes hold
everything constant and look at what the different tax rates do.
Of course, it is known that tax rates affect profitability and
profitability is going to affect investment decisions. The
question everyone has is whether the state will get more oil
production and will it make up for the tax cut. He explained
slide 20 looks at how much more oil is needed for the State of
Alaska to break even revenue-wise. Using [DOR's] forecast and
the assumptions of a mid-cost [$20 per barrel] development and a
West Coast ANS price ($2012) of $105, he looked at revenues the
state could expect to generate on a per barrel basis at the one-
sixth royalty rate [16.67 percent], which would be mostly new
development, and at the one-eighth royalty rate [12.5 percent].
2:06:07 PM
MR. PULLIAM said the revenues generated over time under CSSB
21(FIN) am(efd fld) at [16.67 percent] royalty would amount to
$35.50 a barrel in nominal dollars and $25.75 in real terms
(2012 dollars). Additionally, each new barrel flowing down the
Trans-Alaska Pipeline System (TAPS) would help spread the cost
of TAPS and reduce the per barrel tariff. The impact of that
reduction would increase state revenue by $3.50 per new barrel
($2012). He clarified the reduction in the tariff is not $3.50,
the reduction is much smaller than that; however, expressed in
total dollars in savings to the state across each new barrel
produced, it works out to about $3.50 for each new barrel. At
12.5 percent royalty, each new barrel would generate $23 in
production revenue and $3.50 in additional savings on TAPS
tariffs, for a total of $28.50. Looking at the projected impact
over the next 30 years assuming no production change, Mr.
Pulliam said the nominal difference would be about $17 billion
and, in 2012 real dollars, it would be about $12.9 billion. To
make up those dollars at the aforementioned per barrel amounts,
it would take 441 million barrels at 16.67 percent royalty and
487 million barrels at 12.5 percent royalty. At 16.67 percent
royalty, this equates to needing to develop 15 million new
barrels per year, or 40,000 new barrels a day, over the next 30
years. At 12.5 percent royalty, it equates to needing to
develop 16 million new barrels per year, or 44,000 new barrels a
day, over the next 30 years. Regarding how that amount of new
development relates to estimates of what is left to find, he
said that on state lands just in the Central North Slope the
estimate is 3 billion barrels of undiscovered economically
recoverable oil at $90 a barrel. Per year, that is 0.5 percent
of what is left.
2:09:21 PM
CO-CHAIR SADDLER requested Mr. Pulliam to interpret the chart on
slide 20 in one or two sentences.
MR. PULLIAM replied the sentence is how much more oil needs to
be developed for the state to break even with the revenues that
are estimated will be lost in moving from ACES to CSSB 21(FIN)
am(efd fld).
CO-CHAIR SADDLER understood the answer to be 15 million barrels
per year, each year, for 30 years; or [a total of] 441 million
[barrels] over that 30 years.
MR. PULLIAM confirmed it would be about 15 million barrels a
year of new oil for a total amount of between 440 million to 487
million barrels. In further response, Mr. Pulliam confirmed
that each year the production equivalent of 40,000 barrels would
have to be added per day over the production that is forecast.
He said this example assumes it is all new production and he has
applied the GRE to all of this as well as the $5 [per barrel]
credit. If additional oil is brought on that does not qualify
for the GRE, then the volumes required would be lower.
2:10:46 PM
REPRESENTATIVE TARR asked what discount rate was used to
calculate breaking even. She further asked what year during
this period of 30 years was assumed for when the new barrels
would come on line.
MR. PULLIAM responded the figures are all done in real 2012
dollars, so the discount rate is implicitly 2.5 percent. He
believed his assumption was four years from now for when new oil
would start coming on line.
2:11:31 PM
MR. PULLIAM resumed his presentation, addressing how reasonable
it is that this new production will happen. There is no formula
that will predict, he noted, but it can be looked at as to
whether this is or is not a gargantuan task. As seen on slide
20, what needs to be developed is 0.5 percent of undiscovered
resources each year; over 30 years that is about 15 percent.
From the standpoint of physical capability that would not seem
to be an unreasonable amount, but what would that take capital-
wise? Assuming a development cost of $20 per barrel, he
calculated it would be about $300 million [slide 21].
2:12:40 PM
MR. PULLIAM, in response to Co-Chair Saddler, reiterated there
is [an estimated] 3 billion barrels of undiscovered oil. In
further response he confirmed that 0.5 percent of 3 billion
barrels would have to be found and produced per year, for a
total of about 15 percent [of the 3 billion barrels]. Thus, new
production does not have to be more than what is thought to be
left and economically available.
CO-CHAIR SADDLER surmised, then, that this is not a pipe dream
and is within the realm of possibility.
MR. PULLIAM concurred.
2:14:03 PM
MR. PULLIAM returned to slide 21, saying that at a per barrel
development cost of $20, about [$300 million] per year in
additional investment would be needed. Relative to the $2.4
billion invested in 2012, this would be about a 12.5 percent
increase in investment, so not a gargantuan level of increase.
2:14:40 PM
REPRESENTATIVE TARR recalled hearing that some of the current
investment is related to the credits [under ACES], some of which
would be going away under CSSB 21(FIN) am(efd fld). She
inquired what the impact would be given that CSSB 21(FIN) am(efd
fld) removes 10 percent of the incentive available now for some
of that capital investment. She further recalled criticism that
the [current] credits have not lead to new production and asked
whether there should be a more critical look at where that $2.4
billion was spent to see the impact of where those dollars go.
MR. PULLIAM, regarding whether the credit coming down would make
the spending less likely, answered he would say no because the
credit is a part of an overall system. While the current
overall system has a higher level of credit, it has a much
higher level of take once the oil starts to be produced; so the
overall economics are not as attractive as the lower credit and
the lower take proposed under CSSB 21(FIN) am(efd fld). He
added he does not think there is any question about that and
cautioned against getting wrapped up in the credit by itself.
For example, taken to an extreme, there could be an 80 percent
credit, but a tax of 90 percent, and this would take the state
the other way. The credit must be treated as part of the
overall package because how the investment economics work for
that package is how it is looked at.
MR. PULLIAM, regarding Representative Tarr's second question
that some of this money was spent in other ways, said he hopes
it is not being spent in ways that do not lead to production.
However, even if it did, it is part of this $2.4 billion and how
much more is needed to get to the development of 15 million
barrels a year. It is really that increment that is being
talked about, and that increment is about $300 million, which is
12.5 percent of what was spent in 2012. It gives a sense as to
how gargantuan is this task.
2:17:30 PM
REPRESENTATIVE SEATON expressed skepticism regarding Mr.
Pulliam's answer to Representative Tarr's question about the 10
percent loss in credit, saying those are dollars now for new
development. While CSSB 21(FIN) am(efd fld) says that 10 years
from now when a producer has some oil flowing there will be less
take, it also says the small producer must spend at least 10
more years. Additionally, the Senate bill would take away the
small producer tax credit and when production started the small
producer would immediately have to start paying tax. He said he
would like to see more analysis than just a statement, given the
small producers have told the committee that [HB 72/SB 21] would
probably change their decisions of investing in Alaska because
of the risk and long-term investment. A promise in the future
and more expense now changes the risk/reward for other options
the small producers have, such as in the Lower 48. He requested
Mr. Pulliam to discuss this issue further.
2:19:15 PM
MR. PULLIAM replied he has had discussions and has listened to
all of the testimony of the small producers. In those
discussions the small producers were focused on SB 21 as
introduced; that version provided no ability to monetize the
losses, so the small producers would have gone from being able
to monetize 45 percent of their expenditure to having to carry
forward that full amount. In his view, the one producer most
concerned about that was Pioneer Natural Resources Alaska, Inc.;
however, viewed as a package, he said he thinks the others
looked at the change more favorably. As the bill worked its way
through the Senate the small producers came back and talked to
that body; he suggested committee members particularly listen to
Armstrong Oil & Gas, Inc. and Brooks Range Petroleum
Corporation. Although he did not recall Pioneer coming back
after the changes proposed in the Senate, he said he thinks
Pioneer views the package as being very favorable and pro-
investment.
MR. PULLIAM, regarding more analysis, referred Representative
Seaton to the chart on slide 11 in which a lot of analysis was
done looking at the value and investment metrics of this
proposal. Mr. Pulliam contended the proposal undoubtedly raises
the value of this investment on any level to a new participant,
even without the additional 10 percent credit or the carry
forward of the small producer tax credit. He pointed out that
the NPV is doubled, the profitability index (PI) is increased,
the internal rates of return (IRR) go up, the cash margins go
up, and the government take goes down. Sure, if he was a
producer getting credits he like to keep getting those and also
have lower taxes. However, he continued, the package under CSSB
21(FIN) am(efd fld), from the standpoint of either a new
participant or incumbent, is much stronger from an investment
standpoint than what Alaska has under ACES.
2:21:52 PM
CO-CHAIR SADDLER inquired whether it is true that replacing
credits, like the current qualifying capital expenditure (QCE)
credit that does not necessarily lead to production, with the
GRE and the $5-per-barrel credit will lead to investment that is
more efficient or more focused on actual production.
MR. PULLIAM offered his belief that it will and is a better way
of providing the kind of incentive to get additional barrels
than simply having the QCE credit.
2:22:29 PM
MR. PULLIAM, resuming his discussion of the reasonableness test,
displayed a graph [slide 22] of the estimated capital spending
for exploration and development on Alaska's North Slope compared
to spending in the rest of the U.S. and the world for the years
2003-2012. Over that time period, he said, Alaska's spending
went up about 250 percent total, whereas worldwide spending went
up about 400 percent and U.S. spending went up a little more
than 450 percent. Keeping these numbers in mind, he turned to
another reasonableness test depicted on slide 23, noting that
had investment in Alaska kept pace with the rest of the world,
an additional $1.6 billion would have been spent in Alaska in
2012. Responding to Co-Chair Saddler, he reiterated that
worldwide spending went up 400 percent over the last decade.
Spending in Alaska in 2003 was about $1 billion, and had
spending in the state gone up at the same rate as worldwide,
Alaska would have been at $4 billion in spending in 2012 instead
of the actual $2.4 billion, a difference of $1.6 billion.
Continuing, he said he is asking the question of what that $1.6
billion would turn into in terms of development. At $20 per
barrel [in production cost] it is about 80 million barrels and
Alaska needs 15 million barrels a year; so, from the standpoint
of keeping up with the Jones's, Alaska would be there.
2:24:37 PM
REPRESENTATIVE TARR inquired how the unique situation of joint
operating agreements on the North Slope is accounted for. In
the past, she said, expenditures desired by some partners were
vetoed by one of the partners so that the spending did not go
forward.
MR. PULLIAM disagreed the North Slope joint operating agreements
are unique. He said there are joint operating agreements
worldwide that require agreement amongst owners and that are
operated in similar ways as on the North Slope. Rarely does a
big field have just one owner; therefore, he would say that is
one thing that makes them comparable. Additionally, in looking
at effects over time since 2003, the same issue of joint
operating agreements remains on the North Slope, so he does not
try to untangle that from the analysis. It is an issue, but it
is an issue in Alaska as well as elsewhere and he does not know
that it could be untangled from analysis even if that was
wanted.
2:26:32 PM
REPRESENTATIVE TARR asked whether it is possible to get the
representative companies and actual data used to produce the
graph on slide 22.
MR. PULLIAM responded that, with respect to the North Slope, he
does not think he can provide the underlying data because it is
confidential, but he can provide it in aggregate form. With
respect to the others, he said he does have the details for some
of the years as opposed to just the aggregate.
CO-CHAIR FEIGE noted this is a repeating issue that comes up.
Based on the confidentiality of these tax returns, he continued,
at least three of them must be aggregated to provide a number.
REPRESENTATIVE TARR said BP's [recent oil spill] in the Gulf of
Mexico may have limited the company's opportunities for
investments in North American and elsewhere. Therefore, it
would be helpful to more critically examine the data used to
create the graph.
MR. PULLIAM agreed to provide as much detailed information as he
can. The worldwide and U.S. figures in the graph are all public
information, he continued, so there is no confidentiality there.
2:28:04 PM
REPRESENTATIVE SEATON said he would like to distinguish Prudhoe
Bay from other places on the North Slope and around the world
because it requires the agreement of all three owners for
investment to move forward. According to the information he
has, only one other field in the world has the same criteria
where all participants must agree to the investment or the
project is vetoed. He recalled that two enhanced oil recovery
projects in Prudhoe Bay were proposed and sanctioned by BP, but
were vetoed by Exxon. He maintained there is a broader question
here if Alaska is counting on Prudhoe Bay being most of that 5
percent that needs to be developed because there is a greater
restriction in that than other fields. He requested Mr. Pulliam
to discuss this further in writing.
MR. PULLIAM answered that, first, most fields are operated in a
manner where, at the very least, there must be majority
agreement to move forward on anything. Second, this is not a
situation new to Alaska; it has been here so that aspect is
controlled for in his analysis when looking at the potential of
changing from one level to another. Third, it is looking at a
situation of changing the tax climate and making things more
profitable and how likely it is to see a favorable investment
response. Those metrics have been looked at to see whether they
have been made attractive here versus opportunities elsewhere.
Lastly, the revenue requirement he looked at has anticipated
that this would all qualify for the GRE, so it would all be new
production, and then couching it in terms of what is
undiscovered. Prudhoe Bay is something that has been discovered
and it would be great to get some more production there as well,
and the economics - the proposed changes - make that a high
probability. However, what he is showing here is that more
production from Prudhoe Bay is not required to get to the kind
of volumes that are needed.
2:31:34 PM
CO-CHAIR FEIGE asked where the other field with the same kind of
joint operating agreement [as Prudhoe Bay] is located.
REPRESENTATIVE SEATON replied he does not recall its name, but
that it is in Indonesia and is associated with a large pipeline.
He said he was at a Pedro van Meurs' tax seminar and a fellow
from Australia was familiar with only one other field in the
world that had this same constraint as in Prudhoe Bay.
2:32:37 PM
REPRESENTATIVE TUCK, referring to slide 22, asked whether U.S.
spending includes or excludes the Alaska North Slope.
MR. PULLIAM answered he subtracted the North Slope from U.S.
spending to get the figures on the slide. In further response,
he clarified that the published U.S. figures include the North
Slope, but for this slide he subtracted out the North Slope.
REPRESENTATIVE TUCK inquired whether Mr. Pulliam subtracted U.S.
spending from the worldwide spending.
MR. PULLIAM answered the worldwide spending includes the U.S.
2:33:25 PM
CO-CHAIR FEIGE said that does not work and asked whether the
worldwide spending depicted on slide 22 includes the U.S.
MR. PULLIAM replied the U.S. is part of the world.
REPRESENTATIVE TUCK said Alaska is part of the U.S. but was
excluded from the U.S.
MR. PULLIAM responded he subtracted Alaska from all of these
figures.
2:33:48 PM
CO-CHAIR FEIGE said the bar on the graph for worldwide spending,
then, would have to be higher than the U.S. bar.
MR. PULLIAM clarified the bars on slide 22 are indexes, so it is
changes over time that are being looked at. To explain how the
bars are constructed, he pointed out that spending in Alaska in
2003 was $1 billion, so the index value is 100 on the graph.
Spending in Alaska rose to about $2.4 billion in 2012 so on an
index basis that is 240; thus it is 240 percent of the level it
was in 2003. While Alaska was at $1 billion in 2003, U.S.
spending was probably $100 billion and worldwide spending was
probably $250 billion. Thus, this graph is showing that U.S.
spending overall has increased the fastest, and worldwide
spending has increased a bit slower than the U.S., and Alaska is
slower than either one.
2:35:20 PM
REPRESENTATIVE TUCK asked why the North Slope is not included in
the overall average worldwide spending.
MR. PULLIAM replied that could be done, but the picture would
not look any different because spending in Alaska is so small
relative to the world. What is trying to be done is compare
changes in Alaska to changes elsewhere. In doing that, subtract
Alaska out and look at Alaska versus the U.S. and versus the
rest of the world.
2:36:16 PM
REPRESENTATIVE TARR noted that some of the earlier years
depicted on slide 22 include years where Alaska's tax system was
under the economic limit factor (ELF) under which there was
effectively no tax on some of the largest producing fields. She
surmised if overall behavior is related to tax rate, then Alaska
should have seen significant spending under that scenario.
MR. PULLIAM responded it can be seen during that time period
that spending increases in Alaska are roughly consistent with
spending increases elsewhere in the world. Spending in that
early period was not held back by the tax rate, but rather by
the low oil prices. The rate of increase everywhere in the
world is not the kind of increase that has been seen in the last
five years as compared to the first five years of that [2003-
2012] time period.
2:37:26 PM
MR. PULLIAM continued his presentation, moving to slide 24 and
again resuming his discussion of the reasonableness test. He
said a group of economists studied the impact of tax rates by
constructing a model to try to predict the impact of changes in
tax rates on drilling, among other things ["State Taxation,
Exploration, and Production in the U.S. Oil Industry" by Kunce,
Gerking, Morgan, and Maddux, November 26, 2001]. The authors
looked at rates in a number of different states, constructed a
model, and then applied their model to Wyoming.
2:38:53 PM
REPRESENTATIVE HAWKER inquired whether Mr. Pulliam places high
or low credibility on the quality of work in this study.
MR. PULLIAM replied it is not a peer-reviewed study. He said he
has looked at the study, but has not dug into any of the
underlying calculations. Directionally, the results look
correct, but he cannot say about the magnitude of them. He said
Professor Gerking talked to the Alaska Senate last year about
potential impacts in Alaska, but may not have been familiar at
that time with the Alaska tax system; Mr. Pulliam offered his
belief that all the analyses were done based on the old gross
system. He reserved judgment on the study, but said the kind of
impacts talked about, and the measuring on drilling responses to
tax rate changes, do seem reasonable and some of the results in
the study match with the reasonableness tests he is presenting
to the committee.
2:40:27 PM
MR. PULLIAM returned to his presentation, saying the economists
in the aforementioned study went through a thought experiment by
looking at Wyoming to see what would happen if the tax rate was
doubled in that state. They found that doubling the tax rate
did not have a huge impact on production, but Wyoming got a lot
more production taxes. They also found that while the doubling
did not have a huge impact on production, it had a big impact on
drilling - and, in Alaska, drilling is the driver of getting
additional production. Something to keep in mind, he pointed
out, is that doubling the tax rate in Wyoming is going from 5.3
percent to 10.6 percent, about a 3 percentage point change in
government take. Directing attention to page 22, table 3, of
the Gerking study he noted that a doubling of the tax results in
a 19.4 percent drop in drilling. Moving to slide 24 of his
presentation, Mr. Pulliam said he decided to turn that result
around and calculate the percentage if taxes were dropped from
10.6 percent to 5.3 percent and found that it would be a change
of about 23 percent. Thus, for each 1 percent drop in the
severance tax rate there is about a 4 percent change in
drilling. Under CSSB 21(FIN) am(efd fld), Alaska is looking at
about a 10 percent drop in the effective gross tax. So, if this
same kind of relationship in drilling impact holds in Alaska,
that would suggest about a 43 percent change in drilling. In
2012 the Alaska North Slope had 60 wells started that produced;
a 43 percent increase would be about 26 additional wells a year.
In the first year of production, 26 wells would produce about 11
million barrels. Assuming a 15 percent decline over the life of
the production, that would be about 72 million barrels, which is
a lot higher than the 15 million barrels the committee just
looked at.
2:43:32 PM
MR. PULLIAM allowed he cannot say whether the results translate
from Wyoming to Alaska, although the authors of the study think
the results would be generally applicable. To further test the
reasonableness of achieving breakeven development, Mr. Pulliam
said he therefore conducted the same analysis as he did on slide
24, but at half the predicted response rate, which translates
into 13 new well starts per year [slide 25]. Over the life of
those wells, about 36 million barrels would be produced, which
is more than double what Alaska would need to break even on
revenues.
2:44:36 PM
REPRESENTATIVE SEATON noted the Gerking study is from November
26, 2001, when oil prices were $14-$20 per barrel; increasing
the tax from 5.3 to 10.6 percent on the gross at such a low
price would mean going bankrupt or backwards. He said he is
skeptical on how doubling a gross-based tax at low prices is
applicable to a profit-based tax at today's prices. He
continued: "That is why we are here is because people are
saying ... we went to a scenario at $65 a barrel and now we are
$100 a barrel, and ... is the applicability the same. ... Taking
this assumption for reasonableness and saying that we were in
$15 a barrel oil and we are doubling the gross tax rate, which
you have to pay no matter whether you are making a profit or
not. I think those outcomes and those decision points ... could
be quite different."
MR. PULLIAM agreed they could be different and added that these
kinds of things are taken with a grain of salt. There is not a
lot of work in this area, he said, it is a very difficult thing
to tease out. But this is an example of one that has been done
and the kind of relationships that were found. One of the
reasons he ran a sensitivity test is in case these things do not
directly translate over - perhaps it is only one-half or one-
third that effect [slide 24]. However, it is all still pointing
to say that that breakeven volume is something that is doable
and is not a big stretch, which is the point here.
2:47:33 PM
CO-CHAIR SADDLER commented this is an interesting calculation
and said he would like to have more familiarity with it before
he gives it a lot of credence. He asked whether this is the
only test of reasonableness and why this particular one was
presented to the committee.
MR. PULLIAM responded he looked to see whether there are studies
that have looked at what effect might be gotten from a tax rate
change. There is not a lot and this is the one he has seen.
Also, one of the authors talked to the legislature last year.
2:48:26 PM
CO-CHAIR SADDLER said Representative Seaton has basically
questioned the validity of the study because it is old and
different conditions. He inquired whether there is a better,
more reliable, more up-to-date study.
MR. PULLIAM answered he does not believe there is something more
reliable or more up-to-date, and he is not saying that this
study is. There is not a formula he can give the committee, he
reiterated. [The Gerking study] is one piece among several:
slide 20 looks at how reasonable is it to expect that Alaska
might get this kind of change; slide 11 looks at the investment
metrics, which would increase considerably. Then there is
looking at how much more production is needed - which is 15
million barrels a year - and how that relates to what is left
[to be discovered]. That 15 million is not a lot, so from that
standpoint it would be reasonable to assume that Alaska could
get it. Slide 21 looks at how much additional capital would be
needed to get that 15 million barrels; that capital is $300
million a year, a 12.5 percent increase from 2012. Achieving
this increase is not a stretch as can be seen on slide 23 which
looks at the spending increases that have happened in the rest
of the world under tax rates that Alaska would be more
comparable to. The Gerking study is another piece that suggests
such an increase is not an unreasonable result. While he would
not use this study to predict, it is one piece to consider.
2:50:25 PM
CO-CHAIR FEIGE understood Mr. Pulliam to be saying he is not
really predicting that this is going to be the end result; just
that the possibility exists that it could be done.
MR. PULLIAM replied one has to look and balance the evidence.
2:50:37 PM
CO-CHAIR SADDLER understood the last three lines of slide 23 to
be saying that if Alaska had seen the same increase in capital
investment as had the rest of the world, Alaska would have had
$1.6 billion more spending which would have encouraged the
production of an additional 80 million barrels of oil.
MR. PULLIAM said $1.6 billion would be enough to develop an
additional 80 million barrels at $20 a barrel. In further
response, he confirmed this would not be per day.
CO-CHAIR SADDLER, continuing, understood it would take 15
million barrels per year for the state to break even or get back
what it has given in lower tax rates.
MR. PULLIAM responded correct. Responding further, he confirmed
that 65 million barrels is the additional amount of production
[per year] that Alaska could have seen if investment in Alaska
had been at the same rate as in the rest of the world.
2:52:07 PM
MR. PULLIAM, skipping slide 26, concluded his presentation by
moving to slide 27 to discuss how the divisible income is
divided up between state government, federal government, and
producer. The divisible income is the net value of the oil
after costs, explained. Under ACES, at a West Coast ANS price
of $60 ($2012) per barrel, the state take is a little more than
40 percent. State take includes taxes, royalties, ad valorem,
and income taxes. At $120 the state take is just shy of 60
percent and at $140 the state take is just over 60 percent.
Producer take declines over this price range [to about 39
percent at $60, about 28 percent at $120, and about 26 percent
at $140]. Under CSSB 21(FIN) am(efd fld), the takes basically
remain flat across the price spectrum: state take is about 43
percent at $60, rising to about 45 percent at $140; producer
take is in the mid-30 percent range, slightly declining as the
state take rises; and federal take is just below 20 percent.
2:53:39 PM
REPRESENTATIVE P. WILSON observed that [under CSSB 21(FIN)
am(efd fld)] the take for each entity basically remains the same
between a price of $60 and $140 a barrel. She asked whether
this is still the case at prices below $60 and above $140.
MR. PULLIAM answered that at the top range it does not really
change much from what is seen on slide 27. At very low prices
the state take would go up - the state would get regressive at
lower prices.
2:54:21 PM
REPRESENTATIVE SEATON inquired what dollar amount is being
transferred from the state to the federal government at the
price of $120 per barrel.
MR. PULLIAM replied he does not know the dollar amounts, but
under ACES the federal take is about 14 percent and under CSSB
21(FIN) am(efd fld) it is just below 20 percent. The federal
government gets its share from a combination of the state and
the producers because what producers pay in state taxes is
deductible against their federal taxes. The producers will have
more profit, which will be shared 35 percent to the federal
government and 65 percent to the producer.
2:55:37 PM
REPRESENTATIVE TUCK observed the maximum price depicted on slide
27 is $140 and noted that the Organisation for Economic Co-
operation and Development (OECD) forecasts prices of $170-$220
in 10 years. He requested Mr. Pulliam to prepare a graph that
goes up to a price of $250 a barrel.
MR. PULLIAM agreed to do so.
2:56:17 PM
REPRESENTATIVE TARR returned to slides 24-25 and requested Mr.
Pulliam to prepare a chart for government take that drops from
60 percent to 50 percent, so the difference can be seen between
going from 60 to 55 percent versus 55 to 50 percent in an effort
to determine the "sweet spot" for getting this new amount of
investment.
MR. PULLIAM replied these relationships will not be continuous
because at some point government take is going to "choke it off
... you are going to fall off the cliff" and which is where he
thinks Alaska has been. So reducing 10 percentage point from
that level down may well get a much bigger impact than
increasing government take in a system that goes from 5 percent
to 10 percent; that is a 3 percentage point government take at a
fairly low government take level. So, with that background, he
would not be surprised to see a bigger impact with the kind of
change being talked about than just a proportional change in the
government take.
2:58:10 PM
REPRESENTATIVE TARR requested Mr. Pulliam to do some evaluation
of that for the committee, perhaps looking at Alaska's current
government take and evaluating it by percentage point change and
then 1 or 2 percent beneath that; something that would give the
committee an idea of the bang for the buck in a bracketed way.
MR. PULLIAM responded doing it quantitatively would be a
gargantuan task, but said he can provide a qualitative analysis.
2:59:00 PM
CO-CHAIR FEIGE thanked Mr. Pulliam for presenting the governor's
point of view. He recessed the meeting to a call of the chair,
saying the next presentation will be from the legislature's
consultant [Janak Mayer, PFC Energy].
4:40:02 PM
CO-CHAIR FEIGE called the House Resources Standing Committee
meeting back to order. Representatives P. Wilson, Tuck, Hawker,
Saddler, and Feige were present at the call back to order.
Representatives Johnson, Olson, Seaton, and Tarr arrived as the
meeting was in progress. Representative Herron was also
present.
4:40:12 PM
JANAK MAYER, Manager, Upstream and Gas, PFC Energy, stated Econ
One Research provided a good introduction to what CSSB 21(FIN)
am(efd fld) would do. To frame the issues and aims overall, he
said he will start with the fundamental problems that PFC Energy
has identified with Alaska's Clear and Equitable Share (ACES)
and where and how those issues are addressed in CSSB 21(FIN)
am(efd fld) [slide 2]. He said the largest issue, and the
center of debate, is the high government take under ACES. The
very high degree of progressivity under ACES means Alaska's
regime, relatively speaking, is uncompetitive compared to many
jurisdictions it would be competing against for investment
capital, particularly at the current high price levels. Another
issue under ACES is capital credits and the significant downside
exposure these create for the state in low price environments,
for high cost projects, and for projects that are not entirely
or not at all on state land. The capital credits, plus the
producer's ability to buy down its tax rate through spending,
means there are many different circumstances under which the
state can find that on a production tax basis, it effectively
contributes more in low price environments and for high-cost
projects than it actually reaps through the production tax.
That is particularly the case for a project that is not entirely
on state lands where the royalty received by the state is also
substantially less, but the royalty is still making the same
effective contribution through tax credits to the cost of
development of a project.
4:43:21 PM
MR. MAYER said all of the aforementioned points come back to a
common one - the issue of high marginal rates. High marginal
rates under ACES create the buydown effect, meaning if a
producer has a current high level of tax under ACES because of
where it is on the progressivity scale, it can reduce its tax
burden by spending additional capital. This benefit accrues to
an incumbent producer but not to a new development. In
addition, it is not always clear that that benefit actually
translates into the way a company looks at the economics of its
projects. It is a case after the fact once a producer knows
exactly what the oil price was. In terms of the way a company
runs economics on a project, the benefit it gets from rates of
return and other things from the buydown effect is in some ways
ephemeral - it is nice to have but a company cannot always rely
on it. But, it does mean that a producer gets very different
economics when it looks on an incremental basis and a stand-
alone basis and it is not always clear which of those, even to
an existing producer, best represents the actual fundamental
economics of the project. Even if a producer chooses one or the
other, it is very different economics between a new development
for a new producer that has no production versus a new
development on an incremental basis for an existing producer.
4:45:11 PM
MR. MAYER emphasized ACES is a complex system because of the
many different components and because of all the different
capital credits. But, ultimately, it is most complex because it
is very difficult to take a simple look at the system and
understand what it does because what it does and how it works is
very different in different price environments for different
types of producer. More than anything, he opined, it seems the
state should be seeking to create a much more overall level and
neutral playing field that treats everyone the same - that gives
everyone the same basic economics - and he will later talk about
how CSSB 21(FIN) am(efd fld) achieves that. The very high
marginal rates also mean that producers face very little
incentive for greater efficiency in costs. If a producer is
faced with an effective marginal tax rate of 70, 80, or almost
90 percent, the benefit it gets from saving $100,000 is
ultimately one-fifth to one-tenth of its savings and unless
there is significant benefit from making investments to achieve
efficiencies, in many cases it will not be worth doing so under
ACES. Ultimately, these all add up to a complex system with
often counter-intuitive effects.
4:46:41 PM
MR. MAYER reviewed how CSSB 21(FIN) am(efd fld) aims to tackle
the aforementioned issues. Most significantly, he said, through
eliminating progressivity, CSSB 21(FIN) am(efd fld) creates an
overall neutral regime that gives a steady level of government
take across a very wide range of prices - essentially close to
65 percent government take at prices as low as $70 a barrel to
over $160. The bill limits the downside risk to the state from
the capital credit by eliminating the capital credit. However,
it does not eliminate the downside risk because it maintains the
net operating loss (NOL) credit, which is at the rate of 35
percent rather than [the current] 25 percent to go with the
higher 35 percent base rate. That seems a manageable downside
risk, he said, because it is 35 percent effective government
support for spending versus the 45-90 percent effective support
for spending under ACES depending on whether one is a new or
incumbent producer.
4:48:07 PM
MR. MAYER addressed the question that came up during Mr.
Pulliam's testimony about the possibility of negative taxes from
the gross revenue exclusion (GRE) in a low price environment
under CSSB 21(FIN) am(efd fld). He confirmed that that is the
case, saying it would be a remaining exposure to the state under
the Senate bill. However, he continued, that exposure also
exists under ACES; the difference under CSSB 21(FIN am(efd fld)
is that most of the downside risk is controlled because of
eliminating the capital credit. It remains an issue primarily
with projects that are eligible for the GRE - so, by definition,
no existing production and only a small portion of production
over the coming years as new projects come on line. Most
importantly, CSSB 21(FIN) am(efd fld) achieves a balance within
the system through completely even impacts for an incumbent
versus a new producer. It suddenly becomes very clear to assess
how the system works, what it means for any number of different
producers because its impacts are equivalent across the spectrum
and across a wide range of prices.
MR. MAYER further said that a neutral regime also creates just
one low, constant marginal rate. The marginal tax rate under
CSSB 21(FIN) am(efd fld) is the 35 percent that is specified in
the base rate, creating a very strong incentive for producer
efficiency in cost control of investments that can bring down
costs and increase efficiencies. A balanced regime for both a
large and small producer, along with elimination of the capital
credit, allows for the 2016 sunset of both the small producer
tax credit and the exploration credit under CSSB 21(FIN) am(efd
fld). The state is still able to achieve its intention that
small producers are not disadvantaged, while getting rid of a
number of the perverse and counter-intuitive aspects of ACES.
Particularly once those things have been sunset, the state will
have an overall much cleaner and much simpler fiscal system.
4:50:57 PM
REPRESENTATIVE SEATON said he is trying to figure out the idea
that the balanced system is this goal the state has. The state
was trying to incentivize production from new participants
through its tax regime, he continued. They responded actively
and the state has lots of new participants, leases, units
applied for, and exploration drilling taking place. The higher
marginal amount for the producers did not stimulate them to
invest in the legacy fields. It sounds like it is being said
that a legacy owner cannot analyze what it is with existing
production. They know they have a higher buydown, higher
marginal rate, and that they get a lot more investment on an
individual expenditure from the state, yet they have chosen not
to accelerate their capital spend and increase production like
the smaller participants have. While both systems would be
analyzed as being the same [under CSSB 21(FIN) am(efd fld)], the
state would have less incentive for the producers because they
will get less support at high prices and there will be fewer
credits available for the new producers. He asked how this new
balance achieves the goal of stimulating the investment.
4:53:28 PM
MR. MAYER replied he does not concur that ACES has been a boon
for small producers and has attracted an enormous number of them
to the state. Looking at who is actually in Alaska and active,
Nikaitchuq and Oooguruk are the best examples of significant
projects that have come on line in recent years, and they were
discoveries that occurred and were put into sanction before
ACES. Ultimately, he continued, ACES had a detrimental impact
on the economics of those projects. A number of explorers have
come to Alaska and potentially made promising finds but said it
would require a better tax regime. So, in his opinion, it is
not quite clear that somehow ACES has been a boon to small
producers in that sense. It certainly is a boon if a company is
just an explorer just looking to prove up a prospect with no
intention of taking that into production because it provides
that explorer with a high level of government support for
exploration costs. Beyond that, it is hard to see how ACES
helps, whether a small or large producer.
4:55:06 PM
MR. MAYER, continuing his response, said his comment on
incremental economics was not that people are unable to figure
out what the benefit is. Rather, producers assessing the
economics of projects look at them in a wide number of ways and
a project needs to make sense on a stand-alone basis before
looking at the question of after-tax benefits. A large
developer producing a large project is not developing a project
in order to purchase tax equity for itself. It is looking to
make a substantial investment in a long-term asset that produces
significant cash flow over the very long term in a very, very
wide range of price environments. Being able to look at a chart
and seeing that, in theory, a magical internal rate of return
(IRR) can be had if the producer can get an oil price of exactly
$120 over the next 20 years, does not help that producer in the
real world of actually assessing project economics. It seems
ACES is a system engineered to achieve certain magic goals, like
a higher IRR at $120 if an existing producer is looking just at
that one price level at incremental economics. It is the system
that one creates when trying to pull as many levers as possible
to hit particular targets, rather than a system that one creates
if saying that what is wanted is an overall, simple, balanced,
competitive regime that lets the private sector make the crucial
decisions about allocation of capital and prices at a level
playing field and then let the private sector play.
4:57:16 PM
MR. MAYER commenced his presentation, discussing the key changes
that CSSB 21(FIN) am(efd fld) would make to the state's current
tax system under ACES [slide 3]. The current base tax rate
would be increased to 35 percent, explained. Progressivity as a
separate construct under ACES would be eliminated; however, the
$5 per barrel allowance under CSSB 21(FIN) am(efd fld) would be
an implicit progressivity that is progressivity just sufficient
to counteract the regressive nature of the royalty and provide
an overall balanced, steady, neutral level of government take.
The maximum tax rate of 75 percent under ACES would be reduced
to a maximum 35 percent, also known as the base rate under the
Senate bill. Further, CSSB 21(FIN) am(efd fld) provides
incentives for new production. [A gross revenue exclusion
(GRE)] would apply to new producing areas, expansions to
existing producing areas, or areas in legacy fields that are not
currently contributing to production that the Department of
Natural Resources (DNR) has certified as such. The Senate bill
eliminates the current capital credits and the net operating
loss (NOL) credit would be increased from 25 percent to 35
percent to match the Senate bill's base rate. Additionally, the
NOL credit would be monetized over one year rather than two
years. Also, CSSB 21(FIN) am(efd fld) would sunset the current
small producer credit and the exploration credit in 2016.
4:59:21 PM
MR. MAYER compared government take at base production between
ACES and CSSB 21(FIN) am(efd fld) [slide 4]. He pointed out
ACES is a steeply progressive tax system that rises particularly
steeply from a West Coast Alaska North Slope (ANS) price of $70
a barrel to $120-$125. The $120-$125 reflection point roughly
matches with $92.50 a barrel in production tax value. Beyond
$125, the progressivity levels out somewhat but still steadily
increases until going above 75 percent government take at $150,
ultimately reaching over 80 percent government take at the
highest price levels for existing production. Under CSSB
21(FIN) am(efd fld), progressivity is replaced with essentially
a nearly flat 65 percent government take, coming down to about
64 percent at the lowest price levels.
5:00:31 PM
REPRESENTATIVE TUCK inquired what the value is to the State of
Alaska for each percentage point.
MR. MAYER replied he will need to check, but his guess is around
$100 million.
CO-CHAIR FEIGE asked at what price.
MR. MAYER responded at the current oil prices of $100-$110.
5:01:10 PM
MR. MAYER turned to discussion of the new production that would
be eligible for the gross revenue exclusion under CSSB 21(FIN)
am(efd fld) [slide 5]. Under ACES, rates of government take are
actually higher for new developments on a stand-alone basis than
for base production or a new project on an incremental basis,
rising to rates substantially above 75 percent at upper price
levels. However, the Senate bill seeks to further incentivize
new development by applying the GRE, essentially getting the
government take down to 60-61 percent across a very broad range
of prices.
5:02:11 PM
CO-CHAIR SADDLER requested a definition of stand-alone project.
MR. MAYER answered stand-alone means looking just at a new
project by itself with nothing else. It can be viewed as what
that project looks like for a completely new producer with no
existing production, or simply as an exercise in looking at that
project by itself and assessing its economic value by itself.
In further response, he explained stand-alone versus incremental
means rather than looking just at that one project, an existing
producer would add that project onto the producer's view of the
base portfolio and run it through a model. Then the producer
would take just the base portfolio and run it through the model
and subtract the difference between the two. He pointed out it
is under incremental economics that some of the effects come
into play of counter-intuitively high rates of return at
particular oil prices or very high levels of government support
for spending under ACES.
5:03:53 PM
MR. MAYER, in response to Co-Chair Feige, confirmed that the $18
per barrel development on slide 5 is the capital expenditure.
5:04:09 PM
MR. MAYER, in response to Representative Seaton, confirmed that
stand-alone is as if Alaska had a tax system that was ring
fenced. Under CSSB 21(FIN) am(efd fld), the result is the same
whether or not it is looked at on a stand-alone/ring fenced
basis because the economics look the same either way. It is
only for ACES that there is a significant difference.
5:04:38 PM
REPRESENTATIVE TARR observed Mr. Mayer used $18 per barrel in
development cost [slide 5] while Econ One used $20. She asked
whether this is enough for the development costs of heavy oil.
MR. MAYER replied it depends entirely on the grade of heavy oil
as there can be viscous and heavy or heavy and ultra-heavy.
"For the most expensive of those, possibly not," he said. On
the other hand, he said he thinks the most expensive of those is
unlikely to be economic at current technology and current
prices. If this was run at $20 or $25 per barrel in terms of
overall levels of government take, the result would look
basically the same because it looks the same across a very wide
range of development cost for a new project.
5:05:31 PM
REPRESENTATIVE SEATON understood Mr. Mayer to be saying that the
interaction between different fields, such as heavy oil or shale
oil development, would be no different on the economics if ring
fencing was used than under CSSB 21(FIN) am(efd fld).
MR. MAYER responded that is certainly true under CSSB 21(FIN)
am(efd fld) and he does not think one would want to do that in
the interest of maintaining the overall simplicity of the tax
regime. Seeking to incentivize particular types of development
can be done in other ways, the gross revenue exclusion (GRE)
being an example. Under CSSB 21(FIN) am(efd fld), a ring fenced
project making a loss would be eligible for the net operating
loss credit, which at 35 percent is the same benefit as writing
down that loss against the producer's current tax liability; so,
the two things are identical under the Senate bill. But, they
are not identical under ACES because of the difference between a
25 percent net operating loss credit versus, perhaps, being
taxed at 40 percent under ACES.
5:06:51 PM
REPRESENTATIVE SEATON inquired whether Mr. Mayer is saying that
under CSSB 21(FIN) am(efd fld) the major producers can apply net
operating losses to all developments when prices are down.
MR. MAYER answered it is not his intention to suggest, but
simply to say that, in terms of the fundamental economics,
looking at a project on a stand-alone basis or an incremental
basis is the same thing under CSSB 21(FIN) am(efd fld), which is
not so under ACES.
5:07:35 PM
MR. MAYER resumed his presentation, discussing how CSSB 21(FIN)
am(efd fld) compares in competitiveness of fiscal regime to
regimes similar to Alaska [slide 6]. For example, taking out of
the picture countries like Ireland and New Zealand, which have
very low government take but very little oil and gas production,
and countries like Kazakhstan, which have enormous oil fields
that can sustain a much higher level of government take. He
explained slide 6 looks at regimes comparable to Alaska across a
range of different prices; each cluster of [different colored]
bars on the graph represents four different prices - red is $80
per barrel, yellow is $100, blue is $120, and green is $140.
The left red arrow at the top of the graph represents ACES for
base production and the right red arrow represents ACES for new
development at $18 per barrel. The height difference between
the four bars indicates the very steep progressivity under ACES
- government take under ACES rises from 65 percent to 75 percent
across that range of prices. The effect of that progressivity
is to overall put Alaska's regime at the upper end among
countries with which Alaska might seek to compare itself. At a
new development cost of $18 and prices of $100-$140, ACES is as
bad, if not worse, than Norway, which has the highest government
take within countries belonging to the Organisation for Economic
Co-operation and Development (OECD).
5:09:51 PM
CO-CHAIR SADDLER asked whether slide 6 includes a world average
or mean for the regions against which Alaska is compared.
MR. MAYER replied he has not calculated the mean for this
particular data set, so will get back with an answer. In
further response, he said regimes comparable to Alaska are
around the 60 percent level; for pure tax royalty regimes,
probably a little below that; and for production-sharing
contracts about [60 percent].
5:10:49 PM
REPRESENTATIVE TARR observed the regimes on the left side of the
chart on slide 6 appear to have somewhat of a regressive tax,
and on the right side of the chart a more progressive tax. She
requested Mr. Mayer to talk about the trends.
MR. MAYER responded many of the regimes on the left side of the
chart, including Canada and the U.S. Lower 48, are tax royalty
regimes in which the royalties are the most significant portion
and royalties are inherently regressive. Those appearing most
regressive are usually because they have a relatively high level
of government take and may also have a high level of costs.
REPRESENTATIVE TARR inquired whether a chart is available in
similar format to slide 6 that compares the profits per barrel.
MR. MAYER answered he does not have that as such, but at any
given price level the government take is calculated by first
determining the divisible income. Divisible income is all the
revenues less the costs that are netted out. Government take is
the measure of how much of the divisible income is going to the
government; by corollary, the remaining portion is the amount
going to the company. So, it is a percentage of each of those
barrels at each of those prices.
5:12:59 PM
MR. MAYER, in response to Co-Chair Feige, said [the column on
slide 6 labeled Canada - Alberta OS] is Alberta oil sands.
CO-CHAIR FEIGE commented that production from the Alberta oil
sands only sells for $55 per barrel.
5:13:23 PM
REPRESENTATIVE TARR understood the chart on slide 6 does not
reflect the ability in the U.S. to buy state taxes towards
federal taxes in terms of overall government take.
MR. MAYER, qualifying he is unsure he understands the question,
replied the chart includes all of the components of the fiscal
regime combined.
REPRESENTATIVE TARR presumed, then, that for Alaska the total
government take should be a little bit lower once a taxpayer
applies its state taxes towards its federal taxes.
MR. MAYER responded that, like Econ One, he assumed an effective
state tax rate of 6 or 6.5 percent in Alaska, rather than the
nominal 9.4 percent.
5:14:07 PM
REPRESENTATIVE SEATON noted the same producers are operating in
Alaska as are in the Alberta oil sands. He related that
analysts attending a ConocoPhillips meeting in February [2013]
released a statement saying companies are planning to reduce
their assets in the Canadian oil sands. He therefore asked why
it is being said here that it is a tax regime that is going to
drive this differential.
MR. MAYER answered many different factors drive investment
decisions: fundamental economics of the asset itself combined
with oil prices and the tax environment all come together in
those questions. He said he cannot address in his presentation
a particular quote from ConocoPhillips that is specifically
about the oil sands. However, when looking at the overall
levels of investments being made by ConocoPhillips in the Lower
48 as a whole, and the rate of growth of those investments in
the Lower 48 as a whole, there is no question that the company
sees a dramatically more economic opportunity for itself in the
Lower 48 than it does in Alaska.
5:16:02 PM
CO-CHAIR FEIGE surmised a producer receiving $55 per barrel for
Alberta heavy crude is probably not making as much money as it
would in a place where the price is $95-$100, no matter what the
government percentage is.
REPRESENTATIVE SEATON said that is the point. Producers are
leaving some of these low-tax regimes because of the other
economic factors, but it is being considering in this
presentation that basically the tax regime is the only
characteristic that is changing the economic decisions. It may
well be found that this change in tax regime does not do what
was thought because there are other considerations.
CO-CHAIR FEIGE responded "possibly," but said government take is
the major expense; of the total price received for a barrel,
government take is the largest of the components.
5:17:15 PM
MR. MAYER concurred with Co-Chair Feige, saying that is likely
in general. Addressing Representative Seaton, he said he is not
suggesting that government take is the only metric looked at or
is the only thing affecting the desirability of any investment.
The attractiveness of an investment is due to a number of things
and the economics of a project are due to a number of things,
including the cost structure of the project, the price received,
and the interaction of those things with the fiscal environment.
Taking the Alberta oil sands out of the picture and looking at
the rest of the fiscal regimes on slide 6, it can be seen that
these are mostly fiscal regimes at a lower government take as
well as environments that have substantially lower costs than
Alaska. Unfortunately, both of these things work against,
rather than toward, Alaska's competitiveness. PFC Energy has
produced a wide range of analyses looking at what the different
regimes achieve, and has always tried to look at net present
value per barrel and rate of return of different projects. PFC
Energy frequently comes back to slides like these because,
overall, government take is a measure that is particularly
useful and particularly easy to understand what is happening,
but it should definitely not be seen as the only one. In all
those cases, though, what is seen is that the economic value of
projects under ACES is not competitive compared to some of the
other alternative uses of capital, and CSSB 21(FIN) am(efd fld)
goes a long way in rectifying that problem.
5:19:35 PM
REPRESENTATIVE TUCK, given that there are so many other factors
besides taxes in a fiscal regime, requested a comparison be done
between Alaska North Slope, the rest of the U.S., and the world
that looks at an investment comparison along with tax
competitiveness so a direct relationship can be seen between the
two.
MR. MAYER answered he can look at doing that and said Econ One
earlier had a useful slide in terms of looking at the trajectory
of investment.
REPRESENTATIVE TUCK concurred, but said not as specific to the
different prices per barrel as shown on slide 6.
5:20:29 PM
REPRESENTATIVE TARR noted Alaska has a system based on net
profit rather than the gross. She asked which regimes depicted
on slide 6 are gross and which are net profit.
MR. MAYER replied Louisiana, United Kingdom, and Australia are
net profit-based systems similar to Alaska, but purer in that
they only tax profits while Alaska is a hybrid of both gross and
net. The rest of the depicted regimes are gross, royalty-based
regimes.
REPRESENTATIVE TARR commented it would seem logical that a net
profits system would create a more competitive regime to start
with because a producer would know it is not liable for taxes
until it has made money.
MR. MAYER said he will address this when he moves to his next
two slides.
5:22:01 PM
CO-CHAIR SADDLER, for purposes of slide 6, inquired whether it
matters if the regime is net based or gross based, given it
measures government take, not how it was gotten there.
MR. MAYER responded correct, they can all be compared in terms
of government take. The regimes that are regressive tend to be
gross systems, but they can all be compared ultimately. In
further response, he confirmed slide 6 is therefore a fair
measure. He added that royalties in the Lower 48 accrue to the
private landowner rather than technically to government; in most
cases, all those things are counted as government take for the
reason of being able to compare like to like.
5:22:50 PM
MR. MAYER, returning to his presentation, said the question of
relative attractiveness of net versus gross feeds into the
question of regressive and progressive regimes [slide 7]. In
general, there are two possible reasons to desire a progressive
element in Alaska's fiscal regime. One is to "counteract
regressive elements in the regime to achieve something close to
neutrality." The other is to do what ACES does, which is "to go
beyond neutrality to assure a higher level of government take
for the state in high price environments." In thinking about
why do one or the other, it is important to think about what
regressive and progressive regimes imply in terms of very
different outlooks on risk and reward for government and for the
private sector. Regressive regimes have many flaws, but
essentially they limit risk to the state because they put a lot
of downside risk on the private sector, thereby protecting the
state in low price or high cost environments. In return they
provide outsized benefits to corporations in high price or low
cost environments. Progressive regimes, by and large, involve
the contrary: the state bears more price and more costs in
return for taking less when there is less to go around and more
when times are fat.
MR. MAYER, regarding Representative Tarr's question about the
attractiveness of net profit regimes, said Norway is a good
example in that it is a pure net profit-based tax that is at an
overall high level and quite progressive. But Norway has a
number of ways to keep investment going that do not necessarily
apply to Alaska, such as a state-owned oil company and also a
government vehicle that can invest directly in the oil sector.
Norway is also a regime that while having high government take
at the high end, also has substantially lower government take
when prices fall off, so it has no regressive element in its
regime. Unusual about Alaska is that it combines a fixed
royalty with a very progressive net profit-based tax. So, from
an investor perspective, Alaska's fiscal system arguably has the
worst of both worlds because the investor still has all of the
downside risk that comes with a royalty system. Under ACES, the
royalty alone can result in 100 percent government take at $60
per barrel, which is coupled with high government take in high
price environments. So, rather than being a system that chooses
one or the other, ACES does both because it is a hybrid of
royalty regime and profit-based tax.
5:26:32 PM
REPRESENTATIVE TUCK surmised, then, some sort of progressivity
is beneficial.
MR. MAYER, to provide an answer, drew attention to the chart on
slide 8 which demonstrates regressivity, progressivity, and
neutrality in regard to ACES, CSSB 21(FIN) am(efd fld), and
royalty only. He said royalty by itself has a regressive impact
because it is a fixed percentage of a barrel - royalty takes an
ever greater proportion of the available cash net of costs as
prices go down. Effectively, if the price went down to $40 per
barrel, the royalty would reach 100 percent government take.
While CSSB 21(FIN) am(efd fld) does not specifically have
progressivity as a separate element, the intersection of the
higher rate with the $5 per barrel allowance/credit gives
something that is effectively equivalent to an implicit and mild
progressivity. The counterbalance is that regressive element of
the royalty, giving an overall flat neutral government take.
Some mildly progressive element like that is needed in the
system to achieve neutrality.
5:28:09 PM
MR. MAYER, responding to Representative Seaton, confirmed the
blue line on slide 8 delineates the 12.5 percent royalty rate on
legacy fields and that the royalty at a price of $60 per barrel
is 60 percent and at $100 it is 50 percent. Drawing attention
to slide 11, which depicts how the different components of
government take stack together, he clarified that when he says
"royalty only" he is meaning royalty along with state and
federal income tax, but no production tax. Thus, royalty by
itself is not 50 percent government take, rather royalty with
the other standard components of the system is 50 percent
government take.
5:29:23 PM
MR. MAYER, in response to Representative Tuck, confirmed that
the blue line on slide 8 is the royalty plus state and federal
income tax, but no production tax. In further response, he
confirmed the red and yellow lines depicting government take
percentages for ACES and for CSSB 21(FIN) am(efd fld) do include
royalty.
5:29:46 PM
MR. MAYER, responding to Representative Seaton, confirmed the
line depicting royalty percentages also includes property tax.
5:30:12 PM
REPRESENTATIVE TARR returned attention to slide 7 regarding
regressive versus progressive regimes. She understood the
argument here as being that under ACES the state takes on some
of the downside risk and the benefit is on the high side, and
flipping that. She inquired whether, in transitioning to CSSB
21(FIN) am(efd fld), oil companies will need to use a different
discount route for planning projects on the North Slope.
MR. MAYER replied the discount rate used by oil companies is an
internal matter that reflects possibly, in part, the risks of a
project, but mostly it is a corporate standard to enable
different projects to be compared against each other. He said
he does not think the discount rate used would be affected; or,
if it did, that it would make a material impact. The benefits
of different projects are compared against each other by using a
common standard. So, regardless of what the common standard is,
it does not change the result.
5:31:36 PM
MR. MAYER concluded his discussion of slide 8, stating the point
is that royalty is a regressive element. To achieve an overall
neutral or very mildly progressive regime, some sort of
progressive element would still need to be included. In that
sense, the difference between CSSB 21(FIN) am(efd fld) and ACES
is in the degree of that progressivity as well as how it is
achieved. The Senate bill contains an essentially progressive
element that is just progressive enough to counteract the effect
of the royalty and achieve overall neutrality rather than the
jacking up of government take at higher prices.
5:32:27 PM
REPRESENTATIVE TARR asked whether Mr. Mayer has done any
evaluation to see if some small level of progressivity could be
maintained across higher prices.
MR. MAYER responded there are a number of different ways that
could be achieved should that be the direction the committee
wants to go in. For example, explicit progressivity could be
included, which he would recommend against, or the same
mechanism included in the current Senate bill could be used,
which is a combination of a higher base rate with the
progressive element of the dollar per barrel exclusion to bring
it down at lower prices.
REPRESENTATIVE TARR said she is interested in requesting how the
$5 per barrel credit in the current Senate bill could be
modified to have a much more gradual incline than does ACES, so
that rather than a neutral position it is a just slightly
progressive take over higher prices.
CO-CHAIR FEIGE stated that is something Mr. Mayer has already
been asked to do.
5:34:50 PM
MR. MAYER resumed his presentation, explaining the $5 production
allowance is like reverse progressivity to counteract the effect
of royalty [slide 9]. He posed a scenario of 50 million barrels
of production. At a price of $60 per barrel, the production tax
value (PTV) totals $1 billion, for a PTV per barrel of $20 under
the terms of a profit-based tax. At the flat tax rate of 35
percent, the production tax prior to factoring in the $5 per
barrel allowance would be $350 [million]. The production
allowance of $5 would deduct $250 [million], for a production
tax liability of $100 million, or 10 percent of the total PTV
rather than 35 percent. So, at this low oil price, the rate is
substantially below the notional 35 percent base rate. As oil
prices increase, the tax rate after the allowance steadily
rises, reaching a rate of 30 percent after the allowance at a
price of $140. The rate asymptotically approaches 35 percent,
never quite reaching 35 percent as prices get higher and higher.
The 35 percent is therefore better understood as the maximum
rate under the tax rather than as the base rate. The effect of
the $5 production allowance is, in some ways, like a mild form
of progressivity. It is reverse in that rather than going from
a fixed base and building up, it is instead decreasing from a
fixed top level.
5:37:51 PM
MR. MAYER, in response to Representative Seaton, said the
progressive tax rate deduction shown on the bottom of the chart
on slide 9 is the difference between the 35 percent tax rate
[and the tax rate after the allowance]; so progressive tax rate
deduction is what the taxpayer was able to take off its tax rate
by virtue of the $5 per barrel allowance.
CO-CHAIR FEIGE interjected it is the percentage that the $5 per
barrel is worth at each price.
5:38:27 PM
REPRESENTATIVE TUCK understood more is subtracted as the state
taxes at lower prices.
MR. MAYER answered this is because that $5 per barrel is fixed
and $5 per barrel is a much bigger proportion of a $60 barrel
than it is of a $140 barrel.
CO-CHAIR FEIGE interjected that this is to counteract the
royalty curve depicted on slide 8.
MR. MAYER added those two things are offsetting each other to
achieve overall neutrality.
5:39:07 PM
REPRESENTATIVE SEATON understood the gross revenue exclusion
would be 20 percent of everything on slide 9.
MR. MAYER replied slide 9 does not include the GRE because it is
just looking at existing production. In further response, he
clarified that "production allowance" is the $5 per barrel
credit. It can be referred to either way, he said, but he
prefers to think of it as an allowance rather than a credit.
5:39:46 PM
MR. MAYER, returning to his presentation, compared the marginal
and average rates between ACES and CSSB 21(FIN) am(efd fld)
[slide 10]. He explained the depicted tax rates are not graphed
on oil price, but rather on production tax value (PTV) per
barrel, which is what the tax is actually based on. Under ACES,
the average tax rate rises steeply between a PTV of $30 [and tax
rate of 25 percent] and $92.50 (and tax rate of 50 percent).
After this, the rate of incline is shallower, reaching a maximum
tax rate of 75 percent at $300 per barrel PTV. At current
prices of $110 and $30 per barrel in costs, the PTV is $80. At
a PTV of $80, the marginal tax rate under ACES is just below 80
percent. At a PTV of $92.50, the marginal tax rate under ACES
is 86 percent.
5:41:27 PM
MR. MAYER pointed out what can happen at this high marginal tax
rate when a producer is making a decision on capital to spend or
to do something to reduce costs. At a PTV of $92.50, anything a
producer does to increase its efficiency - reduce its costs -
the producer gets only 16 percent of the benefit because the
remaining percent of the benefit goes to the state. Similarly,
for any dollar a producer decides to spend it bears effectively
only 16 percent of the cost of that dollar because the remainder
on an after-tax cash flow basis goes to the state. In his
opinion, this is one of the biggest problems of ACES from the
perspective of incentivizing cost control and efficiency. In
the hypothetical example of reaching a PTV of $300 per barrel,
the marginal tax rate under ACES would reach 100 percent and at
even higher prices could go above 100 percent, and more than 100
percent government support for spending, although that is not a
major concern at the moment or in the near future.
5:43:02 PM
CO-CHAIR FEIGE inquired what a PTV of $92.50 equates to for the
sales price on North Slope crude.
MR. MAYER responded it would be an oil price of $120, assuming
$30 per barrel in costs; therefore it would be territory the
state has seen recently.
5:43:31 PM
REPRESENTATIVE SEATON remarked this would be a big stimulation
to increase investment because the state is paying most of the
cost, but it would be a very high marginal rate if a producer
does not invest.
MR. MAYER agreed this is one way to look at it, but cautioned
against looking at it that way because it is an incentive in
general to spend money or not to put a lot of effort into saving
money. The distinction between that and investing is that when
a producer looks to investing in Alaska for a large scale new
project, the producer is considering what it looks like over a
very broad range of prices and how it performs over the next 20-
30 years. Whereas a producer considering whether to resurface a
runway can base its decision on this year's cash flow, this
year's prices, and what the after-tax benefit of that decision
is to the producer this year. When running economics, a
producer first and foremost wants to know that the project on a
stand-alone basis makes sense within the regime and then maybe
the producer will also take into account the after tax cash flow
benefits of looking at it on an incremental basis.
5:45:15 PM
MR. MAYER, in response to Representative Tuck, confirmed that
the yellow line depicting the ACES marginal rate on slide 10
does not factor in any of the credits.
5:45:29 PM
MR. MAYER returned to his comparison of the marginal and average
rates on slide 10, pointing out that the marginal tax rate under
CSSB 21(FIN) am(efd fld) is a steady flat 35 percent, never
changing and never deviating from the base rate, unlike the
steeply rising rate of ACES. When the $5 per barrel allowance
is taken into account, there is a downward curve of the tax rate
[at lower PTVs]. Where ACES sets the average rate and gets
spikes in the marginal rate that correspond to that, CSSB
21(FIN) am(efd fld) sets the marginal rate and that rate is 35
percent. Under the Senate bill, the very first dollar of value
has the $5 credit/allowance applied to it and from that point on
each marginal dollar of value is being taxed at the 35 percent
marginal rate, bringing up the average and resulting in the
progressive slope depicted on the graph, rather than the spikes
of up to 80 percent as happens under ACES.
5:46:38 PM
MR. MAYER turned to discussing the ACES tax regime in a base
production portfolio [slide 11]. Drawing attention to the upper
left graph, he said the regime's profit-based production tax
consumes a progressively larger amount of the pie as the price
per barrel increases, rising to 75 percent and above at the
upper price levels. Turning to the upper right graph, he looked
at the split of net present value of production between the
state, the federal government, and the company. At around $70
West Coast ANS price - the point at which progressivity kicks in
after costs have been netted away - the value of the project as
a whole to the State of Alaska starts to rise dramatically (blue
line) while the value to the company starts to flatten out
(yellow line). So, relatively speaking, for each incremental
increase in oil price there is less benefit to the company and
the vast majority of the increased value is captured by the
state under the progressivity under ACES. Correspondingly,
there are only small increases, relatively speaking, in project
value in terms of net present value per barrel of oil equivalent
(boe) as price levels rise.
5:48:23 PM
MR. MAYER, in response to Co-Chair Saddler about the upper right
graph, pointed out that the state's split (blue line) pulls away
from the company's split (yellow line) and the federal
government's split (red line). This is because progressivity
under ACES takes the lion's share of the net present value at
higher price levels as compared to the company. Responding
further, he clarified the dollar sum is in millions, so [25,000]
represents $25 billion in net present value of a future
production stream of base production. But, he added, it is more
useful to think about proportion than the absolute numbers.
5:49:31 PM
MR. MAYER then discussed, for comparison, the tax regime in a
base production portfolio under CSSB 21(FIN) am(efd fld) [slide
12]. [Drawing attention to the upper left graph], he said the
Senate bill has an overall flat, neutral, roughly 65 percent
level of government take across a broad range of prices. The
mild implicit progressivity created by the $5 per barrel credit
counteracts the regressive element of the royalty to create that
overall neutrality. Drawing attention to the upper right graph,
he pointed out the relatively even split of net present value
between state government, federal government, and the company
across all the different price levels. The state still takes
the lion's share compared to the other two, but overall it is a
much more even balance. Correspondingly, there is a higher net
present value per barrel for the base production portfolio.
5:50:38 PM
MR. MAYER, in response to Representative P. Wilson about the
lower left graph, explained that ATCF stands for after tax cash
flow. The green color within the bars represents all the
revenues received and the colors below $0 represent all the
costs incurred - government take and capital, operating, and
drilling costs. Essentially, the after tax cash flow line is
the balance of the positive and negative.
5:51:17 PM
REPRESENTATIVE SEATON surmised the graphs on slides 11-12 are
inflated at 2.5 percent through the year 2037 and a per barrel
price of $185.
MR. MAYER answered correct. He added that all the analysis PFC
Energy has presented to the legislature, in the two years he has
been presenting as well as previously, has always used some sort
of inflation assumption, usually 2.5 percent.
5:51:55 PM
REPRESENTATIVE TARR observed the after tax cash flow for CSSB
21(FIN) am(efd fld) [slide 12] does not look much different than
the ATCF for ACES [slide 11]. She requested further discussion
in this regard, given that is the part that the state is really
trying to get to if it wants companies to invest.
MR. MAYER replied there is a substantial jump in that ATCF line,
which he demonstrated by scrolling from one slide to the other.
To quantify this difference he drew attention to the bottom
right graph on each slide, noting the per barrel cash margin for
a 5-year window at a price of $120 per barrel is $27 under ACES
versus $36 under CSSB 21(FIN) am(efd fld).
5:53:12 PM
REPRESENTATIVE SEATON asked whether the aforementioned 5-year
window is the years 2012-2017.
MR. MAYER responded the 5-year window is the years 2017-2022.
If looking just at base production, he explained, there would be
no reason not to look at 2012-2017. However, since a new
development is also being included, the idea is to take a look
after the majority of the capital has been spent because one
would get a big difference between the early years when the
capital is being spent and the later years when harvesting cash.
So, the idea is to look at one reference period after the big
lump of capital has been spent to see how much the producer gets
to keep during the cash accretion portion of the project.
5:53:56 PM
REPRESENTATIVE SEATON surmised, then, that the price assumption
is $113-$120 per barrel.
MR. MAYER answered that, in nominal terms, he would have to look
it up. There are two ways to build a model, he elaborated, and
both achieve the same thing. One way is to run a model in real
terms where the oil price and the costs remain constant. For
example, this type of model could be used to look at a fixed
royalty regime in the Lower 48 that does not have any price-
dependent components. As long as a stable discount rate is used
for comparison those results are comparable with anything.
However, the ACES regime has price-dependent elements, meaning
inflation must be included in the model because the threshold at
which progressivity and other elements kick in is going to
change in real terms. Rather than trying to figure out what
those thresholds are, it is easier to do the standard type of
modeling which has everything in the model on a nominal basis.
An inflation rate of 2.5 percent is assumed and that occurs on
the revenue side rather than on the question of where the
brackets of progressivity kick in.
5:55:39 PM
REPRESENTATIVE SEATON said he is asking this because "we have
these cash margin assumptions and yet we have in other reports
from oil companies, cash margins, their worldwide assumptions,
and all, and if we do not know how we are comparing because we
are talking about $165 a barrel oil compared to their cash
margins at a particular time, it makes it very difficult to make
those comparisons. So that is why I am trying to understand if
we have inflated these; then it would appear that Alaskan oil is
far more profitable than ... their margin worldwide .... In
those shorter time periods, shorter year periods, it does not
seem to be as big an effect on that."
5:56:35 PM
MR. MAYER resumed his presentation, addressing the impact of the
gross revenue exclusion [slide 13]. He pointed out that the
slide in the committee's packets shows a GRE of 30 percent,
rather than 20 percent, which he has corrected in the on-screen
slide. For purposes of this exercise, he continued, it is not
the absolute numbers that are of concern but rather the question
of what the GRE does. The answer is the GRE simply shifts the
overall curve so that the point at which "progressivity" kicks
in is moved out. Slide 13 repeats the calculations of [slide
9], he explained, but adds in a GRE. At a price of $60 per
barrel and no GRE, the effective tax rate after application of
the $5 per barrel allowance is 10 percent; when a 20 percent GRE
is factored in, the effective tax rate is lowered to no tax. At
a price of $80 per barrel the effective tax rate with the GRE is
4.1 percent [22.5 percent with no GRE], at $120 per barrel the
effective tax rate with the GRE is 14.3 percent [28.8 percent
with no GRE], and at $140 per barrel the effective tax rate with
the GRE is 16.4 percent [30 percent with no GRE]. Thus, in each
case, applying the GRE results in a substantial reduction in the
tax rate and, essentially, a shifting of the point at which the
production tax starts to kick in.
5:58:12 PM
MR. MAYER then looked at a scenario of new development at a cost
of $18 per barrel on a stand-alone basis under ACES [slide 14].
Drawing attention to the lower left graph, he pointed out that
negative cash flows go along with a new development in its early
years. This negative cash flow is the result of expenditures
for facilities (yellow color in the bars) and drilling (blue
color). Once production starts, operating costs (red color) and
government take (purple color) begin to occur. In the early
stages of development, the positive impact of the ACES credits
can be seen (purple bars projecting upward), which reduce the
initial cost to the developer. The green bars depict revenue
from the project. Continuing, he said the upper left chart
shows the overall high level of government take that comes from
the substantial progressivity in ACES, which rises to nearly 80
percent as prices [reach $160 per barrel]. Drawing attention to
the upper right graph, he noted the substantial diversion in
value of the project to the state versus value to the company.
5:59:49 PM
The committee took an at-ease from 5:59 p.m. to 6:08 p.m.
6:08:44 PM
MR. MAYER next looked at this same scenario of new development,
but under CSSB 21(FIN) am(efd fld) [slide 15, top left graph].
Government take is much lower, he said, going down to a flat
level of just below 61 percent over a broad range of prices
because of the GRE. The GRE reduces the overall level of the
tax and pushes out the price point at which production tax
starts to occur to $65. When combined with a net operating
loss, this can mean that at low prices the production tax is
negative. Drawing attention to the bar for $50 per barrel, he
noted that the production tax is located above federal and state
income tax rather than beneath them as is the case for the other
prices. "The top of that bar is the top of where the royalty by
itself comes to and the blue is, in this case, the production
tax taking down the total level of government take to 70-
something percent rather than the 90-something percent that you
would have had from the royalty alone. That is effectively
negative contribution from the production tax at the lowest
price level."
6:10:17 PM
MR. MAYER, in response to Co-Chair Feige, clarified that at a
West Coast ANS price of $50 per barrel, the top of the bar is at
90 percent because if it were just royalty with federal and
state income tax, the government take would reach 90 percent.
However, in this price case of $50 per barrel, the way to
interpret the production tax (light blue color) is that the
production tax is negative, thereby lowering the government take
from 90 percent to about 73 percent.
6:11:26 PM
MR. MAYER continued, reiterating that at low prices the
combination of the GRE with the net operating loss credit can
result in a negative tax exposure to the state. He noted,
however, that in general it is a much smaller liability than
what the state has under the existing system of ACES where all
production accrues to capital credit. Under CSSB 21(FIN) am(efd
fld) this only occurs in circumstances where there is new
development with the gross revenue exclusion, which will be a
very small portion of production in the coming years.
6:12:11 PM
MR. MAYER moved to the cash flow chart at the bottom left of
slide 15, pointing out there would still be a "negative
contribution of government take in the early years" which, under
CSSB 21(FIN) am(efd fld), come in the form of the net operating
loss credits. These credits are smaller than the contribution
that comes under ACES. Under the Senate bill, the state's
support for spending is 35 percent through the net operating
loss credit rather than the 45 percent level of support on a
stand-alone basis under ACES; for an incumbent producer under
ACES the support is much higher than 45 percent.
6:13:04 PM
REPRESENTATIVE SEATON calculated the differential under the GRE
is about 17 percent. Regarding Mr. Mayer's statement that not
much of the oil now or in the near future would be under the
GRE, he pointed out that if the state is trying to do something
for a long term then almost all of the oil eventually is going
to be under this GRE. He asked, therefore, whether it makes
sense to have a provision that could be a huge negative at low
prices and when the value of the royalty would also be low.
MR. MAYER replied his view is that it is a trade-off of a number
of things. It is a smaller negative liability than the state
currently has under the capital credits of ACES. Both the GRE
and the ability to monetize the net operating loss come back to
a question of balance in the system and wanting to achieve the
same economics for a small producer as for an incumbent. In his
opinion, that cannot be done without having an operating loss
allowance. He said he thinks this trade-off is an effective one
because the capital credits are gone while not eliminating the
liability entirely because one also wants to maintain strong
economics for new producers and give them the same opportunities
that an incumbent producer has.
6:14:51 PM
REPRESENTATIVE SEATON, directing attention to slide 14, observed
that [the top left graph] shows the [government take] under ACES
as being down to only 75 percent [at a price of $50 per barrel].
So, he concluded, the ACES reduction on capital credits are less
of a liability for the state than the liability under [CSSB
21(FIN) am(efd fld)]. He inquired whether the reduction [under
the Senate bill] is mostly the GRE.
MR. MAYER answered it is the impact of the 20 percent GRE in
conjunction with the net operating loss credit.
REPRESENTATIVE SEATON requested that as the analysis moves
forward the committee look at a way to limit downside liability
from the GRE at low prices, such as a limitation at certain
prices on gross revenue exclusion. If the state builds a long-
term system that over time has more and more percentage of oil
qualifying for the gross revenue exclusion, he opined, it will
have even more liability and will have to take money out of
royalties to pay for that GRE.
CO-CHAIR FEIGE replied "fair enough."
6:16:38 PM
REPRESENTATIVE TUCK drew attention to the effects of the GRE
shown on slide 13 and surmised the GRE is regressive rather than
a reverse progressivity because as prices go up the more tax is
reduced.
MR. MAYER, shaking his head no, said it is almost entirely the
$5 per barrel allowance that does this. The reduction in tax is
still by far the greatest at the lowest prices, he continued.
The GRE slightly overall reduces the level of tax and it pushes
the curve out a bit farther so that at a price of $60 per barrel
there is no tax liability.
REPRESENTATIVE TUCK understood, then, it is the $5 per barrel
allowance that gives more back at lower prices.
MR. MAYER responded "exactly."
REPRESENTATIVE TUCK further understood the GRE does the opposite
as prices go up - it gives more back as the price goes up.
MR. MAYER confirmed that is the case compared to the $5 per
barrel exclusion, but in absolute terms he said he would need to
check the numbers.
6:18:54 PM
MR. MAYER resumed his presentation, turning to discussion of the
net operating loss credit and sunset of the exploration and
small producer credit [slide 16]. Recounting its progress
through the Senate, he said the original bill had a sunset date
of 2022 for the exploration and small producer credit. Removing
the ability of small producers to stack credits, which can
result in 75 percent effective support of spending for
exploration, limits the overall level of government support for
exploration spending to a sensible amount and makes government
support equal between a new company with no existing tax
liability and an incumbent. Whatever that level of government
support is, it is his opinion that the state would want to be
equal between a new company with no existing tax liability and
an incumbent.
6:21:03 PM
MR. MAYER said a nice thing about how this all works out - the
higher rate with the higher corresponding net operating loss -
is that even though the capital credits have been taken out and
the exploration credit is sunset, people will still have 35
percent government support for exploration spending because the
net operating loss credit can be monetized. A complicated lever
is being taken out of legislation to get to a simpler system
that is completely even in its impacts. Whether for an existing
producer or someone with no tax liability, the impact is an even
35 percent in government support for exploration spending and
the bill is much simpler. By doing this, that flat low marginal
rate is maintained to create a strong incentive for efficiencies
and for cost control. Exposure to the state from higher cost
projects at lower prices is limited, relatively speaking, by not
having the capital credits. Additionally, the overall level of
government support for exploration spending is evened out.
MR. MAYER added there may be specific instances in which the
administration wants to go beyond 35 percent government support.
For instance, when there are particular known prospects that it
is strongly in the state's interest to see drilled for
information purposes as much as anything else. Mechanisms for
accomplishing this can be talked about at a later point by the
administration. He offered his opinion that it makes a lot of
sense to have the same level of support for new companies as for
incumbent ones and to have it capped at 35 percent overall
support for exploration rather than the current 70-90 percent
effective government support under ACES.
6:23:05 PM
MR. MAYER, in response to Representative Seaton, confirmed that
the bill currently before the committee, CSSB 21(FIN) am(efd
fld), does not have any credits that can be stacked because it
has only the 35 percent net operating loss credit. The current
bill still has the exploration credit, he continued, but that
sunsets in 2016. So, once that exploration credit is gone there
will only be the 35 percent net operating loss credit.
REPRESENTATIVE SEATON understood that between now and 2016 the
exploration credit will be available to both producers and
explorers.
MR. MAYER answered correct. Given people may have commitments
and other things already made on that basis, and given that it
is a short timeframe, it seems easier to let them expire as they
are already slated to do rather than to take them away for the
benefit of a year.
CO-CHAIR FEIGE, responding to Representative Seaton, noted that
the "Middle Earth" credits under "025 (n), (m), and (o)" are not
stackable, a company must take one or the other.
6:25:01 PM
MR. MAYER concluded his presentation [slides 16-18], stating
that CSSB 21(FIN) am(efd fld): provides overall neutrality at a
competitive level of government take; improves competitiveness
for new projects via the GRE; reduces, although does not
eliminate, the downside risk to the state from credits; provides
an overall balanced system with even impacts for both incumbents
and new producers; incentivizes producer efficiency through a
neutral regime with low and constant marginal rates;
substantially simplifies the fiscal system; and moves Alaska
into the realm of serious competitiveness with other regimes for
international capital.
6:26:02 PM
REPRESENTATIVE TARR requested Mr. Mayer to provide the internal
rate of return [for the bottom right graphs] on slides 11-12.
MR. MAYER answered no, explaining internal rate of return is a
concept that relies on initial capital spending with subsequent
cash flow that comes from that. Slides 11-12 look at the base
production portfolio where there is no initial spending and
subsequent cash and therefore an internal rate of return cannot
be gotten because it is undefined.
6:26:44 PM
REPRESENTATIVE SEATON drew attention to slide 3 and the gross
revenue exclusion (GRE) of 20 percent for oil from new
participating areas (PAs), PA expansions, and areas in legacy
fields not previously contributing to production. He recounted
that at the February 28, [2013], meeting of ConocoPhillips and
during a trip to the North Slope, it was discussed that Alaska
is a place where it is very hard to develop and produce every
last barrel, but ways have now been developed to economically
produce pockets of oil that were once uneconomic. He therefore
inquired why the state should give gross revenue exclusions to
things that are more economic than conventional drilling. He
further asked why, from a legislative aspect, members should not
listen to the producers' testimony.
6:28:59 PM
MR. MAYER, displaying slide 18, replied there is some degree of
trade-off between how far one is comfortable going in reducing
government take overall and where one wants to be in terms of
incentivizing new production. He said CSSB 21(FIN) am(efd fld)
takes Alaska to the upper end of that realm of competitiveness,
but is far from radical or aggressive in how far it goes. The
gross revenue exclusion is a way of saying the state recognizes
that to be truly competitive across a broad range of new
developments it would like to be a little bit lower than this.
What the gross revenue exclusion should apply to is then the
next question. New units and new producing areas are fairly
straightforward and, in his opinion, so are expansions of
existing areas. Thus, the remaining area in question is the
legacy fields, given it is known that the greatest resources
could be produced from these fields, particularly in the next
five to six years. Is there a way of incentivizing the legacy
fields and what is the trade-off of reducing government take on
things that in some cases many not need a lower rate but also
wanting to ensure the state has a competitive rate for things
that do? The tax code is not necessarily the sharpest
instrument for doing that, and probably is the bluntest. The
Department of Natural Resources has the expertise to make a call
as to whether a portion of a reservoir is or is not currently
contributing to production and on the basis of the department's
determination something could then qualify for the gross revenue
exclusion. If the largest volume of potential new resources is
in the legacy fields and one really wants to get to a truly
competitive rate to encourage as much activity as possible, then
it makes sense to apply some form of gross revenue exclusion to
those. It is a trade-off between a number of things, including
how far one is willing to go on the base rate.
6:32:21 PM
REPRESENTATIVE SEATON stated he has a problem with throwing this
into an administrative procedure to determine whether something
is or is not new. He predicted a gross revenue exclusion will
be requested for every single thing that requires a drill or
enhanced production such as coil tubing and laterals,
consequently resulting in a multitude of court challenges. He
said he would like further analysis as to how difficult it is
going to be to throw this into the realm of administration. He
offered his belief the Senate overreached when it provided that
new oil does not have to be a new reservoir or new producing
area or a new unit.
CO-CHAIR FEIGE said there are two issues as far as what is
considered new oil - oil that may not necessarily get produced
given the ACES tax regime, or new oil that can be produced given
the economics of CSSB 21(FIN) am(efd fld). There are two coiled
tubing rigs on the North Slope, and one of them is stacked. So,
they can only drill holes so fast. He offered his opinion that
if the state improves the economics it will lead to more coiled
tubing rigs drilling more holes and more holes will lead to more
oil in the Trans-Alaska Pipeline System.
6:35:18 PM
REPRESENTATIVE SEATON, in regard to improving the economics,
argued that "we're not talking about having to build new
production facilities, we're not having to do new piping, we're
not having to do transit pipes ... and when we give a gross
revenue exclusion to those that don't require much investment,
at least according to the testimony ... of ConocoPhillips at
their analyst meeting ... we have to presume they are not lying
to their investors. It seems like extending that to existing
... participating areas that are already drilled, that are
already producing, and that they're simply fault blocks and
those kind of things which this more economical method is to
access, further lowering that government take is questionable."
CO-CHAIR FEIGE said the committee can have the Division of Oil &
Gas testify as to how well it can determine whether that is the
case. The question is how to define new oil and whether new oil
will be taxed differently than legacy oil. He said CSSB 21(FIN)
am(efd fld) makes a significant improvement in getting Alaska
into the zone of being more competitive. The question for this
committee is whether that is competitive enough to lead to the
development that is needed to level off or increase production.
6:37:29 PM
REPRESENTATIVE SEATON, in response to Co-Chair Saddler, agreed
to share the information that generated his questions of today.
6:37:45 PM
REPRESENTATIVE TARR returned to her question about internal rate
of return on slides 11-12 and asked for further elaboration.
MR. MAYER replied in those slides that are base production there
is capital being spent but it is being spent at the same time as
there is production, so there is never a period of negative cash
flow.
6:38:13 PM
REPRESENTATIVE TARR, referring to slide 18, offered her
understanding that Alaska's lease expenditures are quite a bit
lower than in the Lower 48. She surmised, however, that that
would not be reflected as a part of government take in the Lower
48 because of the private landholder situation there. Since
slide 18 only looks at government take, she asked whether there
is a way to evaluate some of those other expenditures in terms
of overall competitiveness.
MR. MAYER responded Econ One did well in terms of looking at a
range of economic metrics. It ultimately comes back to net
present value and how other things compare between these regimes
and others. He agreed to provide other comparisons, concurring
that it is not just about government take, but also cost and
other things. By and large, he said, costs in Alaska tend to be
higher rather than lower and they hurt rather than hinder the
competitiveness question.
6:39:38 PM
REPRESENTATIVE SEATON, regarding the Gerking study of drilling
sensitivity to tax rates, inquired whether Mr. Mayer shares the
perspective that lowering the tax rates would lead to dis-
investment in new oil.
MR. MAYER answered, yes, he absolutely believes that drilling,
investment, and all those other things are responsive to tax
rates. He said he also agrees with Mr. Pulliam's reading of the
Gerking paper and the conclusions that Mr. Pulliam drew on that
basis. As to what he knows about the paper itself and the
soundness of its methodology, he said he only knows as much as
Mr. Pulliam, which, as was said, is limited to what can be told
from the paper itself because of not having the sources of the
data. The paper is one reasonableness test of how reasonable is
it to believe the state could, over an extended period of time,
make back the revenue that is foregone by doing this. As was
said by Mr. Pulliam, there are a number of tests of
reasonableness, but they are only tests and none of them is a
guarantee. Taken together, however, they indicate it is
reasonable to expect that it is possible even if not guaranteed.
6:41:21 PM
REPRESENTATIVE SEATON read from the conclusion of the Gerking
study, page 15, which states: "Results of this study suggest
that oil production is highly inelastic with respect to changes
in production taxes. ... Policy implications of this outcome
suggest that state officials may consider raising production tax
rates as a way to increase revenue while risking little in the
way of loss to future oil activity." Therefore, Representative
Seaton said, it seems the conclusion in this paper is exactly
the opposite of what is being proposed.
MR. MAYER replied he and Mr. Pulliam both came away from the
paper with the same conclusion, which is that the study's
authors drew their conclusion based on very, very small changes
in government take. In looking at the study data and the
sensitivity implied to drilling rather than just production, one
would expect that for the scale in government take [being talked
about for Alaska], there would actually be quite a significant
change in overall amount of drilling and investment.
6:43:27 PM
CO-CHAIR FEIGE drew attention to slide 18 and requested both Mr.
Pulliam and Mr. Mayer to each state their opinion on whether
CSSB 21(FIN) am(efd fld) would make Alaska competitive with
other regimes against which it competes.
MR. PULLIAM responded he thinks CSSB 21(FIN) am(efd fld) strikes
a good balance and would give Alaska a competitive system,
particularly with the GRE in place for new production. When
thinking about the investment metrics outlined on slide 11, and
opportunities in Alaska versus opportunities elsewhere, the
Senate bill would put Alaska projects in a good and favorable
spot. While the bill is not the best economics in the world, it
is solidly in the competitive range.
MR. MAYER agreed with Mr. Pulliam. Particularly with the GRE,
he said, CSSB 21(FIN) am(efd fld) would get Alaska to where it
needs to be in competitiveness for new production. Without the
GRE, the Senate bill would be in the competitive range, but at
the upper end of that range. There is a trade-off between how
far the state can go in forgone revenue to get to the heart of
the competitive level for existing production and this can be
achieved through the GRE. There is also a trade-off between
wanting to be as competitive as possible while also needing a
regime that is fiscally stable and secure over the next many
years. In making these decisions, one needs to absolutely look
at breakeven analyses while also remembering that it may take 10
years, if all goes well, before the state is back at the revenue
levels it would have been under ACES with no increased
production. There is a good several years before increased
production starts to take off some of the fiscal weight, and the
further one goes on the base production, the more that is the
case. So, given these things, he said it is his opinion that
CSSB 21(FIN) am(efd fld) is not a bad balance.
6:47:00 PM
MR. PULLIAM, in further response to Co-Chair Feige, said he
thinks that he and Mr. Mayer are in basic agreement on the bill,
particularly when looking at the economics of new development
where the GRE comes into place. He and Mr. Mayer are in
agreement that CSSB 21(FIN) am(efd fld) puts Alaska in a good
competitive position. The state would not be at the high end of
competiveness, but would be right in the middle.
6:47:38 PM
CO-CHAIR SADDLER inquired what Mr. Pulliam and Mr. Mayer, as
professionals in the petroleum economics field, see Alaska's
future being if the ACES tax structure is maintained for the
next 5 to 10 years.
MR. PULLIAM answered he thinks the state will see continued
declining production at rates higher than desired. And, like
this year, he thinks there will be more situations of budget
deficits. If that is the policy the state wants to pursue, then
legislators need to figure out how to save more than what the
state has been doing, he advised.
MR. MAYER replied the ability of ACES to continue generating
substantial revenues from declining production over the next
several years is dependent on high prices. The part of this
debate that puzzles him most, he said, "is when people look at
some of these charts and say 'oh but look at the revenue we
would be forgoing at $200 a barrel.' ... At $200 a barrel, the
State of Alaska has relatively little to worry about ... in any
of these regimes." If he was planning for the future fiscal
health of the state he would be much more concerned with what
any of these regimes look like between $70 and $90 a barrel
rather than $200. Not only does the bill get Alaska to a range
that is substantially more competitive, it does a good job of
protecting the state in lower price environments.
6:49:22 PM
REPRESENTATIVE TUCK surmised that both Mr. Pulliam and Mr. Mayer
believe CSSB 21(FIN) am(efd fld) better guarantees investments
in the state of Alaska in the future.
MR. MAYER nodded yes.
MR. PULLIAM responded it certainly creates a much stronger
probability of getting the kind of investment the state wants
than letting the current system stay in place.
6:49:54 PM
REPRESENTATIVE SEATON asked whether the legislature's consultant
will be available to members of the committee. He noted he has
twice requested to meet [with Mr. Mayer] and it has not
happened. He pointed out that, in the past, consultants have
had a room and members could make appointments to see them. He
requested this be done to avoid having to hash out every
question.
CO-CHAIR FEIGE agreed the request is valid and said he will look
into working something out since Mr. Mayer will be in Juneau all
week. He held over CSSB 21(FIN) am(efd fld).
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES SB21 EconOne Presentation 3.25.13.pdf |
HRES 3/25/2013 1:00:00 PM |
SB 21 |
| HRES SB21 PFC Energy 3.25.13.pdf |
HRES 3/25/2013 1:00:00 PM |
SB 21 |
| HRES SB21 EconOne Background Information.pdf |
HRES 3/25/2013 1:00:00 PM |
SB 21 |