Legislature(2013 - 2014)BARNES 124
04/02/2013 06:00 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
DRAFT
6:08:10 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." [Before the committee was the proposed committee
substitute, HCS CSSB 21, Version B, labeled HCS CSSB 21, 28-
GS1647\B, Nauman/Bullock, 3/29/13, adopted as the working
document on 3/29/13.]
6:08:17 PM
CO-CHAIR FEIGE informed the committee that due to issues with
the effective dates in Version B, a new committee substitute,
Version K, was prepared to merge the effective dates into the
sections of the bill. He advised that amendments submitted for
consideration should be redrafted to the K version.
6:09:17 PM
CO-CHAIR SADDLER moved to adopt HCS CSSB 21, Version 28-
GS1647\K, Nauman/Bullock, 4/2/13, as the working document.
There being no objection, Version K was before the committee.
6:09:44 PM
The committee took an at-ease from 6:09 p.m. to 6:22 p.m.
6:22:28 PM
JANAK MAYER, Manager, Upstream and Gas, PFC Energy, as
consultant to the legislature, said he will discuss the two
significant changes to CSSB 21(FIN) am(efd fld) that are made in
the proposed committee substitute, HCS CSSB 21, Version K, that
affect the North Slope fiscal system. The first change is in
the forms of new production that would qualify for the gross
revenue exclusion (GRE), now being called the gross value
reduction (GVR). The second change is the treatment of the per
barrel credit. New production that qualifies for the GVR would
maintain the fixed $5 per barrel production credit. Production
not qualifying for the GVR - which is production that is not
from a new unit, a new participating area, or an expansion of an
existing participating area, and thus, essentially, the base
legacy field production - would have a stepped per barrel credit
that is at a higher rate when oil prices are low and that is
reduced to zero when oil prices are high.
6:24:26 PM
MR. MAYER demonstrated how a fixed $5 per barrel production
credit would work using a scenario of 50 million barrels of
taxable production at Alaska North Slope (ANS) West Coast prices
ranging from $60-$160 per barrel, with transportation costs of
$10 per barrel [slide 2]. He described the fixed $5 per barrel
production credit as being like a mild form of reverse
progressivity - instead of going from a fixed base and building
up, it decreases from a fixed top level. He reviewed the
calculations on slide 2 for the price of $60 per barrel: at a
transportation cost of $10, the gross value at the point of
production (GVPP) is $2.5 billion; after subtracting lease
expenditures [of $1.5 billion], the production tax value (PTV)
is $1 billion; application of the 35 percent production tax
results in a tax liability of $350 million; applying the $5 per
barrel production allowance to the 50 million barrels of
production results in a total allowance of $250 million;
subtracting $250 million from $350 million results in a
production tax of $100 million. Thus, the tax rate after the
allowance is 10 percent rather than the nominal 35 percent, a
reduction of 25 percent. As prices increase, that tax reduction
steadily decreases. For example, at a price of $140, the tax
rate after the allowance is 30 percent rather than the nominal
35 percent, a reduction of only 5 percent. As prices keep
increasing, the tax rate keeps rising until asymptotically it
approaches 35 percent, but never quite reaches 35 percent.
6:27:25 PM
MR. MAYER, responding to Representative Seaton, explained that
on slide 2 the line for the GVR/GRE is blank, indicating its
functions are working but at a 0 percent rate. Thus, it is not
applying in this example and is not reducing anything from the
overall tax; however, it will apply in a later example. In
further response, he confirmed the difference in the tax
percentage rate is totally from the $5 per barrel credit.
6:28:23 PM
MR. MAYER, at Representative P. Wilson's request, repeated his
review of the calculations on slide 2 for 50 million barrels of
production at the ANS West Coast price of $60 per barrel: from
that $60, subtract $10 in transportation cost to arrive at $50
in gross value at the point of production per barrel; multiply
that $50 by the 50 million barrels of taxable production to
arrive at $2.5 billion in gross value at the point of production
(GVPP); multiply the lease expenditures of $30 a barrel times
the 50 million barrels of taxable production to get a total
lease expenditure of $1.5 billion; subtract the $1.5 billion in
total lease expenditure from the $2.5 billion in GVPP to arrive
at a total production tax value (PTV) of $1 billion (i.e. a per
barrel PTV of $20); taxed at 35 percent, the tax liability is
$350 million without any other deductions or exclusions; there
is no GVR/GRE in this example; multiply the fixed $5 per barrel
credit times 50 million barrels to arrive at $250 million in
credit; subtract that $250 million of credit from the $350
million of tax liability to arrive at a production tax of $100
million. That $100 million represents 10 percent of the $1
billion in production tax value, for an effective tax rate of 10
percent after the $5 per barrel credit, rather than the nominal
35 percent.
6:33:09 PM
MR. MAYER, in further response to Representative P. Wilson,
explained 35 percent is the nominal tax rate under Version K.
So, at $60 per barrel, the production tax without allowance on
the $1 billion in production tax value is $350 million. The $5
per barrel credit provides a total production allowance of $250
million. Subtracting the allowance of $250 million from the
$350 million leaves a production tax of $100 million. That $100
million represents 10 percent, rather than 35 percent, of the
[$1 billion] in production tax value, a reduction of 25 percent.
MR. MAYER reiterated that this is a mild reverse progressive
effect, where the lower the price the lower the rate and the
rate comes down in a curve. The shape of the curve is just
enough to counteract the regressive nature of the royalty that
is also in the state's fiscal system, thereby giving an overall
flat, neutral level of government take.
6:34:51 PM
MR. MAYER next demonstrated how a variable production credit
would work, as proposed in Version K [slide 3]. He again used a
scenario of 50 million barrels of taxable production at ANS West
Coast prices ranging from $60-$160 per barrel, with
transportation costs of $10 per barrel. At prices of $60, $70,
and $80, the per-barrel credit is $8 rather than $5. At a price
of $90 the credit is $7 per barrel, going down by $1 per barrel
for each $10 increase in price until reaching no credit at the
price of $160. At a price of $60: the production tax without
any allowance would be $350 million, representing 35 percent of
the $1 billion in production tax value; with a credit of $8 per
barrel, the total production allowance is $400 million, which is
greater than the $350 million in production tax liability. It
is explicitly stated that the allowance cannot take a taxpayer
below zero, so there is no production tax in this case, as
compared to an effective tax rate of 10 percent for the $5 per
barrel credit. At a price of $70 per barrel: the production
tax without any allowances is $525 million; with a credit of $8
per barrel, the production allowance is $400 million; resulting
in a production tax of $125 million, representing an effective
tax rate of 8.3 percent, as compared to an effective tax rate of
18.3 percent for the $5 per barrel credit.
MR. MAYER pointed out that at a price of $110 the variable
production credit is $5, so the effective tax rate of 27.9
percent is the same as it is for the fixed credit at this price.
Under the variable production credit, the progressive nature of
the effective tax rate is increased from that of the fixed rate
- more comes off at prices below $110 and above $110 the
effective tax rate is higher. Because the variable credit is
zero at the price of $160, the effective tax rate no longer
asymptotically approaches 35 percent - it actually gets to 35
percent at this price and, therefore, the effective rate is the
nominal rate of 35 percent. For production that does not
qualify for the GVR/GRE, the effective tax rate is higher at
higher prices and lower at lower prices.
6:39:26 PM
MR. MAYER then drew attention to the effective tax rates that
apply to new production [slide 4], explaining that under Version
K the definition of new production is narrower - only production
from new units, new participating areas, and expansions to
existing participating areas. This new production would receive
a fixed $5 per barrel credit, rather than a variable/stepped
credit, and would qualify to receive the 20 percent GVR/GRE.
MR. MAYER, responding to Representative P. Wilson, confirmed
that at a price of $60 per barrel the effective tax rate after
the per-barrel allowance and the GVR is 0 percent, so a producer
would pay no production tax. In further response, he noted that
a producer would still contribute other forms of tax, such as
royalty, property tax, state income tax, and federal income tax.
Because of the regressive nature of the royalty, he explained, a
producer may well face still a relatively high level of
government take. Responding further, he noted the nominal tax
rate of 35 percent is reduced by 35 percent for an effective
production tax rate of 0 percent.
REPRESENTATIVE P. WILSON returned to slide 3, which depicts a
variable production credit and no GVR, and observed that at a
price of $70 per barrel the nominal tax rate is 35 percent, the
effective tax rate after allowance is 8.3 percent, for a
progressive tax rate deduction of 26.7 percent.
MR. MAYER confirmed this is correct.
6:43:58 PM
MR. MAYER turned back to slide 4, which depicts new production
at the fixed $5 per barrel credit and the 20 percent GVR for a
scenario of 50 million barrels of taxable production. In
response to Representative P. Wilson, he said the fixed $5 per
barrel credit is the line entitled "Production Allowance/bbl".
The line entitled "GRE" shows the gross value reduction (GVR)
[formerly called the gross revenue exclusion (GRE)], which is 20
percent of the gross value at point of production. In the
previous slides the GVR/GRE was zero because the GVR/GRE did not
apply to those forms of production.
6:45:12 PM
MR. MAYER continued his presentation, reviewing the calculations
for a price of $60 per barrel: $2.5 billion in gross value at
point of production minus $1.5 billion in lease expenditures
equals a production tax value of $1 billion, for a tax liability
of $350 million; factoring in the 20 percent GVR/GRE [$500
million] drops the production tax value to $500 million; a 35
percent tax on $500 million equals a production tax liability
without allowance of $175 million. The $5 per barrel credit,
which totals $250 million, is more than the tax liability of
$175 million. Thus, at a price of $60 with the GVR/GRE and $5
per barrel fixed credit, the effective production tax rate is 0
percent. Comparing the overall rates on slide 4 to those on
slide 3, it can be seen that in all cases the GVR/GRE combined
with the fixed $5 per barrel credit gives lower tax rates for
new production than for production with the stepped-function
credit and no GVR/GRE.
6:47:07 PM
MR. MAYER suggested a linear function for the variable credit
may be preferable to the currently proposed step function [slide
5]. Under the step function the per-barrel credit goes down $1
for each $10 rise in price [in a scenario of $10 per barrel
transportation cost]. This means the marginal rate is, in
general, a flat 35 percent, but every time one of those steps is
hit, that marginal rate spikes up to about 135 percent at that
exact $1 increment before coming back down to 35 percent.
Instead of writing this as a step function, it could be written
as a single linear formula. So, instead of this staircase,
there would be a smooth line that determines exactly what the
credit is at any point along that line. Rather than a series of
thresholds at which a particular rate applies, it could be
written that the credit is $16 minus one-tenth of the gross
value of production, and that it cannot exceed $8 or go below
$0.
6:49:01 PM
MR. MAYER compared the overall government take and economic
metrics for base production between the state's current tax
structure of Alaska's Clear and Equitable Share (ACES), CSSB
21(FIN) am(efd fld), and the proposed committee substitute, HCS
CSSB 21, Version K, [slides 6-8]. Under ACES [slide 6, top left
graph], progressivity results in government take increasing to
over 75 percent at a price of $140. As oil prices rise, the
state's share of total net present value of production diverges
upward, while the company's share rises only relatively little
[slide 6, top right graph]. Under CSSB 21(FIN) am(efd fld)
[slide 7, top left graph], the degree of progressiveness in the
fixed $5 per barrel credit is just enough to offset the
regressive nature of the royalty, resulting in an overall
neutral structure at just a little under 65 percent government
take. As oil prices rise, the state's share of total net
present value of production is greater than that of the
company's share, but the two shares are more evenly split than
is seen under ACES [slide 7, top right graph]. Under the
variable production credit of Version K [slide 8, top left
graph], the production tax has a substantially more progressive
slope. The effect of that is a bending down of the line for
overall government take, rather than it being a flat line just
below 65 percent. At $80 a barrel, government take gets down to
63 percent, and even a little lower at lower prices, and at
price levels above $100 the government take gets as high as 67
percent. In the previous slides, it was seen that at about $60
a barrel, there was little or no production tax, depending on
the cost assumptions. Under Version K, using the base producer
assumptions, there is no production tax liability at $55, there
is a slight production tax at $60, and a steady increase from
that point.
6:52:16 PM
MR. MAYER, responding to Representative P. Wilson, said the
dotted line in the lower left graph on slide 8 is the after tax
cash flow (ATCF). It represents the difference between all the
revenues from production (the positive green bars in the graph)
versus all the costs, including government take (negative bars
in various colors). This difference is the dotted line, which
is the after tax cash flow that the producer receives.
MR. MAYER, responding to Representative Tuck, confirmed the
federal tax rate is 35 percent on slide 8, but said a number of
tax shields available at a project level are factored in, such
as being able to expense intangible drilling tasks. There is no
treatment of any other federal rate effective reductions that
might come through corporate shielding of income. Because it is
the project and the project economics that are being looked at,
it makes sense to look at the tax rate that applies to the
project.
REPRESENTATIVE TUCK recalled an article that reported "Exxon"
only paid 10 percent to the federal government last year because
it shielded its income from offshore. He understood [slide 8]
would not factor that in because the slide is just by project.
He inquired whether state taxes are deducted from the federal
taxes in the graphs on slide 8.
MR. MAYER confirmed they are deducted.
6:54:04 PM
MR. MAYER continued his presentation, pointing out that Version
K has a lower level of government take at a price of $80 per
barrel [62.94 percent] than CSSB 21(FIN) am(efd fld) [64.22
percent, slide 7]. At higher prices Version K has a higher
level of government take; for example, at $100, government take
is 65.26 percent under Version K and 64.54 percent under CSSB
21(FIN) am(efd fld). At $110 there is parity in terms of the $5
per barrel credit, he said, so it would seem there should be
"exactly the same level of government take at $110 and less
below that." However, the answer to that comes back to the
question of inflation. Moving to slide 9, he noted the time
series at the top of the chart is the same time series that was
used to generate the cash flow charts on slides 6, 7, and 8 ...
6:55:28 PM
MR. MAYER, in response to Co-Chair Saddler, confirmed that the
labels on the left side of the slide 9 chart are in dollars for
the ANS West Coast price per barrel, the transportation cost per
barrel, and the gross value at the point of production per
barrel. Returning to his overview of slide 9, Mr. Mayer
explained why government take is higher at $100 per barrel
[under Version K than under CSSB 21(FIN) am(efd fld)]. At a
price of $100, less $9 per barrel in transportation cost, the
gross value at point of production is $91 per barrel, which
qualifies for a credit of $6 per barrel. To hold the ANS West
Coast price constant at $91 as time goes on, it is raised by 2.5
percent inflation [per year]. The Trans-Alaska Pipeline System
(TAPS) tariff is raised by 3.5 percent a year to be consistent
with what has been seen in the past. The gross value at point
of production rises accordingly, so in nominal dollars it rises
from $91 in 2012 to $93.18 in 2013, and so on. The credit of $6
per barrel applies [for years 2012-2015], falling to $5 [for
years 2016-2020], and continuing to fall over the years until
the year 2034 when there is no per-barrel credit at all. The
credit becomes zero because the gross value at point of
production has risen in nominal terms even though in real terms
it is still - in 2012 dollars - $100 oil. Inflation results in
the value of the credit being eroded over time in both real and
nominal terms. In nominal terms the credit itself actually gets
smaller year after year. "The reason for that is it is actually
this series of credits at $100 a barrel that is being used in
that previous result and is why what we see is actually slightly
higher government take at $100 a barrel across the lifecycle of
a project or, in this case, across the lifecycle of the base
production, rather than slightly lower government take."
6:58:17 PM
MR. MAYER, responding to Representative Tuck, clarified
government take at $100 per barrel is higher in Version K as
compared to CSSB 21(FIN) am (efd fld). Where CSSB 21(FIN)
am(efd fld) has a steady credit of $5 per barrel, Version K has
a couple of years at $6, five years at $5, and a lower credit in
the following years. Toggling back and forth between slide 7
for CSSB 21(FIN) am(efd fld) and slide 8 for HCS CSSB 21,
Version K, he drew attention to the purple cash flow bars in the
bottom left graph on each slide, explaining that government take
is lower in the earlier years and higher in the later years,
which is what leads to the slight increase in government take at
$100 a barrel, but lower government take at lower prices.
6:59:35 PM
REPRESENTATIVE SEATON noted that while it is interesting to look
at it this way, Alaska's tax rate is based on overall individual
corporate taxes rather than a ring-fenced production. He
inquired what will be the way the state looks at this and what
will be that impact when it is not a single ring-fenced field
that is being looked at.
MR. MAYER answered that [slide 9] represents typical base
production from the most mature fields for an existing producer;
thus, no factoring in of new developments, and looking simply at
a declining base portfolio. It is not a single asset ring-
fenced; it is a collection of assets. In further response, Mr.
Mayer clarified this is looking at base production rather than a
50 million barrel field.
7:00:38 PM
REPRESENTATIVE SEATON said he is trying to equate the previous
slides, which looked at a 50 million barrel field, with Alaska's
tax structure that is company-wide and has no ring-fences. He
asked whether it is the proportion of an individual company's
base production versus how much with GVR/GRE that must be looked
at to understand how this would affect different players.
MR. MAYER replied that can be done, but said the administration
and its consultant are in a better position to do that because
they have access to confidential taxpayer data. The three big
producers, by and large, do not have significant, if any,
production that would initially apply for the GVR/GRE. Looking
at it in terms of the variable credit and the impact on base
production is the best way to understand overall what this looks
like for them, not including any new things in new areas that
they might do. One can distinguish between those and understand
their economics separately without needing to perfectly layer
them on top and put a final precise number on the combination.
REPRESENTATIVE SEATON said he would like to ask the question of
the administration because the committee needs to see the
proportion of what to expect, given there is quite a difference
in the tax rates depending on what a company is doing.
7:03:01 PM
MR. MAYER commenced his presentation, outlining a hypothetical
scenario for a new development of 50 million barrels with $18
per barrel in costs [slide 10]. For this scenario under ACES,
he said the overall tax rate with progressivity would rise above
76 percent at the upper price levels.
MR. MAYER, in response to two questions from Representative
Seaton, confirmed the $18 is solely capital cost and does not
relate to the $30 per barrel in lease expenditure. He clarified
the earlier slides are a very simplified way of looking at
overall base production - they are 50 million barrels a year in
production, not a 50 million barrel field. Slide 10] is looking
at actual lifecycle economics of a hypothetical 50 million
barrel field.
7:04:32 PM
MR. MAYER moved to slide 11, discussing the aforementioned
scenario under CSSB 21(FIN) am(efd fld) with 12.5 percent
royalty and 20 percent GVR/GRE. Rather than progressive rates
rising above 76 percent government take, the rate is just under
61 percent. This 61 percent rate remains unchanged under
Version K; the only change is the categories of production that
qualify for this level of government take.
MR. MAYER, responding to Representative Tuck, said the $18 is
the total drilling and capital cost of development per barrel of
reserves in the 50 million barrel field.
7:06:08 PM
MR. MAYER, in response to Representative P. Wilson, explained
the top left graph on slide 11 tallies the total level of
government take for this scenario, which is then reflected in
the bottom right chart labeled "Economic Summary." The column
in the bottom right chart labeled "GT0" is the undiscounted
government take.
REPRESENTATIVE P. WILSON observed that at a price of $80 per
barrel the total government take is [60.56] percent and at a
price of $45 there is no tax except for royalty.
MR. MAYER replied that in this scenario of cost structure and
12.5 percent royalty, royalty alone at a price of $45 gets to
100 percent government take. In further response, he explained
that at a price of $45, the government take with other taxes
could be more than 100 percent, but it would not be productive
to show more than 100 percent on the chart. The essential point
is that at $45 a barrel, all of the cash the project produces
net of its costs is taken up just in paying the royalty, nothing
is left for anything else.
7:09:17 PM
MR. MAYER next looked at the aforementioned in the context of
Alaska's competitiveness with other comparable regimes [slide
12], noting that for new production qualifying for the 20
percent GVR/GRE, the government take is decreased substantially
from the very high levels under ACES. Interpreting the chart,
he explained the [right-most red arrow] on the chart depicts
government take for new production under ACES and the [left-most
blue arrow] depicts government take for new production under
Version K. Under Version K, the level of government take for
new production is much more in the "heart of the pack" among
Alaska's peer groups, particularly the peer group of the Lower
48. For production not qualifying for the GVR/GRE, Version K
(the right-most blue arrow) puts Alaska in the heart of the pack
at a price of $80 per barrel; however, at prices of $100 and
above, Version K [is less competitive than the middle of the
pack]. Responding to Representative P. Wilson, he confirmed the
left-most blue arrow is new production and the right-most arrow
is the legacy fields, both under Version K. He further
explained that for new oil, government take is the same under
Version K as it is under CSSB 21(FIN) am(efd fld). For legacy
production, Version K is a little better at $80-$100, but
slightly higher at $100 and above, than under CSSB 21(FIN)
am(efd fld).
7:13:22 PM
REPRESENTATIVE P. WILSON posited Version K accomplishes little
for improving worldwide competitiveness of the legacy fields.
MR. MAYER responded that when looking across the lifecycle of an
asset, if looking at just the next year or two, Version K is
lower at $100 and the same at $110, so all of the change is
below those levels. He suggested asking the companies that will
testify after him as to whether lower take at those prices will
make a material difference to them.
7:15:25 PM
MR. MAYER resumed his presentation, noting that the 12.5 percent
royalty rate included in the aforementioned scenario applies to
many of the older leases in Alaska [slide 13]. In a 50 million
barrel field of new development at 12.5 percent royalty and a 20
percent GVR/GRE, the overall level of government take is just
below 61 percent across the board. However, most of the newer
leases have a 16.7 percent royalty rate [slide 14], which raises
the government take to 63-64 percent and is the level of
government take that will apply to many things that might be
done across the North Slope, particularly by new companies
coming to Alaska to invest. The impact of that high royalty is
worth bearing in mind when thinking about competitiveness, he
said. For those leases at 16.7 percent royalty, he suggested
consideration be given to raising the GVR/GRE to 30 percent,
which would lower the government take to 61 percent [slide 15].
7:17:16 PM
MR. MAYER, responding to Representative Tuck, confirmed that the
assumptions in slide 15 are not included in any version of
SB 21. He said purpose of the slide is only to show what the
impact would be if the GVR/GRE were to be raised for leases with
16.7 percent royalty to achieve the same level of
competitiveness.
MR. MAYER, responding to Co-Chair Saddler, understood that new
leases are more likely to be at one-sixth [16.7 percent] than
one-eighth [12.5 percent]. He suggested the Department of
Natural Resources be asked about this.
7:18:25 PM
REPRESENTATIVE P. WILSON observed that when the state's split of
the net present value of production goes down, the federal
government's split goes up, and vice versa. She asked why.
MR. MAYER explained this is because federal income tax is the
last form of tax applied. Thus, all the costs for production,
including state taxes, are deducted in calculating profit and
loss for the perspective of paying federal income tax. In
further response, he confirmed that if a company pays the state
less, it will then pay the federal government more. Responding
further, he said the companies do better, relatively speaking,
when the state taxes them less, but the degree to which they do
better is reduced slightly by having to pay the federal
government that little bit more.
REPRESENTATIVE P. WILSON inquired whether it is good for the
companies if the state taxes them less, but they then have to
pay more in federal tax.
MR. MAYER responded the amount in federal tax that companies pay
in addition is substantially less than the reduction that they
get from the state because it is a 35 percent rate.
7:22:22 PM
BARRY PULLIAM, Economist & Managing Director, Econ One Research,
Inc., as consultant to the administration, compared the fixed $5
per barrel credit provision in CSSB 21(FIN) am(efd fld) with the
sliding per barrel credit provision in the proposed committee
substitute, HCS CSSB 21, Version K. He said the sliding credit
starts at a high of $8 per barrel when the wellhead value is $80
a barrel or less, moving down at the rate of $1 for every $10
increase in the wellhead value until reaching $0 credit at $150
wellhead value. In Version K, this sliding scale credit applies
only to areas without the gross value reduction (GVR); for areas
with the GVR, the credit is fixed at $5 per barrel.
7:24:10 PM
MR. PULLIAM provided an example of tax calculation [under
Version K] using the sliding scale production credit for volumes
not subject to the GVR [slide 3]. At an ANS West Coast price of
$100 per barrel, less a transportation cost of $10 per barrel,
the gross value at the wellhead comes to $90 per barrel.
Subtracting lease expenditures of $30 per barrel, the taxable
value per barrel comes to $60. For 100 taxable barrels, the
total production tax value comes to $6,000 ($60 times 100).
Multiplying that $6,000 by the tax rate of 35 percent results in
a production tax before credit of $2,100. At a wellhead value
of $90 per barrel, the credit is $6 per barrel. Multiplying the
100 taxable barrels by $6, the total production credit comes to
$600. Subtracting the $600 of credit from the $2,100 of tax
leaves a tax obligation of $1,500. Dividing the $1,500 in tax
obligation by the $6,000 in production tax value arrives at an
effective tax rate on the net value of 25 percent. Dividing the
$1,500 in tax obligation by the gross value of $9,000 ($90 gross
value per barrel times 100 barrels) arrives at an effective tax
rate on the gross value of 16.7 percent. Following the chart to
the left, it can be seen that as the price per barrel falls, the
credit amount increases until reaching the maximum of $8.
Following the chart to the right, it can be seen that as the
price rises, the credit amount falls until phasing out at the
wellhead head value of $150. The effective tax rate, as a
result of the interaction with the credit, is lower at low
prices and moves up to a maximum of 35 percent at high prices.
7:28:33 PM
MR. PULLIAM, in response to Representative P. Wilson, restated
how to calculate the production tax after credit at a price of
$100: the $600 in total production credit is subtracted from
the $2,100 in production tax before credit, resulting in a
production tax after credit of $1,500. To arrive at the 25
percent effective tax rate after credit, the total tax actually
paid of $1,500 is divided by the production tax value of $6,000.
7:30:15 PM
MR. PULLIAM then provided an example tax calculation [under
Version K] using the fixed $5 per barrel credit for volumes that
qualify for the 20 percent GVR [slide 4]. Different than on
slide 3 is that the per-barrel credit line (fifth line up from
the bottom) remains fixed at $5 per barrel rather than varying,
and there is a line for the 20 percent gross value reduction
(eighth line down). The bottom line on the chart illustrates
that the effective tax rates are uniformly lower for volumes
qualifying for the GVR. Responding to Representative P. Wilson,
he confirmed that production fits into either the sliding credit
scale or the GVR [and a fixed credit of $5 per barrel].
7:32:55 PM
REPRESENTATIVE SEATON understood that, currently, all production
would fall under the sliding scale production credit shown on
slide 3.
MR. PULLIAM replied almost all. He believed some production,
such as Nikaitchuq and Oooguruk, would qualify for the gross
value reduction. In further response, he confirmed that except
for Nikaitchuq and Oooguruk, all production would be under the
sliding scale production credit.
7:33:35 PM
MR. PULLIAM compared the average government take across all
existing producers for Version K, for CSSB 21(FIN) am(efd fld),
and for ACES for fiscal years 2015-2019 [slide 5]. He explained
the fiscal years match those in the fiscal note. The effect of
the sliding scale credit and 35 percent base tax in Version K is
to reduce government take below that of the fixed $5 credit and
35 percent base tax in CSSB 21(FIN) am(efd fld) at ANS West
Coast prices of $100 and less, and to increase government take
somewhat at prices over $100 per barrel. Government take would
top out at about 67 percent when the sliding credit goes to $0
at the price of $150. Thus, at higher prices, government take
under Version K is 1.5-2.0 percent higher than under CSSB
21(FIN) am(efd fld); at lower prices, government take under
Version K is a few percentage points lower than CSSB 21(FIN)
am(efd fld). Essentially, the line for Version K is tilted to
be a more progressive line, with the axis point at $100 per
barrel where the $5 credit applies.
7:35:34 PM
MR. PULLIAM, responding to Representative Tuck, confirmed that
the percentage of government take depicted on slide 5 is an
average for the five-year time period with all the credits and
deductions.
7:35:53 PM
MR. PULLIAM, responding to Representative Seaton, confirmed that
at the price of $160 and above, the percentage of government
take under the sliding scale decreases from 67 percent and that
this is the result of royalty. He explained the royalty has a
slight regressivity to it and there is no progressivity left in
the tax system at that point, so the overall government take
comes down slightly.
7:36:34 PM
MR. PULLIAM, responding to Representative P. Wilson, explained
the chart on slide 5 is calculated across all producers on the
North Slope, so some of those producers will not fall under the
sliding scale. Some of them will fall under the GVR with the $5
credit. In further response, he confirmed "all producers" means
he lumped all of the producers together and then averaged it.
He said this is done to protect confidentiality because these
are based on cost projections that are provided by the taxpayers
to the Department of Revenue (DOR) and those figures are used in
DOR's forecasts. Essentially, the forecast values developed by
DOR are used for both the volumes and the costs. To protect
confidentially the information for a particular field or for a
particular taxpayer is not revealed - it is aggregated over the
total. He added that the production on the North Slope will be
overwhelmingly based on just the sliding scale rates, as opposed
to the GVR.
7:39:16 PM
MR. PULLIAM moved to slide 6, explaining that the calculations
for estimated state revenues are his, not DOR's. The revenue
depicted by the blue bars is for CSSB 21(FIN) am(efd fld). The
revenue depicted by the green bars is for Version K and to
calculate this revenue he replaced the flat $5 per barrel credit
with the sliding scale where that would apply. Comparing the
two bill versions, the revenues under Version K would be: a
little lower at an ANS West Coast price of $80 per barrel, down
ever so slightly at $100, flat at the DOR forecast price because
the $5 credit would be applying to both versions, and higher at
$120 and above.
7:40:55 PM
MR. PULLIAM explained slide 7 is a pictorial representation of
the tax rates; the lines on this graph correspond with the
percentages shown in the charts [on slides 3-4]. Version K is
depicted in green and CSSB 21(FIN) am(efd fld) is depicted in
blue. The solid line for each bill version is the effective tax
rate on the net value of the oil and the dashed green line for
each bill version is the effective tax rate on the gross value
of the oil. The tax rate for the sliding scale credit under
Version K increases in a stair step function. The tax rate
lines for both bill versions cross over each other between the
ANS wellhead value of $100 to $110, so above that level the tax
rates under Version K are higher than CSSB 21(FIN) am(efd fld)
and below that level the tax rates are lower.
7:42:42 PM
MR. PULLIAM pointed out that at every increment of $10 in
wellhead value, the stair step credit moves by $1 [slide 8].
For example, between the wellhead value of $80 and $89.99, the
credit is $8 per barrel and [at $90] the credit drops to $7. He
recalled that Mr. Mayer showed committee members what happens
with the marginal takes. He further recalled Mr. Mayer
mentioning that the sliding credit could be structured as a
straight linear function so that with each $1 movement in the
value of the oil the credit could be moved and accomplish
essentially the same thing as would a stair stepped method.
7:43:46 PM
MR. PULLIAM, responding to Representative P. Wilson, said there
is no benefit one way or the other between using either a stair
stepped versus smoothed sliding credit. However, in his
opinion, the smoothness to the linear function is somewhat more
attractive than the abrupt change at each $10 level. Responding
further, he said the tax would be just as simple for a stair
stepped credit as for linear. Directing attention to slide 9,
he said a linear credit, as opposed to a stair step, would
flatten out the tax rate over the price range, which, in his
view, is more attractive than the other method.
7:45:18 PM
MR. PULLIAM, responding to Representative Tuck, said he could
provide a formula for a linear function. He explained that
whether this linear line falls above or below the stair steps on
a graph depends upon which dots are connected. For example, on
slide 8 at $150 wellhead value the credit is $0, at $140 and
above it is $1, so he connected the linear line at that portion
of the stair because, in his view, that fits with what is
written in the bill if one wanted to smooth out the line.
7:46:41 PM
MR. PULLIAM, responding to Representative Seaton, said he does
not have these same charts with the GVR/GRE, but could provide
one.
REPRESENTATIVE SEATON said he would appreciate that. He then
inquired whether the administration has a time estimate for when
30 and 50 percent of the oil would be subject to the GVR/GRE and
fixed $5 credit rather than just the stair step credit.
MR. PULLIAM responded he would have to talk with the forecasters
at the department. He offered his belief that it would be "a
while out" before 50 percent was reached because the legacy
fields would, by and large, be subject to the stair step and
will continue to be more than 50 percent of the oil for "quite
some time."
REPRESENTATIVE SEATON commented it would be helpful to see
because shale oil could take off and in fifteen years could be
350,000 barrels a day.
MR. PULLIAM said he will talk with the department's forecasters.
7:48:30 PM
MR. PULLIAM returned to Representative Tuck's question about a
formula and advised that a formula is easy to derive regardless
of whether one wants to connect it at the bottom or the top of
the stair steps.
MR. PULLIAM concluded his presentation by drawing attention to
graphs comparing the share of profits received by the state,
industry, and federal government under ACES (slide 10, top
graph) to the shares that each would receive under Version K
(slide 10, bottom graph). To create the charts he combined the
2012 historical information for the two legacy fields.
7:51:18 PM
DAMIAN BILBAO, Head of Finance, BP Exploration (Alaska) Inc.,
testified it is important to remember that the benchmarking is
against the ACES policy, the policy that has left Alaska
uncompetitive relative to other locations where BP can direct
its investments, and said that is fundamentally the policy
decision before the committee. He reminded members that [on
3/26/13] he talked about how [CSSB 21(FIN) am(efd fld)] created
a step change for Alaska in terms of competitiveness. It would
position Alaska in a better place than under ACES, which is
uncompetitive, complex to administer, and difficult for planning
a business. It would create a more competitive environment and
would provide a simpler model to administer and to plan a
business. Being able to run models for what a business
investment would look like is valuable for both existing and
potential investors.
7:54:25 PM
MR. BILBAO noted slide 2 is the same slide he displayed [on
3/26/13], except it includes checkmarks highlighting where the
proposed committee substitute, HCS CSSB 21, Version K, makes
additional progress beyond that of CSSB 21(FIN) am(efd fld).
Both bill versions do well in their provisions to eliminate
progressivity, include the GVR/GRE which positively impacts
economics, and simplify Alaska's fiscal system. Version K takes
an additional step by simplifying the GVR/GRE to make it clear
that there really are two levers to work within the legacy
fields - the base rate and the sliding scale [credit]. Version
K takes an even further step in simplifying the fiscal system
because a producer would not have to determine whether the
GVR/GRE applies, which makes it simpler to model business and
project economics.
MR. BILBAO recounted that [on 3/26/13] he testified to what CSSB
21(FIN) am(efd fld) could do better: below $100 a barrel the
high base rate of 35 percent presents a challenge. Version K
addresses this. Another provision to which he testified on
3/26/13 that could be better was the GVR/GRE: under CSSB
21(FIN) am(efd fld), it was uncertain what projects the GVR/GRE
would apply to. Version K addresses this. This progress was
partly accomplished by "taking the line ... and tilting it a bit
to the right so it corrects some of the challenge below $100 a
barrel and takes away some of the upside opportunity above $100
a barrel, effectively reintroducing a slight progressivity to
the equation."
7:56:45 PM
MR. BILBAO said BP believes that, overall, Version K is another
positive step forward and is a positive balance. Version K does
not attempt to select winners or losers; it provides a level
playing field that ensures the state, large producers, and small
producers have opportunities to benefit. Although there is
opportunity to take that even further, Version K repositions
Alaska on the competitive landscape and it represents a policy
shift because it shifts the burden to benefit from those credits
from spend to production. It is a signal from the legislature
that the policy will require the producers to deliver the
production in order to benefit from the credits. He said BP
believes this shift in policy is fair because the progressivity
is also eliminated, which allows BP to capture the upside of its
projects and places that opportunity under BP's control.
7:58:23 PM
REPRESENTATIVE SEATON, noting the elimination of progressivity,
asked how many years it would take for BP, the largest operator
on the North Slope, to see an increased investment and
production to at least stem the decline and have equal
production to that of 2013.
MR. BILBAO replied Version K encourages not only long-term
investments, but also near-term and mid-term investments. If
the bill passes in its current form, near-term opportunities
could be expected as a result of additional drilling, additional
pads, and some opportunities within the legacy fields.
REPRESENTATIVE SEATON related the committee has heard three to
four years as a timeframe for seeing something in the legacy
fields. His comment at that time was that if the bill is passed
and within five years it fails to produce the rates of
production that the state has now, he will consider the bill a
failure and not working. He asked whether five years would be a
legitimate timeframe from BP's standpoint.
MR. BILBAO responded it depends on what the final bill looks
like and how meaningful the tax change is. As stated by the
legislature's consultants, different levels of tax change will
lead to different levels of investment. If a bill passes in the
current form, he would expect to see an impact to investment and
production within the next five years.
8:00:41 PM
REPRESENTATIVE SEATON observed slide 2 states that prices
averaged $80 per barrel in 2010. Since people have been saying
they do not like ACES at high prices, he is surmising that 2010
is considered high prices. According to the presentation by
Econ One, he further observed, $80 would have an effective tax
rate after credit [under Version K] of 15 percent on the net and
8.6 percent on the gross. He inquired whether 8.5 percent on
the gross is about where BP is thinking the tax rate should be
for the legacy fields which already have facilities.
MR. BILBAO answered he cannot disclose what prices BP uses for
its economic modeling or for planning its business. However, he
advised, today's price futures typically assume for the next
five years a range of between $85 and $95. The market expects
that to be a mid-level range for prices - not high, not low, but
where the market is expected to be; with that in mind, it is
important that the bill is meaningful and impacts investment in
that price range as well. The legislature is looking to
incentivize not just BP, but investors across a broad range and
of different sizes. The legislature's consultants have shown
the impact at those levels, and at prices of $80 and $90
[Version K] shifts Alaska "to the left" in terms of competition.
It is up to legislators to decide how far left to shift, whether
to remain at the top of the middle of the pack or to be lower.
REPRESENTATIVE SEATON said he is hoping the committee will
receive a fiscal note that is generated on the prices that
industry expects, as well as the prices that DOR expects.
8:03:25 PM
REPRESENTATIVE HAWKER remarked he is not sure the base rate in
Version K results in meaningful change. He requested Mr. Bilbao
to discuss the problem/issue of joint interest billing (JIB),
which is not included in Version K. He noted that AS 43.55.165,
which came into law with the original production profits tax
(PPT), defines the basis for what is an allowable deductible
expenditure in calculating production taxes. The initial PPT
recognized the importance and validity of JIBs as a basis from
which to begin determining what ought be considered and allowed
in DOR's process of reviewing and auditing what are allowable
lease expenditures. However, ACES substantially rewrote that
section and now DOR believes it is prohibited from using JIB
statements to determine what is a legitimate lease expenditure.
MR. BILBAO replied it would be BP's preference to leverage
existing processes or instruments that industry has already
created for use internally and between companies. The JIBs
exchanged between companies are audited by the other co-
venturers. In BP's opinion, those JIBs present an opportunity
for DOR to leverage an existing instrument for informing DOR's
analysis and audit process. The decision to not use the JIBs
results in the creation of separate processes and separate
instruments. Using something that is already being created and
already being audited makes it easier and more efficient for BP
to satisfy the requests of the state. In further response, Mr.
Bilbao confirmed that JIBs are one of the fundamental
instruments used by BP for it Internal Revenue Service (IRS)
filings. Responding further, he deferred to DOR to say whether
it is familiar with JIBs.
8:07:55 PM
REPRESENTATIVE TUCK related the committee has heard in the past
that the bill is a great start, but may not get the investments
the state would like to see. He inquired whether BP's overall
investment per year in Alaska is directly proportional to the
state's taxes, such that if taxes are reduced BP will
proportionally invest more in the state.
MR. BILBAO responded the more robust the economics of the
projects, the more likely they are to compete for capital. The
more competitive Alaska is the more investment the state will
see from BP as well as other existing and new players. The
process used by BP is to regularly review what has changed - not
just the fiscal policy but also technology, resourcing, and
other factors. Once BP knows that a project meets a certain
minimum threshold, that project will compete with other
opportunities around the world. At the end of the day, good
projects with good economics get funded.
8:09:53 PM
REPRESENTATIVE TUCK noted the goal is to at least flatten, if
not reverse, the decline. He said the committee has heard that
an [additional] 40,000 barrels a day over 30 years [is needed to
offset the projected fiscal impact of CSSB 21(FIN) am(efd fld)].
The committee also heard 25,000 barrels a day is needed to lower
the decline from 6 percent to 1 percent. If the state needs to
get to 40,000 barrels a day, where does it need to be in the
competition and will Version K get the state there and how soon,
he asked. He understood the legacy fields are the quickest way
for getting additional oil down TAPS. If the state saves BP 20
percent in taxes a year, can the state expect to see 20 percent
more production out of BP's portfolio, he further asked.
MR. BILBAO answered it is not as simple as 20 percent here and
20 percent there. However, he continued, what is simple is that
the more competitive it is the more investment from all players,
and more rate-adding investment leads to more production. The
more competitive the state is the more rate-adding investment
the state will see. To provide context, he explained that if
nothing was done at Prudhoe Bay the decline would be closer to
20 percent; it is only because of investing and running a fleet
of rigs that BP is able to cut the decline to 6-8 percent.
Those are tens of thousands of barrels that are being produced
every year that were not flowing through that pipeline the year
before. It is a significant investment to get to today's level
of 6-8 percent decline and it will also take a significant
investment to get above that. Often lost in the conversation is
that Alaska has a fantastic resource base. Within BP there is
only one other location that has the resource opportunity seen
in Alaska. Additionally, Alaska has a fantastic talent pool of
employees and contractors that develop technology and are
recognized for it on a regular basis. Alaska's problems are not
below the surface; they are that Alaska's policy does not make
those projects economic. With the right policy, BP believes
there is great opportunity for Alaska to create a new future and
a different production profile than that seen in the past.
8:13:16 PM
CO-CHAIR FEIGE, assuming Version K becomes law, inquired what
logistical hindrances BP might encounter moving forward with
projects, such as sufficient drill rigs, service companies, and
fabricators, that might prevent BP from increasing production.
MR. BILBAO acknowledged there are geographic and logistical
challenges to shifting the activity profile in Alaska, but said
some are the result of seven years of no encouragement to invest
in the aforementioned. There would need to be an appropriate
time to correct for that and ensure the infrastructure is in
place, whether that is ensuring rigs are available or even as
simple as ensuring that BP is able to go back and look at
opportunities to see if they compete under the new policy. It
is the logistical and infrastructure challenges that will have
to be dealt with first. Beyond that, it is the simple matter of
ensuring BP does the right frontend loading of some of these
projects. Once there is a green light BP would have to catch up
with six or seven years of living under a policy that encourages
a short-term focus. That may be as equal a hurdle as the
logistical one, but BP is up for the challenge.
CO-CHAIR FEIGE asked what sort of timeframe could be expected.
MR. BILBAO replied he thinks it is realistic to say that in the
next few years the state would begin to see an impact on
additional production. That would likely be attributed to how
BP allocates it rig fleet more so than constructing a new pad,
for example. He offered to do the work necessary to provide a
specific answer if the committee would like.
8:16:21 PM
CO-CHAIR FEIGE inquired whether it is a simple matter to
reactivate the rigs that are currently stacked at Prudhoe Bay.
MR. BILBAO responded it is more complex than putting the key in
ignition. The rigs would need a full safety and efficiency
review and BP would have to ensure they are capable of operating
to the standards that BP requires to be used in the fields it
operates. Additionally, there needs to be the right people to
staff them. Therefore, it can take several months to get a rig
from zero to ready to drill.
CO-CHAIR FEIGE opined that the variable per barrel credit in
Version K that would apply to legacy fields would induce what he
would refer to as a progressivity type of effect, although not
progressivity the way it currently is. It would take a slightly
higher bite at higher prices and a lower bite at lower prices.
He asked whether the variability of that tax credit makes the
tax code simpler or is a complicating factor.
MR. BILBAO answered it has a dual impact. He confirmed it has a
positive effect below $100, but said that is problematic because
the base rate is quite high. It reintroduces a slight
progressivity to the tax structure, which is concerning from an
investor's perspective because at higher prices an investor may
not have the trade-off opportunity versus some other factors.
The shift of the burden to a production-linked credit is offset
by the opportunity of the removal of progressivity. The more
that progressivity is reintroduced it will factor into the
equation to a certain degree and to what degree will depend on
the individual company to determine.
8:19:14 PM
CO-CHAIR FEIGE recalled BP's [February 2013] testimony that the
order in which deductions are taken affects the tax rate -
changing the order changes the tax rate, which makes it
difficult for an investor trying to plan a project to be able to
determine what the tax rate will be. He inquired whether
Version K still presents this same problem.
MR. BILBAO replied that while BP must make an assumption for the
dollars per barrel to model, Version K is fundamentally much
simpler to administer and to model from a business planning and
economic perspective. It would be pretty hard to get much more
complicated than ACES, he added.
CO-CHAIR FEIGE presumed BP could possibly have areas within its
acreage that would fall under the GVR versus legacy field
property. Thus, there would be two different tax schedules. In
setting up this tax structure, legislators tried to keep the
percentages of government take relatively close, especially at
the price ranges the companies have indicated are used for basic
planning. He asked whether there are any issues with this
slight difference in percentages of government take between GVR
and non-GVR production at prices of $70-$90 per barrel.
MR. BILBAO responded BP does not expect for the GVR to be a
factor in the fields it operates, at least not for near- to mid-
term. When looking at its modeling, BP has kept it simple and
has only looked at a base rate and a dollar per barrel. The
company has not considered any unintended consequences of having
dual systems within a single unit, although there is always a
potential for that if there are different structures. He
suggested that the base structure of the base rate and the
dollar per barrel actually provide the legislature with a
structure that could be used for specific types of developments
in the future, which is a conversation for another day.
8:22:48 PM
CO-CHAIR SADDLER recalled hearing that the expiration of credits
might induce frontend loading, such as some quick purchases and
quick capital expenses. He inquired whether BP would spend more
than it ordinarily would to take advantage of that if the
qualified capital expenditure credit was sunset at year's end.
MR. BILBAO answered BP typically lays out its plans one year or
more in advance, so he does not expect that BP would a shift to
try to respond to a change in the policy. Rather, he would
expect that BP's focus would be on how its plans may change for
after the new policy is in place.
CO-CHAIR SADDLER asked about BP's perspective regarding what
goes into making an investment decision no matter the location.
MR. BILBAO replied the decision making can be as much art as
science, and depends on individual factors as well as
opportunities. He may look at different factors for a deepwater
Gulf of Mexico project than he does for an onshore project in
Texas or Alaska, or even more so an unconventional hydrocarbon
project like coalbed methane. So, it is not quite as simple as
a certain number and another number and then comparing and
whatever is above the line is undertaken, in particular because
there are so many intangible factors, such as political
stability or durability of the fiscal framework. Those
intangible factors must be injected throughout the process and
ultimately a business plan is developed that BP feels best
reflects its strategy across a broad portfolio.
8:26:00 PM
CO-CHAIR SADDLER noted it is heard that the oil industry is
making a profit in Alaska, so no matter what the state does the
industry will continue spending money in Alaska. He inquired
whether BP seeks profit or the highest profit when making
investment decisions. He clarified he is asking whether the
factor of being profitable is more important than the relative
profit. He is asking whether BP actually evaluates where it can
make the most money, not just make money.
MR. BILBAO answered BP has choices on where it invests the next
dollar. First and foremost, there is a base level of investment
that ensures the fields are operated safely and efficiently,
which is typically constrained more so by logistics and
resourcing than by funding. Beyond that, the dollars do
compete. If BP is going to decide on whether to build a pad in
Alaska or spend those billions of dollars to drill wells in the
Gulf of Mexico or offshore Angola, those opportunities are going
to compete against each other. It is about competing for the
rate-adding investment, not necessarily the rate-sustaining
investment. Those rate-adding investments must compete because
day the company's return per barrel is not the same everywhere.
MR. BILBOA, responding further to Co-Chair Saddler, explained
that rate-sustaining investments are those investments that BP
makes to ensure the fields are renewed for the long-term. For
example, Prudhoe Bay was built for 30-something years and it has
been more than 35 years and so there are new things that BP has
to put in place to ensure that the field is prepared and renewed
to produce for another 30 years. Those are large investments in
facilities and pipeline. Also, it must be ensured that BP's
employees are developed and learning the new technologies.
Rate-adding investments are the ones that bring on an additional
barrel, such as a rig that drills a well or a pad that provides
a new location to drill multiple wells from, or a deepwater
platform that allows drilling in several miles of water. All of
those are rate-adding investments that must ultimately compete.
8:28:57 PM
REPRESENTATIVE P. WILSON related it is being heard that there
are more workers on the North Slope than ever before, but Mr.
Bilbao is saying BP must spend lots of money to keep production
going, which tells her that much of that is maintenance work or
bringing things up to par. She requested Mr. Bilbao to comment.
MR. BILBAO replied it is not just maintenance, but also renewing
the facilities for the next 30 years. He agreed that today the
level of employment on the North Slope is high, pointing out
that five of every six people on the slope are focused on
renewing the infrastructure - rate-sustaining, not rate-adding,
projects. Only one person of the six is focused on a project
that delivers new rate, which is consistent with the policy that
is in place. If the policy encourages companies to maintain
production in an efficient way and focus on near-term
opportunities, then that is the ratio of how personnel will be
deployed. If the policy were to change, the ratio might change
to something different.
8:30:38 PM
REPRESENTATIVE TUCK recounted that when legislation was first
before the committee, the [Department of Revenue and Department
of Natural Resources] stated the credits lead to investments but
not necessarily production. However, the smaller oil companies
have stated they are scratching their heads over those
statements. He inquired whether BP has seen investments across
the North Slope that do not lead to production.
MR. BILBAO responded that by definition an investment must
either sustain the production for a longer period of time or add
new production. So, fundamentally, the answer to the question
is that new production comes from investment and sustaining
production comes from investment. In further response, Mr.
Bilbao explained if a company does not sustain it will not have
the facilities to be able to decline; in fact, the decline would
be 100 percent because there would be no pipelines or facilities
to flow through. He specified it is important to differentiate
between sustaining infrastructure and sustaining production
decline. If one considers what it took to build the
infrastructure to begin with, and that it has lasted 30-plus
years, it can be seen that a significant level of investment is
needed to ensure it lasts another 30 years. That is different
from sustaining production decline. If BP continues to do what
it is doing now with the same number of rigs, at best BP will
continue to decline at its current levels of 6-8 percent,
assuming things continue as they are.
8:32:51 PM
CO-CHAIR SADDLER asked whether the tax regime of net base, GVR,
and credits as proposed in Version K looks similar to any other
regimes in the U.S. or world.
MR. BILBAO replied he has worked in several countries and has
never seen a structure with a base rate this high and credits
the way they are. Remarking that similar questions have been
asked in the past by the co-chair with regard to new and old
production, he said that in every place he has worked all that
was cared about was production without regard to whether it is
new or old, so long as it is more than there was the day before.
8:34:03 PM
REPRESENTATIVE TARR inquired whether the employment information
of five out of six and one out of six cited by Mr. Bilbao has a
source or is anecdotal.
MR. BILBAO responded it is based on data from BP's human
resources department. As operator of Prudhoe Bay and many other
fields on the North Slope, BP knows what its staff and
contractors are doing and what projects they are deployed to.
Additionally, BP knows what proportion of its investment is
going towards rate-sustaining projects as opposed to rate-adding
projects as opposed to drilling projects.
REPRESENTATIVE TARR asked whether Mr. Bilbao included employees
of other companies in his numbers for exploration work.
MR. BILBAO answered BP does not do exploration, so that would be
zero for BP. The numbers are primarily focused on BP operated
facilities - Prudhoe Bay, Milne Point, Northstar, and Endicott.
REPRESENTATIVE TARR surmised the numbers cited by Mr. Bilbao are
reflective of that particular employment situation and not
encompassing everyone.
MR. BILBAO understood the numbers are reflective of other
fields, but suggested those operators be asked.
8:35:32 PM
REPRESENTATIVE TARR said a concern about Version K is that it
disadvantages small companies by the way it changes the credit
system that is for bringing them up to do exploration. Given it
has been suggested that both near- and long-term scenarios be
looked at, there needs to be more exploration, she opined. She
inquired whether BP anticipates returning to exploration on the
North Slope.
MR. BILBAO agreed it is important that all good opportunities
move forward for large players as well as new entrants and small
producers. As a large operator, BP benefits from that because
its facilities are underutilized. Just like TAPS is three-
fourths empty, BP's facilities could benefit from having
additional flow-through, which benefits existing operators as
well as new entrants. While he cannot speak for BP's board of
directors regarding strategy direction in Alaska, he can say BP
has significant existing opportunities in its portfolio, in both
light and heavy crudes as well as gas, and those are more than
adequate to keep BP busy for quite some time.
8:36:58 PM
CO-CHAIR SADDLER said he has heard the argument that there are
limitations to production and Alaska should not dare to hope for
increased production because there is not enough capacity in the
North Slope for the handling, processing, and transit lines.
Given that BP's facilities are underutilized, he asked whether
there is any difficulty in ramping up production based on the
current state of the physical plant.
MR. BILBAO allowed that is correct and said there are certain
facilities where a bottleneck is possible. When considering new
projects, BP looks at what additional investment is required to
ensure the facilities have the capacity to accept that
production. He requested that his statement not be taken as a
broad application to all of BP's facilities, adding there are
some where there is opportunity when a new project comes on to
ensure that the production will flow through. In further
response, he explained that currently in BP's fields, Prudhoe
Bay in particular, a tremendous amount of water and gas is
produced along with some oil. Thus, BP must work hard to manage
that ratio and ensure that the water is properly managed.
Oftentimes it is reinjected to maximize the recovery of oil, and
that delicate balance can be more challenging in some facilities
than others. So, when BP looks at new investments, that is one
of the things considered.
8:39:40 PM
BART ARMFIELD, Chief Operating Officer, Brooks Range Petroleum
Corporation, first provided an update on his company's Mustang
development as a response to the question being raised in other
bodies and committees about what the state is getting for its
investment [slide 2]. He said his company is 10 days away from
completion of an access road and production pad that is 4.5
miles off of the Kuparuk River Unit infrastructure. Results
from this project are very good: the overburden, the amount of
material that has to be removed to get to the gravel product,
has been less than expected; the gravel quantity is much larger
than was expected; and the quality is well above specification.
The plan is to condition that road over the summer, to do
facilities design, procurement, and some fabrication, and to
begin onsite construction in second quarter 2014. The project
is 17 months away from contributing new oil to TAPS at the rate
of 15,000 barrels a day. Therefore, there are results from the
investment the State of Alaska is making.
8:42:40 PM
MR. ARMFIELD, referencing BP's testimony about production,
sustaining production, and increasing production within the
legacy fields, he stressed the state needs both exploration and
production [slide 3]. "One size does not fit all - it means a
totally different result for a major than it does for a small
producer like Brooks Range Petroleum," he said. Brooks Range
Petroleum as a small independent has delivered and has brought
significant value to the state for the credits that have been
provided. Overall, his joint venture has received $69 million
in credits over a period of 7 years for its total North Slope
portfolio. The Mustang project alone will recover all those
credits within a single year and over its project life Mustang
will return $1.2 billion in revenue to the State of Alaska - 17
times the credits paid out.
MR. ARMFIELD, responding to Representative P. Wilson about the
Mustang project's timeframe, turned to slide 4, explaining the
blue line at the bottom of the graph is Mustang, which will
start production in 2014 and go 15 years through 2031. It will
contribute 15,000 barrels per day to TAPS. With an aggressive
schedule that his company has planned and with the other
remaining projects in his company's inventory, a total of 55,000
barrels per day will be reached within five years (2018).
8:45:08 PM
MR. ARMFIELD returned to his presentation, providing his
company's comments on the proposed committee substitute, HCS
CSSB 21, Version K. He requested consideration be given to
reducing the 35 percent base tax rate to 30 percent (slide 5].
Regarding elimination of credits, he requested consideration be
given to extending the qualified capital expenditure (QCE) and
exploration incentive (EIC) credits to 2016. Understanding the
long-term effects on the fiscal note that extending the credits
would create, he said his company supports the $5 produced
barrel credit. To offset the loss of the credits, he proposed
that monetization of the 35 percent net operating loss be
transitioned from a starting rate of 45 percent down to the 35
percent rate. He explained 45 percent is the equivalent of the
20 percent QCE credits and the 25 percent loss equaling the 45
percent that the Mustang project was originally sanctioned
under. All of his company's acreage would qualify for the 20
percent GVR/GRE. Brooks Range Petroleum would qualify for the
small producer credit that will expire in 2016 under Version K,
but this will not impact the company because it will have
production in 2014 thereby qualifying for the 10-year benefit of
this credit. To support the exploration side of exploration and
development, however, he suggested qualification for the credit
be extended to 2022 in anticipation of new players coming in.
8:47:53 PM
REPRESENTATIVE TUCK asked whether Mr. Armfield's aforementioned
suggestions would put the exploration back into the exploration
and production.
MR. ARMFIELD replied they would provide a better basis for
exploration than the current proposal under Version K.
REPRESENTATIVE TUCK inquired whether that would bring it back to
the current exploration under ACES.
MR. ARMFIELD responded he does not believe it would because
Brooks Range Petroleum will get out of the 45 percent credit
basis once it goes into production and is profitable. At that
time the company will fall under the same tax structure as
everyone else. Hopefully, his company will provide the basis
with its Mustang project to be able to sustain an exploration
program moving forward to backfill the decline that is generated
from the Mustang project and later those projects through 2018.
REPRESENTATIVE TUCK asked why there is such a concern with the
base rate, given the effective tax rate is low when everything
is combined.
MR. ARMFIELD answered the slides provided by both consultants
are for a new producer with a 50 million barrel field, and in
this scenario the government take at $100 per barrel oil is in
the range of 64 percent. A 5 percent adjustment in that base
rate is a significant base position that creates added value for
his company's projects.
8:50:40 PM
REPRESENTATIVE SEATON inquired whether the suggestion for a
transition from 45 percent to 35 percent would be for a
durational time or for anyone who qualifies for the net
operating loss (NOL).
MR. ARMFIELD assumed that 35 percent is the legislature's target
rate for a net operating loss. The only basis he has to request
the 45 percent is to make Brooks Range Petroleum whole to the 45
percent combination of QCE's and 25 percent loss that was in the
old program under which the project was sanctioned. Once the
company becomes profitable, it would transition out of that 45
percent, which would also be the case at 35 percent.
REPRESENTATIVE SEATON noted that once Brooks Range Petroleum
goes into production, it would depend upon company-wide
expenditures, not just expenditures for Mustang. If the
transition does not apply to a number of years, then that net
operating loss could apply for as long as a company was
continuing to invest and developing other fields. He said he is
asking whether Brooks Range Petroleum needs a specific number of
years or a duration that applies until it is profitable.
MR. ARMFIELD concurred a company could spend itself into a loss
position, but that is not what Brooks Range Petroleum is looking
for. In his company's forecast, the spend for those fields is
driven by the revenue generated from the Mustang project; so, he
is asking for the 45 percent relative to the Mustang project,
which is two years, not the portfolio as a whole.
8:53:53 PM
CO-CHAIR FEIGE pointed out that although Brooks Range Petroleum
may be reinvesting the profits so to speak, it is resulting in
significant production as seen by the graph on slide 4.
8:54:07 PM
REPRESENTATIVE P. WILSON surmised Brooks Range Petroleum is
saying it needs as much as possible in credits when it starts
production because that cash flow will be used to continue the
company's other projects.
MR. ARMFIELD replied yes, the front side support in an
exploration company transitioning to a production company is
very important. Effectively losing 23 percent of those capital
credits by the elimination of QCE and EIC significantly impacts
Brooks Range Petroleum. Going back to that forecast would
require a more modest growth to that production profile than the
aggressive nature that it is in now.
8:55:13 PM
REPRESENTATIVE TARR asked whether the [six] projects outlined on
slide 4 were all sanctioned under ACES.
MR. ARMFIELD responded the only project currently sanctioned is
Mustang. The graph is an extrapolation of his company's current
inventory, tested oil, and application of the parameters that
result in this profile.
REPRESENTATIVE TARR recalled previous testimony in which Mr.
Armfield said the Mustang project would have been shifted out a
few years had the credits not been in place. She inquired
whether the timeline depicted on slide 4 is reflective of how
investment opportunities would go under the current system.
MR. ARMFIELD answered this is his company's original forecast
and it was based under the assumption of 20 percent capital
credits and 25 percent loss credits.
8:57:07 PM
The committee took an at-ease from 8:57 p.m. to 9:12 p.m.
9:11:47 PM
CO-CHAIR FEIGE noted Pioneer Natural Resources Alaska, Inc. has
submitted written testimony.
9:12:01 PM
DAN SECKERS, Tax Counsel, ExxonMobil Corporation, stated both
CSSB 21(FIN) am(efd fld) and the proposed substitute, HCS CSSB
21, Version K, make significant progress to reforming ACES and
represent a strong step forward towards improving Alaska's
investment climate. Version K would make Alaska more
competitive and would improve the state's overall investment
climate. As to whether Version K would make Alaska more
attractive across all prices compared to its competitors, the
answer is yes and no. ExxonMobil's concern remains that the
base rate is too high relative to competitors, especially the
lower 48 states, which was demonstrated by PFC Energy's chart.
Also, while Version K provides more attractiveness at lower
prices, tying the GVR/GRE for legacy fields to price reduces the
competitiveness of that as prices rise. Alaska represents a
critical component of ExxonMobil's worldwide portfolio and the
company looks forward to being in Alaska for many years. It is
ExxonMobil's view that the need for Alaska to develop a
competitive and attractive fiscal regime is one of the most, if
not the most, important issues facing Alaska today. It is the
legislature's policy call as to whether either bill makes Alaska
as competitive and, more importantly, globally attractive
against the state's competitors at all prices to attract the
investment that is needed on the North Slope for Alaskans and
for development of the state's resources going forward.
9:14:42 PM
REPRESENTATIVE TUCK understood Version K makes Alaska's
investment climate better but not necessarily the best. He
asked whether the bill will be able to stop the decline curve.
MR. SECKERS replied that is everyone's goal and ExxonMobil
believes that with the right improvements to ACES the
marketplace will dictate more investments be made. Investments
coming forward from making Alaska more attractive will lead to
more production and more investment in Alaska from all players.
REPRESENTATIVE TUCK surmised Mr. Seckers agrees that more
investment leads to more production.
MR. SECKERS responded clearly there will not be more production
without more investment, and it is critical to get that
investment from all players.
9:15:50 PM
REPRESENTATIVE SEATON inquired whether it would mean the tax
change was unsuccessful if within five years production is not
at 2013 levels.
MR. SECKERS answered it will be important for the state to take
a good look at that point in time to decide whether the changes
went far enough. If the hoped-for production has not been
reached by that time, the state could make further changes after
conferring with its consultants.
9:16:57 PM
REPRESENTATIVE SEATON expressed his concern that, in regard to
increasing production in Alaska's larger fields, it may not
matter what short-term changes are made because investments made
by the major oil companies are driven by the companies' long-
term strategic plans. He inquired whether ExxonMobil makes its
investments based on a long-term strategic plan or vacillates in
its investments fairly rapidly with changes in tax rates.
MR. SECKERS reiterated ExxonMobil has been in Alaska for a long
time and looks forward to staying for many years to come. The
company is actively looking for investments in Alaska that are
attractive to make, and will make them as they become attractive
to do so. A number of variables are reviewed when making both
long-term and short-term decisions. Most investments are long-
term driven investments because it takes quite a bit of upfront
capital before recovery is ever made. However, that does not
mean ExxonMobil cannot move on the shorter term if need be or if
opportunity presents itself. The company makes as many
investments as it can because that is the business it is in.
9:19:37 PM
CO-CHAIR FEIGE noted the governor's proposed legislation is
based on several principles - make the tax code simpler,
durable, and equally affect all players. He asked whether Mr.
Seckers believes Version K has the potential to be a relatively
stable tax regime and treats all taxpayers relatively equally.
MR. SECKERS responded it is up to current and future legislators
to decide whether the proposed change has the chance to be
durable. It is the legislature's purview to change taxes and
policy when it deems necessary or desirable. ExxonMobil values
stability, so the longer a good policy is in place and the more
stable it is the better it is for investment climate. The more
changes that are made the less predictable a structure is and
therefore the less attractive the structure. The goal would be
to establish a policy that is competitive and attractive for the
long-term. Regarding equal treatment of all taxpayers, he said
ACES does not because it has different rules for different areas
within the state - Cook Inlet, "Middle Earth," and the North
Slope - and Version K does not change any of that. On the North
Slope, Version K distinguishes the legacy fields apart from the
GVR/GRE, which creates disparity between the different
taxpayers. The proposed $5 per barrel credit is different for
the legacy fields than it is for the others. So, no, Version K
does not treat everybody the same and that could bear being
looked at, at least for the players on the North Slope.
9:22:33 PM
CO-CHAIR FEIGE inquired whether Mr. Seckers sees any obvious
instances in the bill that would create disincentives for
various companies.
MR. SECKERS answered he cannot say how other companies might
look at the bill, but ExxonMobil is looking to do all the
investments it can that are attractive with its partners.
9:23:06 PM
REPRESENTATIVE SEATON noted the legislature is looking at gas
pipelines and understood ExxonMobil is also looking. He asked
whether ExxonMobil plans to hold to the 35-year fiscal certainty
requirement before it will engage in a gas sales agreement.
MR. SECKERS replied he cannot answer questions regarding gas.
9:25:55 PM
SCOTT JEPSEN, Vice President External Affairs, ConocoPhillips
Alaska, Inc., provided one slide in a PowerPoint presentation
regarding the proposed committee substitute, HCS CSSB 21,
Version K. He said the left column on the slide [slide 2] lists
the issues with ACES that ConocoPhillips believes need to be
addressed to create an improved investment on Alaska's North
Slope. The right column lists ConocoPhillips' perspectives on
Version K. Progressivity is the most difficult element of ACES
in terms of attracting new investment in the state, and needs to
be changed. Version K has a slightly progressive tax structure,
but would predominantly address the major issue under ACES and
is therefore a positive. ConocoPhillips has advocated for a
flatter tax rate over a broad range of prices where there is
equal sharing in the upside as prices increase and as prices
decrease and also as margins change, so Version K is a
significant improvement over ACES. Relative to ACES, CSSB
21(FIN) am(efd fld) represented a tax increase at lower prices,
and the progressive tax credit per barrel structure in Version K
addresses that issue. ConocoPhillips would prefer there be no
progressivity, but the company understands the balance the
committee took into account when it changed the effective tax
rate at lower prices in Version K.
MR. JEPSEN reminded members that ConocoPhillips has advocated
for a competitive tax structure that creates a competitive
attractive investment. This would include a competitive tax
rate, incentives to balance the high cost environment on
Alaska's North Slope, and the incentives and tax rates would
apply to both legacy and new fields. The base tax rate in
Version K is still too high, he specified. As seen in the data
provided by the legislature's and administration's consultants,
a 30 percent rate is about the average of the competition in the
other areas that are attracting significant investment. As that
dollar per barrel tax rate decreases as prices go up, Alaska
moves backwards and ends up on the high end of average. While
it is the committee's policy call on where it wants to position
Alaska for investment, ConocoPhillips thinks this is an area to
look into to potentially improve the bill.
9:29:01 PM
MR. JEPSEN pointed out Version K has no investment incentives
inside the legacy fields, which have many challenged projects.
He said ConocoPhillips is drilling around the periphery of
legacy fields and drilling for bypassed reserves and isolated
fault blocks inside fields like Kuparuk and Prudhoe Bay. Some
very complex and costly wells are being drilled to try to access
those reserves. Regarding what needs to be done to position
Alaska to attract more investment, Alaska still is challenged by
its location, weather, logistics, and environmental and tax
frameworks. A positive change in Version K is the committee has
looked at some of the comments ConocoPhillips made previously
about the application of the GVR/GRE to participating area (PA)
expansions inside the legacy fields. It appears there would be
a greater likelihood of PA expansions inside legacy fields
having the GVR/GRE application as well as the 35 percent/$5
credit applied to those sorts of expansions versus the current
progressivity structure.
MR. JEPSEN, addressing an earlier question about whether these
changes will lead to increased investment, said ConocoPhillips
believes Version K does change the investment climate on the
North Slope and will lead to increased investment and additional
production. However, until a bill is passed he cannot say
exactly what projects ConocoPhillips is going to do, how much
production the company will add, how many billions of dollars in
investment on the North Slope might change. Once a bill is
passed, ConocoPhillips can look more closely at all of its
project economics and determine which projects to sanction.
Version K, by and large, is a positive step forward, although
there are some things that could be done to attract even more
investment. Version K is a better bill than CSSB 21(FIN) am(efd
fld) and is a good start towards putting Alaska on a path to a
healthier longer-term economy.
9:31:51 PM
REPRESENTATIVE TARR understood it is more expensive to invest in
Alaska, but noted much infrastructure is already developed on
the North Slope. She asked how that factors into investment in
the state.
MR. JEPSEN responded that in many areas where ConocoPhillips is
currently investing considerable amounts of capital, such as the
Bakken and the Eagle Ford, significant infrastructure is not
required to bring those wells on line. Also, the infrastructure
the company is building [in those locations] does not begin to
compare with the costs and infrastructure on the North Slope.
So, even though there is infrastructure on the North Slope, it
is still highly constrained by the regulatory environment.
REPRESENTATIVE TARR inquired as to the exploration activity of
ConocoPhillips.
MR. JEPSEN answered there was a hiatus, but ConocoPhillips has
been active in exploration for quite a while on the North Slope.
The company will probably drill two exploration wells on the
Cassin prospect, and has other opportunities where there has
been success in the National Petroleum Reserve-Alaska (NPR-A).
9:33:56 PM
CO-CHAIR SADDLER asked whether ConocoPhillips believes it has a
good understanding of the proposed system.
MR. JEPSEN replied he cannot say ConocoPhillips has a 100
percent confidence factor that it understands all the potential
unintended consequences of Version K. For example, he is unsure
he fully understands the impact on the marginal tax rate as the
thresholds are crossed over. However, his company understands
it well enough relative to the current tax framework to say that
it is a big improvement.
CO-CHAIR SADDLER asked whether the looming deadline for
qualified capital credits would encourage ConocoPhillips to make
additional frontend loading investments.
MR. JEPSEN responded there are many structural issues with
attempting to do that - it takes time to get additional kit on
site, to gear up people to do work, and to order materials. The
system basically has a built in governor regarding the level of
activity that can be ramped up quickly. So, the answer is no.
9:35:45 PM
CO-CHAIR FEIGE, assuming Version K becomes law, inquired what
logistical hindrances ConocoPhillips might encounter in moving
projects forward and what things could the legislature do
outside of taxes that would help smooth some of those logistical
road blocks.
MR. JEPSEN answered there are obviously things that have to be
done to mobilize, but they are what ConocoPhillips does and so
it knows how to do them. What his company is looking for is to
create the investment climate on the North Slope that will allow
it to make those decisions and implement those new projects.
CO-CHAIR FEIGE asked whether Mr. Jepsen believes the changes
made to the GVR/GRE definitions in Version K are clearer and
provide certainty as to whether a project qualifies.
MR. JEPSEN replied ConocoPhillips might like to expand the PA
for its West Sac development inside its Kuparuk River Unit. As
Version K reads now, it is clearer the acreage that would be
expanded onto would probably qualify for the GVR/GRE. While
there is still some discretion, he could go into it with a much
higher degree of confidence than he would have before - before
he would have thought it would not qualify or much of it would
be unlikely to qualify. Also, there is still some uncertainty
about how to measure the production, but there is history and
precedent for how the company monitors production without
actually having a meter on every well. This change is a
positive, although the company will have to test it to know
exactly how it will be interpreted.
CO-CHAIR FEIGE commented the committee will look forward to see
if the expected results of the change in policy do pan out.
9:38:55 PM
REPRESENTATIVE SEATON noted ConocoPhillips has quite a bit of
experience in shale in the Lower 48. He understood the company
holds interests on the North Slope that have shale underlay.
He inquired how ConocoPhillips would interpret the GVR/GRE in
the development of shale and how shale developments would fit
into PA or PA expansions where the wells are not contiguous with
anything else.
MR. JEPSEN responded that in the abstract, not paying attention
as to whether the economics of shale make any sense, it would be
a separate PA or production from these horizons and his belief
is that it would probably qualify for the GVR/GRE. There is
currently no production on any of the leases that ConocoPhillips
has coming out of the shales and the company has no PAs that
encompass the shales or production from shales.
REPRESENTATIVE SEATON surmised, then, that Mr. Jepsen's estimate
is that each well would qualify for the exclusion and $5 credit
because it would not have continuity with another reservoir.
MR. JEPSEN answered his understanding of Version K, as written,
and the definition of what would qualify for GVR/GRE, is that
ConocoPhillips would probably form a single PA that encompasses
the entire area it would be developing in this contiguous shale.
Rather than thinking about it well by well, he would think about
it as any well inside that PA that was producing from that
horizon because that horizon is qualified. For example, as
discussed by Mr. Armfield, every well in the Mustang field would
qualify for the GVR/GRE - it is not individual well by well, it
is any well inside that PA.
9:41:57 PM
REPRESENTATIVE SEATON inquired whether it would mean the tax
change was unsuccessful if within five years production is not
at 2013 levels.
MR. JEPSEN replied the answer is a relative answer because right
now he cannot say what might happen to the existing production
from the current fields. Based upon all his years in this
business, he can say it is difficult to predict how reservoirs
are going to perform, particularly as they age. It is not
beyond the realm of possibility that base decline might actually
steepen for some reason and there could be a much bigger gap to
overcome by the investment that this bill might attract to the
North Slope. At that time in the future, there would need to be
a look at how much new investment happened, how many new wells
were drilled, what was the production from those wells, and what
was the base decline, and then make a relative judgment rather
than sitting here today making an absolute judgment based upon
preconceived ideas of what would constitute success.
9:43:40 PM
REPRESENTATIVE SEATON, noting there would no longer be credits
[as a way to track investments], asked what Mr. Jepsen would
suggest for providing a handle on what investments have been
made during that time period; for example, whether there should
be something in the bill requiring companies to report their
investments so a comparison of investment levels can be made.
MR. JEPSEN responded DOR receives investment numbers from all
producers and explorers, so that would be a gauge as to how
investment levels might be changing. However, he added, it is
again a relative answer. If the price of oil were to go down
but the tax environment or the investment climate on the North
Slope competes favorably with other locations, maybe investments
are down but relative to other places it is robust. Judgment
needs to be made at that point in time when the current
environment can be considered.
9:45:15 PM
REPRESENTATIVE SEATON addressed the co-chairs, saying the
committee needs to hear from DOR whether the legislature has the
right to know or whether it is in-house knowledge regarding the
level of investment in terms of determining whether changes were
successful. He said something may need to be included in the
bill that requires aggregated investment data.
9:46:11 PM
CO-CHAIR SADDLER requested Mr. Jepsen's opinion about the Oil
and Gas Competitiveness Review Board proposed under Version K,
and the board's composition, mission, activity schedule, and
confidentiality provisions.
MR. JEPSEN answered all of those could be somewhat problematic,
depending upon how they are handled. He suggested the bill be
given time to work and, if the legislature wants to have such a
board, to push it out far enough in time where there is the
opportunity to have a meaningful look back. He would argue the
legislature should ensure the board has the ability to hire
qualified consultants to make that assessment. It could work
under the right setup, but doing it on a very frequent basis
would not be terribly helpful because it takes time to do things
on the North Slope and for investors to react.
CO-CHAIR SADDLER said he thinks the board is on a four year
schedule. He asked whether Mr. Jepsen believes ConocoPhillips
would feel safe sharing confidential information with the board.
MR. JEPSEN replied he has not looked at the provision close
enough to answer the question.
CO-CHAIR SADDLER asked whether the review board would be seen as
a benefit to the industry as well as a possible negative.
MR. JEPSEN responded that is a possibility.
9:48:05 PM
REPRESENTATIVE TARR said she thinks Version K provides for the
board to meet no more than once a calendar year. She asked
whether Mr. Jepsen meant once a year is too often and commented
she does not think that to be too often.
MR. JEPSEN said his comment was about how often a pronouncement
is actually made as to whether the state is competitive. He
reiterated he thinks the state needs to give it time to work.
9:48:52 PM
CO-CHAIR FEIGE requested the Department of Natural Resources to
address the shale issue brought up by Representative Seaton.
JOE BALASH, Deputy Commissioner, Office of the Commissioner,
Department of Natural Resources (DNR), replied that as the
hypothetical is laid out, the question that must be asked is,
"Where is the production from the shale resource taking place?"
If it is taking place in a unit that was formed after 2003, then
clearly it will qualify for the GVR/GRE. If it is taking place
in a PA that is newly formed in a unit that formed before 2003,
it will qualify for a GVR/GRE. If it is acreage that is not
currently in a unit, and if a unit is not being formed for shale
production, then it will not qualify for a GVR/GRE; what it will
qualify for is the per barrel credit that slides from $8 to $0.
The way the definitions unfold is that the per-barrel credit is
determined based on whether or not the production qualifies for
the GVR/GRE. If production does not qualify for the GVR/GRE,
then it gets the sliding per barrel credit.
9:50:38 PM
REPRESENTATIVE SEATON presumed there would be two different tax
rates for production out of the same source rock in a unit such
as Prudhoe Bay or Kuparuk where there is no previous
participating area.
MR. BALASH interpreted the question as whether - because the
Prudhoe Bay Unit was formed before 2003 - that source rock is
going to be in a participating area. He said: "If it is not
going to be in a participating area, if it just going to be
drilled and produced, then it will not qualify through any of
the three buckets for the GVR. So, ... it will get the slider."
9:52:07 PM
REPRESENTATIVE TARR inquired whether there is an established
process for the expansion of participating areas, given there
has not been a reason previously to do so. She understood
participating areas were previously developed with the idea that
that was the acreage needed for development.
MR. BALASH confirmed there is a procedure, saying it is an
amendment to Exhibit C in the unit documents. A change in the
file would correspond with a date, an action, and a review that
comes in through the division process.
9:53:09 PM
REPRESENTATIVE SEATON related that his understanding from
testimony is producers anticipated the source rock would be
established as a PA and wells drilled in that PA would get the
GVR. However, DNR is saying if it is source rock then it would
not be certified as a PA at all, whether it was inside or
outside an existing unit.
MR. BALASH said the question goes to the particular hypothetical
being looked at. Due to the time, effort, and expense that
would be required, it is unlikely a PA will be formed for each
well that is drilled in a resource play development. Because
the drainage from a fractured well is fairly limited - measured
in feet - it would not be worth the effort. Establishing PAs
for the dozens of horizontal legs out from the well is not going
to make much sense, so DNR does not expect that is the way it is
going to work out. Returning to the Prudhoe Bay scenario, he
said a unit established prior to 2003 and not in a new PA, would
not qualify for the GVR. However, a PA recorded for each of
those wells would qualify because it would be in a new PA in a
unit formed prior to 2003. For the operator, the question is
the price environment and whether it would be better to get the
$8 or the higher side that the GVR affords. Because of the
steep decline that occurs in a shale well, maybe the operator
would play a little bit of a price game there, he allowed. That
would be the operator's choice coming into the department and
the department would have the discretionary tool of whether to
grant the PA. The operator can still drill and produce that
well if a PA is not granted.
9:56:32 PM
REPRESENTATIVE SEATON stated this is fairly critical in terms of
a durable system. There is potential for significant finds and
developments, so there should be something that actually deals
with the entire play since it is different than conventional,
rather than leaving it up to whoever happens to be in the office
at the time. He urged this be considered as the committee goes
forward.
CO-CHAIR FEIGE allowed the aforementioned is a legitimate point,
but said it is a policy decision on the committee's part whether
to incentivize shale oil development and there has been no
testimony from a company trying to advance such a project. A
GVR could be defined to apply to that and would be a reasonable
way to provide an incentive, if an incentive was necessary.
Since the costs of such a project are unknown, it is unknown
what amount of incentive would be needed and would be a guess at
this point.
MR. BALASH advised that unconventional resources, such as shale
or heavy oil, might require different treatments. There is no
answer right now because today it is not economic. As the
understanding of those resources improves, that opportunity will
afford future legislatures the opportunity to make a reasonable
decision. However, the current structure of Version K does
provide tools to deal with that.
[CSSB 21(FIN) am(efd fld) was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| FY15sensitivity HRES CS WDRAFT Supplemental Slide HRES 4.2.13.pdf |
HRES 4/2/2013 6:00:00 PM |
|
| HRES HCS CSSB21 BP 4.2.13.pdf |
HRES 4/2/2013 6:00:00 PM |
SB 21 |
| HRES HCS CSSB21 Brooks Range Petroleum 4.2.13.pdf |
HRES 4/2/2013 6:00:00 PM |
SB 21 |
| HRES HCS CSSB21 Pioneer Natural Res. 4.2.13.pdf |
HRES 4/2/2013 6:00:00 PM |
SB 21 |
| HRES HCS CSSB21 ConocoPhillips 4.2.13.pdf |
HRES 4/2/2013 6:00:00 PM |
SB 21 |
| House CS for CSSB21(RES) Work Draft Version K - 4.2.13.pdf |
HRES 4/2/2013 6:00:00 PM |
SB 21 |