Legislature(2011 - 2012)BUTROVICH 205
02/29/2012 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB192 | |
| Oil Production Tax Modeling by Pfc Energy | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 192 | TELECONFERENCED | |
SB 192-OIL AND GAS PRODUCTION TAX RATES
3:34:11 PM
CO-CHAIR PASKVAN welcomed PFC Energy saying, according to its
website, it is a global consulting firm specializing in the oil
and gas industry. [CSSB 192(RES) 27-LS1305\B was before the
committee].
^Oil Production Tax Modeling by PFC Energy
3:35:20 PM
CO-CHAIR PASKVAN recapped that PFC had presented testimony to
the committee on February 16 and 17 focusing mainly on
progressivity. Subsequently, the committee requested additional
information and modeling.
GERALD KEPES, Partner, Head of Upstream and Gas, PFC Energy,
Washington, D.C. introduced himself.
3:36:53 PM
JANAK MAYER, Manager, Upstream and Gas, PFC Energy, Washington,
D.C., introduced himself. He said he would continue his analysis
of proposed amendments to CSSB 192 and how progressivity changes
government take over the course of a price deck. In response to
questions about the cost assumptions PFC used for the generic
low cost field development - $10 for OPEX, $5 for development
CAPEX and $5 for maintenance and $7 in transportation costs - he
said they used their own research, particularly on what costs
had been at Prudhoe Bay in the most recent financial year they
had data for (but somewhat higher if one includes both the
initial capital development and the ongoing capital spend).
3:39:04 PM
He said it's important to understand that in some ways the idea
behind this generic low cost field was a hybrid reference case.
On the one hand, an actual Prudhoe Bay obviously depreciated its
capital a long time ago, but has a relatively high maintenance
cost of $5 per barrel to replace old facilities to do new well
work. The idea was that it would enable them to present life
cycle economics including some initial relatively low upfront
development costs, but also show the impact through capital
credits of the ongoing maintenance capital that is a key
characteristic of an aging field.
In addition, Mr. Mayer said he would present a look at what this
fiscal regime looks like in a high cost field development of
about three times the lower case -about $15 per barrel of
reserves in the initial capital spending and very high operating
costs of $17 per flowing barrel. Recent high cost developments
that have actually occurred have had figures quite close to
this. Further, he explained that precisely because ongoing
capital is treated somewhat preferentially under the current
system because of the capital credits, they included a small
amount of ongoing maintenance CAPEX, but the idea was to look at
a high cost new development that doesn't have a lot of
maintenance yet.
MR. MAYER explained that the reason they wanted to look at the
higher cost case is because it is what marginal additional
production on the North Slope increasingly looks like. It's
important to understand what the ACES regime looks like for a
Prudhoe Bay type development over a life cycle, because that is
what the majority of production is. But it's just as important,
and possibly more so, to understand what it looks like for a
high cost development, because the economics of replacing the
decline with new barrels are even harder. It's important to
start showing that picture.
3:42:02 PM
He said he was using the same slides as last time for
transparency purposes, and noted a 1 percent to 2 percentage
change upward in government take as a result of a revision to
the model improving the accuracy, but he said it had a
relatively minor impact overall on the figures. It showed 75
percent government take at the $100 level and 84 percent at the
$230 level. Mr. Mayer said if they compare that with the next
slide of a high cost development, one sees that while ACES is
highly progressive on price (economic rent and cost being other
categories), it is actually not progressive at all at high
costs. In some ways it is slightly the opposite, and that seems
counterintuitive, because one thinks this is a profit-based
system and surely a profit-based system must inherently be
neutral with regards to cost. But looking at the details, one
sees that production tax by itself is slightly progressive with
regard to cost. Capital credits make the production tax
component slightly progressive with regard to costs, but it's
not sufficiently progressive to overcome the inherent
"regressivity" of the other components of the system,
particularly the fixed royalty. He said it is important to
understand that means that government take numbers for a high
cost developments are not lower than they are for the low cost
developments, but in fact they are slightly higher. It's
important when one starts to look at how high costs impact the
economics of a project and what it can do to breakeven prices in
the $70s and $80s versus in the $90s and above. He used a
generic example project to explain to illustrate how high
marginal take can move the cost of a project up so much that it
becomes uneconomic.
3:45:12 PM
MR. MAYER said PFC was also asked to do an analysis using DOR
FY13 estimated costs. In doing that, the mode of analysis
changed from looking across time to looking at just one specific
year. A number of things don't get captured with using a
snapshot in time - things like the bracket creep effects that
occur because of inflation over time, which reduces the
government take. One is also not looking at the life cycle of an
asset type.
3:50:28 PM
SENATOR STEDMAN asked him to explain that in more detail.
MR. MAYER explained that the appendices to the Revenue Sources
Handbook, page 104, (d)(1)(c) showed $13.75 for operating and
lease expenditures and $15.36 for capital expenditures. Those
are per barrel prices, but not per barrel produced. They are per
taxable barrel, meaning that they are taking the entire costs
for North Slope production, but taking out royalty barrels and
barrels that for other reasons don't come under the system, and
spreading the costs over the taxable barrels. To use those
figures as an input to the model, they need to understand what
they actually are on a per barrel produced basis (that
calculation will equalize the costs of processing it through the
model and taking out the things that get deducted as the model
works).
3:52:00 PM
Instead Mr. Mayer note that he provided a table of actual
revenue figures (slide 7) of different components of a regime,
not from a percentage of government take perspective. For
instance, $110 oil has a production tax number of $4.78 billion,
slightly higher than the $4.717 in DOR FY13 estimates. That
difference is entirely due to their using a $109.47 barrel price
for ANS crude versus $110. The next important thing to say about
this analysis is that it shows what the system looks like at
different price takes holding everything else including costs
constant. But the reality is that as prices have risen
historically, so have costs - very dramatically. He reminded the
committee how to remember that this was just an analysis and not
a forecast.
CO-CHAIR PASKVAN asked if he was saying if prices go up, costs
could go up, too. But for his analysis he kept the costs
constant using FY13 levels adjusted for the flowing barrels.
MR. MAYER answered yes.
MR. KEPES said they know that costs will go up if that does
happen on a sustained basis.
3:54:59 PM
MR. MAYER went to slide 8, an overview of two unbracketed
amendments and two bracketed amendments in CSSB 192. He
summarized the salient points of each saying first that under
ACES the production tax is level until $30 barrel when .4
percent progressivity kicks in and that is reduced to .1 percent
level once production tax value reaches $92.50.
Under CSSB 192, two key changes are made: one is putting in a 60
percent maximum for production tax value (rather than the 75
percent), and the other is the initial progressivity coefficient
is reduced from .4 percent to .35 percent.
Amendment B.3 uses that 60 percent maximum, but it doesn't
change the .4 percent progressivity coefficient. Amendment B.18
uses the 60 percent maximum and keeps the .4 percent
progressivity coefficient up until a production tax value level
of $67.50 per barrel; then it reduces that to the .35 percent
level for prices between $67.50 and $92.50.
Two bracketed amendments take the 25 percent base level that
applies in all of these cases to production tax value, and takes
the $30 price at which progressivity kicks in, but instead uses
a bracketed approach for progressivity going up in $12.50
increments. Under Amendment B.4, that bracketed system tops out
at a maximum level of 60 percent, common with the unbracketed
amendments. Under Amendment B.5, that bracketed approach tops
out at maximum of 50 percent.
MR. MAYER said he started by looking at what it does to
breakeven prices in the high cost development example. In this
example, it pushes a 10 percent level breakeven way up into the
$100 barrel range. He explained that is a function of high
marginal takes under the ACES system. Using this mode of
analysis, he said he had noticed a couple of things: that the
base CS along with Amendment B.8 and B.18 look relatively
similar. The significant difference between those and ACES
occurs at higher dollar per barrel oil prices and it increases
as the prices get greater. That is simply a function of the 60
percent cap. At oil prices in the $80 to $100 range, there will
be some differences between them (because of the slightly lower
progressivity coefficient, for instance, under CSSB 192), but
they are relatively minor. The shift in breakeven economics for
the example indicates a shift, but a small one compared to that
in the two bracketed amendments where the result of the
bracketing is to significantly reduce the marginal government
take, and that, in turn, straightens the line and significantly
reduces breakeven prices in the high cost develop example.
MR. MAYER said he had results for each using the low cost
development example, the high cost development example and using
the FY13 numbers. He offered to step through all of them.
CO-CHAIR PASKVAN said they had one hour left and he would defer
to Mr. Mayer's estimation on how long it would take to get
through another two dozen slides.
4:00:35 PM
MR. MAYER started going through the results using the low cost
development example, the high cost example and the FY13 numbers
saying since this was ultimately an exercise in comparison of
regimes the number are comparable across the range. So, the
differences in distinction seen between the amendments in any
given case were largely similar, even if the actual percentage
numbers were different (depending on the cost estimates the
analyses used).
SENATOR FRENCH reminded folks that the low cost field
development assumptions were $10 plus $5, plus $5 plus $7.
MR. MAYER answered yes, and added that the $5 plus $5 are not
strictly additive in any given year, because the initial $5
occurred during developing on a per reserves basis. The
maintenance $5 is every year after production starts.
SENATOR FRENCH asked how he plugged in the reserves CAPEX.
SENATOR MEYER answered that the idea is to say if over the
economic lifespan of this asset, this is the total amount that
will produced, where if he looks at operating costs in a given
year (on a per flowing barrel basis), he could say what it will
cost to produce per barrel in that timeframe. But he couldn't
look at a given year's production to say what the initial
development capital was going to be. The best way to estimate
that is to say the size of the development is indicated by the
total reserves that are going to be recovered. Instead of taking
each year's production, he would take the sum of the production,
and saying in total they are comparable, but one is about the
initial act of development, which occurs before any production
has occurred and one is about an amount based on a given year's
production.
4:03:55 PM
SENATOR FRENCH thanked him and recapped that it's taking into
account everything spent to get the first barrel out of the
ground.
MR. KEPES replied yes; it's the initial development capital. It
depends on different types of development, but you could foresee
a type of development where eight years after production
startup, you may need to re-drill some wells or drill additional
ones to increase the recovery factor, which wasn't quite what
you thought it was going to be. In this case, because the low
cost development is effectively older fields, the additional
development costs have been "smeared out" annually in a uniform
pattern, which wouldn't necessarily be the case with a brand new
field development. That has been called renewal or maintenance
capital and could include replacing pipelines, re-drilling wells
- essentially, what is happening on the North Slope now.
4:05:37 PM
MR. MAYER directed attention to the initial big yellow dip on
cash flow graph on page 10 that occurs before any production has
occurred, the development CAPEX, calculated on a per barrel
reserves basis and noted the ongoing yellow line was the
maintenance capital. While their shape over time is different,
because each is $5 per barrel, they will add up to the same
amount in total. He also noted that the dip in yellow bars
(development capital) and the black line (after tax cash flow),
is not as significantly negative in the early years as the CAPEX
would suggest it might be, and that is the impact of the credits
under ACES.
CO-CHAIR PASKVAN pointed out that Alaska, because of its CAPEX
credits at the early stage of the project, is front-end loading
those costs by a certain percentage, and the initial development
phase is Alaska's contribution to the project. Once production
starts, the black line goes positive to the state.
MR. MAYER agreed except that it would be positive to the partner
that had undertaken the project. The 60 percent progressivity
cap makes a difference in government take occurring upward of
the $140 to $150 barrel range.
4:08:09 PM
MR. MAYER said there is a slight difference early on at lower
prices when you might see 1 percent lower government take
compared to the previous example that comes from the lower
progressivity (.35 percent) coefficient being applied.
SENATOR WIELECHOWSKI asked for the difference between ACES and
the CS in the range from $100 to $130, which is where oil is
expected to be in the next few years.
MR. MAYER turned to slides 22/23 saying that 22 represented what
ACES looks like using the FY2013 inputs and 23 represented what
CSSB 192 looks like on that basis.
He said using the $110 example, since it is closest to the DOR
figures, in the ACES case that equates to $4.78 billion and
under CSSB 192 it equates to $4.512 billion.
4:10:16 PM
SENATOR WIELECHOWSKI commented that last week oil had been
between $120 and $130. And the state take went from $9.952
billion to $9.6 million at $120 (roughly $300 million), and at
$130 it's almost a $450 million spread.
MR. MAYER said that sounded right to him. He explained that
looking at the first amendment, B.8 (simple progressivity) slide
12 indicated the effect of going from $140 to $150 onward on
overall levels of government take is largely similar to that in
the previous example, because the cause of that change is
exactly the same as the cause of the change in CSSB 192, which
is simply the cap being set at 60 percent progressivity. Below
the level at which that cap binds, levels of government take are
essentially identical to the ACES system, because unlike CSSB
192, Amendment B.8 doesn't have the change in progressivity
coefficient from .4 percent to .35 percent.
4:13:18 PM
Instead, Amendment B.18 (slide 13) in many ways lies between the
impact of CSSB 192 and Amendment B.8, meaning that the 60
percent maximum starts to bind above the $140/$150 level, and
therefore levels of government take flatten out. A slighter
effect happens earlier in the price deck; that is because in a
more limited range of prices, there is also a reduction in the
progressivity coefficient from .4 percent to .35 percent, but it
only occurs above the $67.50 production tax value level.
4:14:26 PM
Amendment B.4 (slide 14) showed progressivity bracketed with the
35 percent top bracket and a significantly greater reduction in
overall levels of government take. In this case, at the top end
these come down from the 84 percent under ACES to 79 percent
under CSSB 192 down to about 75 percent in this case. This is
the result of the fact that while the maximum is still being set
at the 60 percent level, the effect of bracketing is to bring
down levels of government take across the entire price deck.
Amendment B.5 (slide 15) showed something similar, but a little
lower, because the lower maximum is set at 50 percent. In this
case the highest levels of overall government take are around 71
percent.
4:16:06 PM
MR. MAYER said the impacts at a high cost development [under
ACES] (slide 16) will be similar in each case just with slightly
different absolute numbers because of the different cost
assumptions, particularly with the FY13 revenue estimate
numbers.
SENATOR WIELECHOWSKI asked if he was assuming payment of the
full 9.4 percent for corporate income tax or something lower.
MR. MAYER answered that he assumed 8.4 percent, which previous
research led them to believe was a reasonable average for the
state of Alaska.
SENATOR WIELECHOWSKI asked if it were a couple percentage points
less than that would it have an impact.
MR. MAYER answered it would have a very small impact. If you
look at the contribution of state corporate income tax to
overall government take, there are questions of deductibility
from other forms of tax and the fact that 8.5 percent or 9.5
percent income tax is on taxable income not on divisible income,
which government take is calculated on. They see something that
ranges from 0 percent to 2 percent of the total for government
take and if that was sliced in half, it might go down 1 percent,
but nothing dramatic.
4:17:44 PM
SENATOR WIELECHOWSKI quipped that cutting production taxes just
gives a more to the federal government and asked if there is
another lever to pull that wouldn't give it to the producers
instead.
4:18:14 PM
CO-CHAIR PASKVAN asked what percentage of government take he
used for federal income tax as his base assumption. They have
heard the actual rate paid is substantially less than the 35
percent. He asked him to walk them through an analogy similar to
the one he did for state income tax.
MR. MAYER responded that this model uses the nominal 35 percent
effective rate. The contribution of federal corporate income tax
to total government take varies between 8 percent and 13
percent. So a substantial reduction could take 1 percent to 3
percent off the total government take figures.
MR. KEPES asked if his question was about going from 35 percent
to 28 percent, which is the latest proposal.
CO-CHAIR PASKVAN said he wanted to give the committee a general
understanding. Also on page 16 and in other charts there is a
federal CIT corporate income tax; that rate is set forth in
various cost structures for the price of a barrel of crude.
4:20:28 PM
SENATOR STEDMAN said some communities have first call on the 20
mil state property tax. PFC figures indicate a total of $400
plus million in property tax with $93 million coming back to the
state. He asked why he wouldn't count all of the property tax
paid by the industry regardless of whom it goes to in that
process.
4:21:42 PM
MR. MAYER answered that may be something he may need to
understand in greater detail than he had at this point.
He went to slides 22-24 modeling high cost developments under
ACES with DOR FY13 estimate inputs. At the $110 level under ACES
government take is an estimated $4.78 billion and that goes to
$4.512 billion under CSSB 192. Mr. Mayer said they get something
almost indistributable from ACES at that price level for
Amendment B.8, the reason being that it doesn't have the impact
of the low progressivity coefficient and the reduced cap doesn't
bind at that price level.
SENATOR STEDMAN asked him to explain why the yellow bar goes
below the Y axis on slide 22 (the current system).
MR. MAYER explained in this $40 case, you see negative
production tax value, and that will occur in low oil price
environments for almost any project. Where in the price deck it
occurs will depend on project economics. The reason it occurs is
because at that price level the project as a whole is probably
no longer profitable. It certainly doesn't generate production
tax value. So, before capital credits and other credits, its
production tax liability is zero. Over and above that, however,
if the project is spending capital and accrues a 20 percent
capital credit, that is reimbursable regardless of the fact that
there is no production tax liability against it. In that case,
the effective production tax after capital credits have been
included is negative, and that is why the yellow bar goes below
the Y axis.
He emphasized that in this case, while it's negative at $40 a
barrel, the overall level of government take and state
government take is still very high, because of the regressive
nature of things like royalty, which is still coming in
significantly from the project. In this instance it is greater
than that negative payment and probably consumes almost the
entirety of the cash flow from that project.
4:24:57 PM
SENATOR STEDMAN said at $40 a barrel, government take is 112
percent, and asked if he could infer that under the current
system.
MR. MAYER replied that the divisible income from the project
isn't enough to cover all the taxes that are paid on it in that
case. The best way to visualize this is to use the example from
his last testimony in looking at the impact of a flat royalty
over different cost structures, some with marginal economics,
because they had very high costs relative to the oil price. The
impact of the royalty may be to take up all the divisible income
or in some cases more. That is possible for any project that
faces a flat royalty; it is a question of what oil price that
occurs at and what the cost structure is.
SENATOR STEDMAN asked if that is because royalty gets first call
on the income stream.
MR. MAYER answered exactly. It's because royalty is measured on
a gross basis before costs and other things are considered.
He continued that Amendment B.8 at the $110 level (slide 24) is
largely the same as the current system. There is a slight
reduction in the modeled revenue at the $110 level under
Amendment B.18, but it is less than under CSSB 192. The reason
for that is because the reduced .35 percent progressivity
coefficient in this case applies only at prices above the $67.50
mark not to the entire price deck.
4:27:25 PM
He said Amendment B.4 (slide 26) forecasts revenues of $3.27
billion at the $110 mark and a similar rate under Amendment B.5
(page 27), the difference being that the greater differences
occur at points higher in the price deck.
4:28:03 PM
MR. MAYER went next to graphs of average marginal take occurring
to these systems (slide 28); the one on bottom right looks just
at the production tax component of the ACES regime; the axis on
the bottom looks at that against production tax value - to see
what that means, both in terms of the system as a whole and in
terms of the oil price - instead of the technical question of
production tax value. The graph in the upper left looks not just
at ACES and the particular tax rate that is paid, but on the
left axis has a total level of government take, either a
marginal rate or an average rate and what that looks like over
the course of the price deck. For instance, under ACES they see
relatively high marginal rates going up to high $80s and low
$90s under ACES, picking up at the $92.50 production tax value,
which is where the coefficient goes from being .4 percent to .1
percent. In the context of the system as a whole, that means at
oil prices of $110 to $130 range they see very high marginal
rates and the peak that one sees at that point in the price deck
in the overall system is the same peak as the one from
production tax value in the bottom right graph.
MR. MAYER said on the next slide (29) CSSB 192 does two
different things; the peak of marginal take under CSSB 192 is a
little lower and the slope going up to it is a little more
gradual and that is simply a function of 3.35 percent
progressivity coefficient. It still has the same sort of saw
tooth profile. But the production tax value graph drops down and
is equal to the average rate at production tax values around
$200 to $210 mark, which is where the 60 percent cap on
progressivity starts to bind.
4:31:11 PM
CO-CHAIR PASKVAN asked him to explain the difference between
production tax value (PTV) and the price of oil.
MR. MAYER explained that PTV per barrel of oil is a tangible
concept that underpins ACES and all systems envisioned by the
various amendments. It's a number that is arrived at by taking
the revenues from selling oil, subtracting the costs and
dividing by the total taxable production.
CO-CHAIR PASKVAN asked him how the effective tax rate layers on
top of everything.
MR. MAYER answered for their purposes here "effective" and
"average" mean the same thing. The important thing to understand
in that context is that the average rate is the rate at any
given price level that is actually paid; the marginal rate is
the rate that comes when he looks at if the price of oil
increases by a dollar a barrel how much he gets to keep and how
much goes to tax.
4:34:17 PM
MR. MAYER went to Amendment B.8 (slide 30) and noted that
earlier in the price deck they have exactly the same profile as
under ACES with the sole difference being the second saw tooth
where the marginal rate comes down (in the bottom right graph)
to the 60 percent level, which is where the 60 percent cap
binds.
Further, looking at Amendment B.18 (slide 31), Mr. Mayer pointed
out a slightly more complex profile of the marginal rate, which
is the impact of the initial .4 percent progressivity
coefficient with a reduction to .35 percent somewhere in the $60
range, and marginal tax rates under PTV still getting up to the
$80s but not quite as high as they were otherwise. And then
after that the same profile as under CSSB 192.
4:35:29 PM
MR. MAYER said the bracketed systems are very different. In
particular, there are no dramatic peaks in either very high
marginal tax rates for the PTV or high marginal rates of
government take, and that is simply the impact of the bracketed
approach to calculating these things. As a result, the average
rises more slowly. That means a number of things in this
context. Slide 34 shows the sensitivity of project value over
crude prices and it's the lower levels of marginal take under
the bracketed systems that increase the slope of the line for
both, and that makes a significant difference, in this case, to
project breakeven pricing.
Second is the question of the impact of high marginal rates on
what companies spend in their capital budget, the gold plating
issue, when one faces a very high marginal tax rate, there may
be incentives to spend more on a given project than one might
otherwise simply because the high marginal tax rate means that
effectively the share of additional spending one has to bear
one's self is relatively low.
4:37:40 PM
MR. MAYER went back to slide 33 and pointed out that Amendment
B.5 looks a lot like Amendment B.4, but the peak of the marginal
rate and the average production tax rate that follows it is at
50 percent instead of 60 percent, and correspondingly one sees a
big marginal rate well under 80 percent in the case of Amendment
B.5.
4:38:12 PM
SENATOR MCGUIRE referenced his last point about marginal
taxation and that Pedro van Meurs had talked to them about the
concept of efficiency in projects and the tendency for companies
to want to gold plate when marginal rates go up, and asked if he
would say that is how inefficiencies get built into the system.
MR. MAYER replied that it's possible that there may be perverse
incentives under systems with a high marginal rate.
4:39:15 PM
SENATOR MCGUIRE said Alaska offers credits in an unusual way;
they forward fund them and don't force companies to carry them
forward into their tax liability. Alaska allows companies to
turn in credits for cash unlike other countries like Australia
that makes companies carry them forward to when they have tax.
She asked if Alaska would be better off to lower its
progressivity rate and perhaps correct what it's doing with
respect to credits - either reduce the amount or force them to
be carried forward against the actual tax liability - to build
more efficiency into the system.
MR. MAYER responded that this is one of the issues that this
committee and the legislature as a whole needs to grapple with.
PFC has been doing a lot of research and analysis on it.
SENATOR MCGUIRE said she wanted to know if Alaska would be more
competitive by lowering the progressivity rate and adjust the
way they do credits. Where would the "sweet spot" be? And did he
have any information about whether companies look at these
credits in decision making? It didn't seem like companies were
factoring them in.
MR. KEPES replied that companies do factor them in and they also
take them as a signal of the government's or state's intent in
terms of investment climate. Maybe the existing credit structure
is incenting investments in part of the production base, but not
in terms of new projects, for instance.
4:43:33 PM
MR. MAYER added looking at the ACES regime on slide 16 and using
the high cost development as an example, that the reason the
economics of a project like this are particularly challenged is
just because of the very high upfront capital cost. It is
somewhat ameliorated in this case by the 20 percent capital
credit, but the problem is that it's not sufficiently
ameliorated to make up for the overall challenge of the
economics.
MR. KEPES said companies often look at how much capital they are
out in any one year. So, if they are out $2.3 billion at peak
before they can get a project on stream that is a risk metric
for them. They wouldn't want to do that in Ecuador, for
instance, but would feel better about doing it in a place like
Alaska.
CO-CHAIR PASKVAN remarked that another way of saying "risk
mitigater" is that Alaska is attractive in regard to its
credits.
MR. KEPES agreed; if you compare Alaska and Ecuador, Alaska is
more attractive for a number of different reasons, not just
because of the government.
4:45:43 PM
SENATOR FRENCH asked to go back to slide 11 and asked for more
discussion on the internal rate of return graph.
MR. MAYER explained that the chart provided an indication of
what some very rough project economics look like for the generic
low cost development example across a range of different cases.
The numbers are more instructive in terms of comparison between
the different fiscal scenarios than they are in their own right,
since this isn't an actual project. If they look at the $100
level, they see an increase in the overall project net present
value, that being the discounted value today of the future cash
flows of the project, from in this case $712 million to $756
million. That comes almost entirely as a result of the decrease
in the progressivity coefficient from .4 percent to .35 percent,
since at the $100 level the 60 percent cap isn't binding.
4:47:08 PM
SENATOR FRENCH asked him to talk about what the 23 percent
figure means for IRR.
MR. MAYER answered that IRR means Internal Rate of Return, which
is another benchmark metric that is often used in terms of
project evaluation and approval. On the one hand, net present
value (NPV) enables one to get a sense of the absolute level of
value of a given project, but it's less useful in comparing very
different projects with each other, because it doesn't say much
about where the value comes in terms of time value of money. It
becomes quite difficult to compare very expensive projects with
relatively cheap ones. IRR can be more useful for that. He said
companies may have particular IRR benchmarks as one first filter
in the process of capital allocation that may be lower in
developed countries than in developing countries where probably
a company would expect to see a 15 percent rate of return at a
minimum and in many cases significantly higher, as a hurdle,
depending on a range of things.
SENATOR FRENCH said they had heard the 15 percent number used
before as a benchmark for investment and asked what would happen
to that IRR using $120 as the price - for something at Prudhoe
Bay.
MR. MAYER said he didn't want to give a precise answer, but it
would be further up in the 20s.
SENATOR FRENCH asked if drilling an infield well at Prudhoe Bay
would be a low cost development.
MR. MAYER replied that he wouldn't want to go so far as to say
that somehow these particular figures apply to that, but that is
the general idea. One of the key things to grasp here is that
there absolutely are profitable forms of investment on the North
Slope at the moment, and they are ongoing as they speak. Capital
is being spent on the North Slope both on renewing and
maintaining old facilities that were built to last 25 years and
now require significant investment if they are going to keep
going. Doing a range of well work going from what otherwise
would be a 15 percent decline curve to a 6 percent decline curve
involves a lot of capital, but there are healthy returns to be
had by spending that money, and that is why it is spent.
He said as soon as one gets away from the established
infrastructure and starts drilling much more challenging wells
into viscous oil reservoirs, if one has to build a sand island
to put production facilities on, these things suddenly start
costing much, much more money. When that's the case, you see
much more challenged economics in the high cost example.
4:50:56 PM
SENATOR FRENCH said they talked about how the state might be
$2.3 billion out of pocket for total costs before money starts
coming back and asked how the state could improve the economics
of a $2 billion field if it wanted to invest $500 million
alongside that private investment.
MR. KEPES asked if he meant the state would take an equity
stake.
SENATOR FRENCH answered yes.
MR. MAYER replied that doesn't change the ROR; it just means
that ROR applies to both.
SENATOR FRENCH added assuming that the state wanted to
participate at the exact same ROR.
MR. MAYER responded that the state is putting in its share of
the capital as an equity partner, but it's also taking out its
share of the cash flows and the impact of those two things is
neutral.
MR. KEPES added unless the state is willing to pay "a promote"
to the operator in place. In theory, if Chevron asked BP to
"farm into 25 percent of this and I'll pay $500 million," and
they want it badly enough, BP might charge them a promote where
Chevron would actually pay an additional amount just to enter.
That could make the ROR different.
SENATOR FRENCH asked if the buy-in partner is willing to take a
lower ROR, the economics for the other entity could be improved.
MR. KEPES said that was correct.
4:53:08 PM
SENATOR WIELECHOWSKI asked his sense of the North Slope where
legacy fields are relatively low cost, high ROR, high profit
margins, but then there's some new exploration, which is
probably not as lucrative - in other words, a blended portfolio.
He said the way ACES is structured that investing in high cost
fields actually lowers tax rates on the low cost fields as well.
MR. MAYER said that was true, that effect occurs, but it's a
relatively marginal effect. For instance, looking at the
hypothetical high cost development in the context of an existing
portfolio, two things could occur to improve the economics
compared to what it looks like to a new operator starting from
scratch. Those are the ability to not only take capital credits
for the initial capital spending and deduct those from existing
production and, second, the question of whether in that process
of blending the average rate is reduced and that's a marginal
benefit. In a case like this, by and large, they don't change
the fundamentals of the question of very high costs combined
with an overall high level of government take making a project
very challenging.
4:54:54 PM
SENATOR WIELECHOWSKI said if the policy for the state was to
encourage new higher cost developments that a couple of
amendments provide allocations for different ways of doing it,
and asked if he had looked at them.
MR. KEPES replied no.
MR. MAYER said he had looked at them very briefly, precisely
because they were more challenging to model. Aspects of those
regimes don't look at total government take and total revenue,
but what it looks like if it's a new project versus an existing
project.
CO-CHAIR PASKVAN said they see low cost developments and
translate that to the legacy fields. Yet they look at the fall
2011 Revenue Source Book and see the figure north of $37 for
transportation, OPEX and CAPEX and asked why that is different
than the $22 Mr. Mayer is using.
MR. MAYER replied like any process of averages, you have a very
wide range of extremes. By simply looking at a mean, one loses
all of the data on the granularity and it's particularly crucial
to understand that as they think about this. Because the
economics of what ACES looks like is very different for a mature
asset that has just enough capital being spent on it to keep it
on a particular decline to what it looks for a brand new high
cost development far from infrastructure. And to the extent that
it's the difficult oil that is going to provide incremental
barrels to make up for some of the decline, that is what needs
to be incentivized through a fiscal system that is not currently
happening.
MR. KEPES added that it looks like ACES is a fiscal system
designed to get the maximum out of a harvest area as opposed to
using it in a growth area.
4:58:36 PM
SENATOR WIELECHOWSKI asked if they had looked at the exploration
credit aspect of ACES and what sort of credits companies get for
new exploration.
MR. KEPES replied that they had looked at that, but hadn't
prepared formal testimony on it for today; it hadn't been their
primary focus. They focused on things that would impact the
state of Alaska over the next 10 or 12 years from a revenue
perspective.
SENATOR WIELECHOWSKI asked if they understand exploration
credits.
MR. MAYER answered that the principal one is the exploration
credit that can be up to 40 percent.
CO-CHAIR PASKVAN thanked the presenters and held SB 192 in
committee.
| Document Name | Date/Time | Subjects |
|---|---|---|
| PFC Energy_Requested Additional Analysis of Possible Progressivity Caps_02-27-2012.pdf |
SRES 2/29/2012 3:30:00 PM |
SB 192 |
| PFC Energy_REVISED_Senate Resources_Slides_Feb_17_2012.pdf |
SRES 2/29/2012 3:30:00 PM |
SB 192 |
| PFC Energy_CSSB192 and Amendments_02-29-2012.pdf |
SRES 2/29/2012 3:30:00 PM |
SB 192 |