Legislature(2013 - 2014)BUTROVICH 205
02/15/2013 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB21 | |
| Presentation: Pfc Energy | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 21 | TELECONFERENCED | |
SB 21-OIL AND GAS PRODUCTION TAX
CHAIR GIESSEL announced SB 21 to be up for consideration and to
start the Department of Revenue would walk through the
complexities of progressivity.
3:32:08 PM
MICHAEL PAWLOWSKI, Petroleum Systems Advisor, Office of the
Commissioner, Department of Revenue (DOR), Juneau, AK, said the
intent of the presentation was to give members a general walk
through of the actual mathematics of how progressivity works and
then to talk about some of the issues that the department has
identified in progressivity that have caused concern. He noted
that a lot of these issues are about the aggressivity of the
progressivity, specifically about the math of the equation in
the current system.
He said he would first walk through the calculation of the
production tax liability and then second how the basic
progressivity calculation works; and finally go through what the
administration has identified as some of the problems with it.
He invited Mr. Stickel to walk through calculating the
production tax liability.
3:34:06 PM
DAN STICKEL, Assistant Chief Economist, Department of Revenue
(DOR), Juneau, AK, said the basic calculation of the ACES tax
liability is: production tax value times your tax rate minus
your credits. Production tax value is: the value at plant
production (volume of oil and gas produced times the wellhead
value). In calculating the wellhead value you subtract:
transportation costs to get it to market, operating (Opex) and
capital (Capex) expenditures in the year earned in calculating
production tax value (the tax base). The base rate is 25 percent
plus an additional .4 percent for every $1 per barrel that the
production tax value exceeds $30/barrel up to $92.50/barrel, and
then at $92.50 that turns into a .1 percent slope. The credits
are subtracted from that (primarily the 20 percent credit on
capital expenditures as well as small producer credits and
transitional credits).
MR. PAWLOWSKI said the progressivity function itself is found in
AS 43.55.011(g). He reiterated that the progressivity doesn't
begin to get calculated until production tax value exceeds
$30/barrel of oil (deducting transportation costs). As soon as
it goes past $30 a barrel, the tax rate increases .4 percent per
$1 until the production tax value exceeds $92.50/barrel when it
flattens out. The maximum tax rate of the progressivity portion
is a 50 percent tax, which when combined with the base tax is 75
percent. Progressivity itself is calculated monthly and it is a
single statewide calculation on all oil and gas revenues.
3:36:03 PM
SENATOR MICCICHE asked if there are any eligible transition
expenditures that are still in use.
MR. PAWLOWSKI replied that he would get back to him on that, but
he understood that those are repealed in SB 21.
3:36:54 PM
SENATOR DYSON joined the committee.
MR. PAWLOWSKI said the basic calculation as it appears in the
2012 Fall Revenue Sources Book begins with the base assumption
of 170,262,000 barrels of taxable production (royalty oil not
included). The equation begins with an ANS West Coast price of
$109.61/barrel as forecast by the department. Transportation
costs of $8.81/barrel are subtracted from that, which results in
$100.80/barrel gross value at the point of production (wellhead)
of. The deductible lease expenditures are subtracted from that
to arrive at the production tax value. So, the Fall Revenue
Sources Book shows an operating expenditure of $16.32/barrel and
a capital expenditure of $19.61/barrel, for a production tax
value of $64.87. The base tax of 25 percent is applied against
that production tax value. So the base production tax in the
example would be around $16.22/barrel. Those are the basic
numbers to begin to calculate the progressivity function.
Calculating the progressivity function begins with the
production tax value of $64.87/barrel minus the $30/trigger,
which results in a value of $34.87. Because that production tax
is less than $92.50, the amount of the percentage increase
applied to this number is .4 percent. So, $34.87 times .4
percent is roughly the equivalent of 13.95 percent (therefore
the progressivity in this example is 13.95 percent). This 13.95
progressive tax is then applied to the production tax value per
barrel of $64.87 (not the $34.87). So, $64.87 times 13.95
percent equals $9.05/barrel; therefore the $9.05/barrel
progressive tax plus the 25 percent base tax of $16.22 results
in a $25.27/barrel production tax (before the credits are added)
multiplied by the taxable production results in $4,302,000,000
in production tax revenue.
3:40:04 PM
SENATOR FRENCH said it struck him that for all the wailing and
gnashing of teeth about progressivity it accounts for just $9
out of $109/barrel of oil, and it doesn't appear to be a
dominant aspect of the taxation system. He asked where the gross
value at point of production is on the North Slope.
MR. STICKEL answered that includes all of the netback costs,
everything that it takes to get from the unit boundary to the
destinations: the feeder pipelines, TAPS tariff and tinker
tariff.
SENATOR FRENCH asked if it is just upstream of the pipeline tie-
in or downstream of the production facility. Do the feeder pipes
count between the production facility and the pipeline or no?
MR. STICKEL replied that it depends on whether it's a regulated
pipeline or if it's within a unit boundary and he offered to get
a technical definition.
SENATOR FRENCH said he understood that it is basically
downstream of the production facility (after everything has been
taken out) but before the feeder pipe; yet it's called a
wellhead price.
MR. PAWLOWSKI commented that the wellhead is generally for
calculating royalty. There is a general synergy between the
point of production and the wellhead, but they are not the exact
same number because of getting different treatment under the tax
- particularly when it comes to the allowable deductible costs
for a shipper that has an affiliated ownership in the TAPS (that
gets a regulated treatment by the Department of Revenue).
3:42:23 PM
Some of his preliminary observations about the progressivity
mechanism were:
-It increases the overall tax rate as the overall profitability
rises. The progressivity in the production tax itself is one
component of the overall fiscal system. After that is
calculated, then state and federal income taxes are also levied
on the remaining net profit of a barrel.
-Progressivity is company specific and each company will have a
different exposure because progressivity is sensitive to:
-the oil price
-spending
-production
-Progressivity is only one part of what makes the overall system
progressive; it is not a factor at all at low oil prices ($30
net). He explained that the combination of credits and
progressivity creates the linear slope that is different than
the slope in SB 21. They don't want people to forget about the
credits while talking about progressivity in the overall
picture, and this presentation will only talk about the
progressivity.
SENATOR DYSON commented that progressivity isn't triggered until
you get $30 over the combination of Capex, Opex and
transportation costs, but once it is triggered, it goes back all
the way to the Capex and Opex.
MR. PAWLOWSKI agreed and added that it's important to note that
in the beginning of calculating the progressivity, $64.87 minus
$30 gives one a number that is used to determine the tax rate,
not the number that the tax rate is applied against. The
production tax value is the number against which both the 25
percent base tax and the progressive tax rate are applied
against.
3:45:28 PM
Next Mr. Pawlowski walked them through the sensitivity of the
progressivity function example based on the same numbers but
changing one number in the equation, increasing the capital
spending by $500 million. In this example, the exact same
transportation costs results in the same gross value at point of
production; the deductible lease expenditures and the operating
cost are the same at $16.32, which raises the Capex/barrel to
$22.55 dropping the production value from $64.87 to $61.93. The
base tax is reduced from the previous example by 25 percent
against the $61.93 which results in $15.48. Calculating
progressivity starts with $61.93/barrel (instead of $64.87). So,
doing the same walkthrough: $61.93 minus $30 equals $31.93.
Since that $31.93 is less than $92.50, that is multiplied by .4
percent, which results in a progressive tax rate of 12.77
percent, which is applied to the $61.93, which results in the
progressive tax of $7.91/barrel. So, one sees as capital
spending goes up, the production tax value has dropped, as has
the corresponding calculation of the progressivity.
The combination of the progressive tax and the base tax results
in $23.39/barrel (before credits) multiplied by the taxable
production. That shows state revenues declining to
$3,983,000,000. Therefore, in looking at the impact just from
the progressivity, of spending $500 million in capital, state
revenues went down $319 million before considering the cost of
credits (similar to what Econ One presented earlier).
3:48:24 PM
He said the department's preliminary observations were:
-Progressivity based on the net production tax incentivizes
spending.
-The level of the incentive depends on the price of oil and the
cost structure of the investor not the relative economics of the
project. The $319 million is a function of the operating and
capital costs per barrel, the price of oil in the market and,
therefore, not linked directly to a specific project or
improving the overall economics.
-The value of this deduction often exceeds the credits. In other
words, when we think of 20 percent of $500 million, what we see
is really $100 million. So, $500 million in capital spending
would accrue $100 million in credits; and in this example, $319
million worth of buy down value in the progressivity equation.
So, because of the price of the oil in the cost structure, the
value of the progressivity buying down is actually much higher
than the value of the credit.
-This benefit is only available to an incumbent producer that
has a tax liability and doesn't create a level playing field
with new entrants accounting for the difference in government
take levels for a new entrant versus an incumbent producer.
3:49:12 PM
SENATOR FRENCH said he would add "in Alaska" to the first bullet
point, "progressivity based on the net production tax
incentivizes spending - in Alaska." If that extra $500 million
is spent overseas, then Alaska gets nothing.
MR. PAWLOWSKI responded that Alaska would get the additional tax
revenue of that spending going elsewhere.
SENATOR FRENCH said his only other point was that Mr. Pawlowski
had selected the number of $500 million, but in reality which of
the oil companies doing business in Alaska would increase their
capital spending by that much.
MR. PAWLOWSKI replied that it would be easy to foresee a
combination of companies currently doing business in Alaska
doing it or some of the newer entrants. He thought it was a
fairly reasonable number and it was a round number to use as an
example.
SENATOR FRENCH asked if he agreed that a $500 million increased
in capital spending in one year would be a significant increase.
MR. PAWLOWSKI answered absolutely.
3:51:41 PM
SENATOR MICCICHE asked if the small producer credit would offset
the benefit.
MR. PAWLOWSKI answered that it offers a definite benefit to the
small producers at $12 million/year, but one that is not
commensurate to the scale of the upfront buy down.
SENATOR MICCICHE said he thought that would be almost a direct
offset for the small quantities the small producers are
producing, but he could be wrong.
MR. PAWLOWSKI offered to work with him on the economics of that
premise. His next example took the same $500 million but
decreased the oil price by $10 (using $99.61 instead of
$109.61), the same transportation costs, but the gross value at
the point of production is lower ($90.80), because of starting
from lower oil prices; the same operating expenditures of
$16.32/barrel and same capital expenditures of $22.55/barrel and
that resulted in a production tax value of $51.93/barrel. The
base tax 25 percent would be $12.98. Calculating the
progressivity from that $51.93, minus $30, results in
$21.93/barrel. Again, since it's below $92.50, $21.93 times .4
percent results in a progressive tax rate of 8.77 percent;
$51.93 times 8.77 percent equals approximately $4.56/barrel.
Therefore, the $4.56, plus $12.98 base tax results in a
$17.54/barrel production tax before credits, multiplied by the
taxable production. Running the same equation without the
additional spending derives revenues of $3,265,000,000.
He explained that one sees the benefit of the deduction of that
additional $500 million in spending at a higher oil price was
worth $319 million, but the oil price falling $10 reduced the
value of that deduction to $279 million. This illustrates that
the value of the deduction is largely dependent on the price of
oil when the deduction occurs.
He observed:
-Since the value of a deduction is dependent on the price of
oil, it's very difficult for a company to predict its value,
especially with long lead time projects. So, if the value of
one's benefit depends entirely on the price of oil in the year
you happen to be spending the capital, looking out 3-5 years for
an investment is a different thing than looking at the near
term, next year. And given the degree to which that benefit can
fluctuate, that is a fundamental problem within the
progressivity structure.
-The reduction in taxes is temporary, since as soon as the
spending is done the tax rate rises back to the higher rate.
-This effect can potentially create misalignments amongst
working interest owners in the same field. For instance, if one
working interest owner is spending and another isn't, then the
value of the incremental spending to that company that is
already spending will be less than to the one that isn't
(because of where they are in their progressivity equations).
Again, the value is based on an equation and not the project
economics that they are all working on together.
3:56:25 PM
SENATOR FRENCH said he knew the point he was getting at, but he
must be really careful in expressing it. Working interest owners
in the same field have to be aligned when they make investment
decisions or they don't happen; Prudhoe Bay requires unanimity.
MR. PAWLOWSKI said he appreciated the clarification. Because
unanimity is needed to move forward in some of these fields, one
of the participants may be in a different tax place than the
others, so there may be an actual material benefit to one of the
working interest owners to wait to harvest that progressivity
benefit as opposed to another. He thought that was offset to a
large degree by how they actually can look at the value of that
deduction in planning out into the future. However, for short
term there could be a difference in the working interest owners
for the maintenance spending and capital infrastructure and
those types of things. This is not a major problem with
progressivity but just a potential concern that he saw in
running through the scenario.
3:58:24 PM
SENATOR DYSON asked why one of those companies couldn't have an
opportunity to increase production significantly with expenses
on their portion of the lease.
MR. PAWLOWSKI answered that it goes back to what Senator French
talked about; at the margin things can be done by an individual
company within a lease depending on the actual structure of that
working interest in the relationship of the unit agreement, but
for bigger decisions having different tax rates with multiple
companies that are all working together can potentially create
problems.
SENATOR DYSON asked if it's not dependent on what part of the
field they own.
MR. PAWLOWSKI answered no; their individual tax rates depend
basically on their overall activity in Alaska not at the field
level. So, in that a company may have different activities than
their other partners, they will be in different tax places, and
that creates an interesting question of how that actually works
in practice and if the progressivity creates potential
misalignments. He said the administration was consistently
concerned about where the potential misalignments are in the
current tax system.
SENATOR DYSON said he was talking about the different leases
they own and whether or not they can produce more oil.
MR. PAWLOWSKI said he would invite Mr. Balash to talk about
actions within the units.
4:00:46 PM
JOE BALASH, Deputy Commissioner, Department of Natural Resources
(DNR), said that type of scenario is one they may have seen 15
years ago with multiple operators in the same unit at Prudhoe
Bay. But after the merger between BP and Arco the operatorship
was consolidated into the hands of a single company. His
understanding of how the unit operating agreement functions
between the owners is that a single operator carries the
responsibility of the day-to-day business and then brings
forward projects to the other working interest owners for
approval through the AFE process.
4:01:45 PM
MR. PAWLOWSKI made a final observation that the state gives a
greater incentive to a company spending money at high prices
than at lower prices for the same expenditure - the opposite of
what is needed to make projects economic - if you are purely
looking at it from the progressivity perspective in terms of
what the state is giving as a benefit.
He turned to another example of what happens in the
progressivity equation when a company cuts its costs. In this
example he went back to the $109.61/barrel (WC) and instead of
increasing spending he cut spending by $5/barrel. So, $109.61
minus the same transportation costs for a gross value at the
point of production (GVPP) of $100.80. The same Opex of
$16.32/barrel but this time a Capex of $14.61 gives a higher
production tax value of $69.87 than the initial example
($64.87), but all that has changed is the $5 less in capital
spending. The base tax goes up to $17.47 (25 percent against
$69.87 is more than 25 percent against $60.47).
4:03:41 PM
In calculating the progressivity, he said one starts with the
production tax value (PTV) of $69.87 minus $30 times .4 percent
resulting in a progressive tax rate of 15.95 percent. Multiplied
against the $69.87 results in $11.14/barrel and adding that to
the base tax results in $28.61/barrel production tax (before
credits).
Going back to the first example before the $5 less in capital
was spent; taxes were $25.27/barrel; now they are $28.61/barrel.
Therefore, a reduction in capital cost per barrel of $5 actually
leads to a tax increase of $3.34/barrel. With progressivity the
producer keeps $1.66 of the $5 in cost savings; without
progressivity the producer would keep $3.75 of the $5 in cost
savings. The purpose of this illustration was to show that
cutting costs and increasing taxes can lead to distortions in
decision-making and behavior.
MR. PAWLOWSKI said technology allows one to do the same thing
cheaper, but with progressivity that could actually lead to tax
increases; it's just the nature of the mathematics of the
progressivity itself. It creates the same effect as cutting
costs because it increases the production tax value and
therefore, the progressive tax rate.
He said according to the administration's consultant, similar
things that reduce the production tax value reduce the tax rate
and there is a much stronger incentive to keep costs under
control without progressivity.
Next he said Mr. Stickel would walk through what happens when
there is a major gas sale, which has been talked about over the
years as "de-coupling."
4:05:51 PM
MR. STICKEL said he picked a nice round number for this example
of 1 bcf/gas/day at a price of $8 and a transportation cost of
$4.50/mmbtu. On a barrel of oil equivalent basis he used the
ratio of 6:1 oil to gas and this would just illustrate one
potential set of numbers for a gas sale to show what the impact
of the gas sale is.
He explained that the average price per barrel of oil equivalent
actually drops by including the gas. A $48/barrel of oil
equivalent is the gas destination value, and on a barrel of oil
equivalent basis, the transportation costs increase and the
total gross value at point of production per barrel of oil
equivalent becomes $79.79. With the same per barrel of oil
equivalent lease expenditures, one's production tax value per
barrel of oil equivalent under ACES drops to $43.86 from $64.87
from before the gas sale; the base tax (25 percent) will
increase a little to $10.97.
4:08:10 PM
MR. PAWLOWSKI explained that the de-coupling dilemma was a
problem that was thoroughly discussed in the 26th Legislature;
it is exacerbated by the aggressive net-based progressive
function, and it's when a high value product (light oil) is
blended with a low value product (gas), because you are moving
is the blended price of the two commodities together, which
walks through the equation in the relationship to progressivity
in the same way as a reduction in price would naturally.
Adding the 1 bcf/gas/day (lower value product) to the higher
value light oil leads to a lower oil value per barrel of oil
equivalent and functionally reduces the state revenues before
credits from $4,302,000,000 to $3,096,000,000. So, bringing the
low value gas on line when you have a net based progressivity
reduces revenue to the state. The values are drug down because
they are linked together.
4:09:42 PM
SENATOR MICCICHE referred to slide 17 with $109 ANS price.
MR. STICKEL said they assumed the $109 for the oil being sold
and averaging in the $8 per 1/btu gas; and on a barrel of oil
equivalent basis the weighted average price is $93.39. The way
the ACES tax works, if you have a major gas sale, that gas is
converted to barrel of oil equivalent on the ratio of 6
mmbtu/gas equal to 1 barrel of oil.
MR. PAWLOWSKI said what they see happening is 170,262,000
barrels produced at $109.61/barrel; then they're seeing
60,833,333 barrels of oil equivalent produced at $48/barrel. So,
that lower value gas blended with the higher value oil is all
rolled together into the net calculation which leads to a lower
overall price for the total product stream.
4:11:24 PM
SENATOR MICCICHE asked why transportation costs go up if they
are averaged together; it's a pretty substantial jump.
MR. PAWLOWSKI replied because the cost of moving the gas is in
relationship to the value of the gas much higher than it is for
moving a barrel of oil. The tariffs on any gas pipeline would
generally be much higher as a portion of the value of the
product than it is for moving the liquid oil. In this example,
they see transportation costs of $4.50 on an $8/gas price versus
transportation costs of $8.81 for oil on $109 price. It's just a
function of it being much more expensive to move a much lower
value product. And when all of that rolls in together, one sees
a substantial reduction in state revenue when the gas is
produced alongside the oil. That's because the overall value of
all of it has been brought down and that .4 percent
progressivity moves the total value down. So rather than a
progressive tax of 13.95 percent, you move to a regressive tax
of 5.55 percent. And the tax rate drops dramatically as opposed
to just producing the oil.
4:12:39 PM
His general summary was that progressivity is fundamentally not
simple, and that is because:
-It reduces the cash margin per barrel in ways that leaves
Alaska uncompetitive. That is where the administration started
to look at the impacts of progressivity. Once you are in the low
spending, cash generation phase of these long life time
projects, progressivity goes up.
-It is highly sensitive to price, making it difficult to predict
for the state of Alaska and taxpayers. So if a taxpayer is
looking forward to a long term investment, any benefit from
progressivity is basically dependent on what the price of oil
happens to be when that investment is made. It may work for
short term decisions, but not well for long ones.
SENATOR BISHOP commented that it seems that it could take a
common sense approach out of when a producer would actually
would want to do their front end work to get more oil out of the
field, because at high prices the math doesn't work as well as
at lower prices, making it less advantageous to develop a field
from the investor's perspective.
MR. PAWLOWSKI agreed and added that the higher prices make it
worse than the lower prices from the investor's perspective. It
creates misalignment potentially in that it incentivizes
spending, because that short term decision is easy to make under
the progressive system. The tax rate is changing monthly not
annually and if an investor is looking at a long term - 3-5 year
-Big spending investment, looking through the lens of a tax rate
that is changing monthly over that entire time period based on
oil prices which no one has any control over is not easy.
-It creates misalignments between working interest owners based
on individual spending programs.
-It incentivizes spending but not necessarily investments that
lead to production
-It mutes the incentive to save costs or utilize technology.
-It creates and exacerbates the de-coupling dilemma.
4:16:29 PM
SENATOR MICCICHE said progressivity exacerbates it, but it
doesn't eliminate the high cost of transportation off the North
Slope.
MR. PAWLOWSKI said that was correct.
SENATOR GIESSEL thanked Mr. Pawlowski, Mr. Stickel and Mr.
Balash.
^Presentation: PFC Energy
4:17:06 PM
CHAIR GIESSEL announced the committee would next hear from
consultant Janak Mayer with PFC Energy. He would discuss
competitiveness and answer questions that were submitted through
the letter of intent that was written by the TAPS Throughput
Committee. She also mentioned a quote from Jean Colbert an
economist and minister of finance under King Louis XIV of France
in 1619, that amused her: "The art of taxation consists in so
plucking the goose as to get the most feathers with the least
hissing."
4:18:00 PM
JANAK MAYER, Upstream Manager, PFC Energy, consultant to the
Legislature on oil and gas taxation and fiscal reform for the
State of Alaska, said that PFC Energy consults specifically in
the field of oil and gas. They look at questions of above-ground
risk in oil and gas operations that covers a wide range of
things from geopolitics to understanding the dynamics of oil and
gas markets, supply and demand in different countries,
commercial strategies of major national and international
companies, and questions of project economics and fiscal
structures.
4:19:50 PM
Putting things in context, Mr. Mayer said he would look at a
couple of very simple sensitivities of future cash flows from
petroleum to the State of Alaska that are outside of government
take under the fiscal system. The biggest one is the price of
oil. For example in a hypothetical world of a steady $140 price
and looking at the current declining forecast, revenue to the
state from oil and gas taxation could be as high as $12 billion
a year or as low as $2 billion. But a $60 price could create "a
massive variation that dwarfs everything else that we might talk
about in terms of either new production or fiscal systems change
or any of the rest."
SENATOR FRENCH asked if his state take of at $140/barrel in 2022
figures were strictly ACES or royalty and everything else.
MR. MAYER answered they were the entire state take.
SENATOR FRENCH asked him to explain his comment that "the
potential variation is even greater since production also
responds to price."
MR. MAYER explained that this analysis holds production steady,
but in reality, production is deeply respondent to price. In a
low price environment very few new projects are economic, don't
get sanctioned and don't go ahead. Lots of things that are
included in the current DOR forecast wouldn't go ahead in a
$60/barrel sustained world: wells become non-economic earlier,
production gets shut in earlier than it would otherwise. The
inverse is true in a very high price environment: wells keep
producing longer, it's worth investing in new liquids handling
capacity and other things that currently constrain production in
a way that is not at the moment. So, this already enormous range
of future revenues is much greater if one considers that
production also responds to price.
4:24:31 PM
He said the other major determinant is the level of future
production and in the context of declining North Slope
production, the rate of that decline. For instance, rather than
the 6 percent decline forecast we had only a 3 percent decline
or worse, a 9 percent decline, there is a good $4 billion in
difference between those two possible 2022 worlds.
SENATOR FRENCH asked why he started calculating the production
at 2017, because DOR forecasts a 2.6 percent production decline
between 2013 and 2014, 3.7 percent between 2014 and 2015 and 3.6
percent decline between 2015 and 2016, much lower numbers than
he used. Aren't the near numbers usually more accurate than the
out numbers for production forecasts?
MR. MAYER answered that was a reasonable statement but the
furthest out numbers don't include results of exploration or
other things, which in the right price and fiscal environment
might come on line. The reason he started at 2017 onward is by
thinking of this in the purely hypothetical context if through a
fiscal change it were possible to stimulate new production and
what would be a reasonable timeframe for that to happen. It
won't happen tomorrow, but it might happen by 2017.
4:27:06 PM
SENATOR FRENCH commented that as we get out that far he just
wanted to make sure we keep our feathers in our down comforter
and not in theirs.
MR. MAYER said he was thinking about what sort of new production
would need to come on line as a result of a change to make back
lost revenue in the future.
4:28:48 PM
SENATOR FRENCH said he would be asking for these numbers
constantly, because he was very concerned about net loss to the
state in reducing oil taxes and he didn't know that it could be
made up given the time value of money. You can reduce taxes to
zero and North Slope investment can go crazy at the same - and
the State of Alaska starves.
MR. MAYER said it's the most the important question to be
asking, but unsatisfactorily there is an enormous limit to the
science, but one can take the science further than it has been
taken so far.
SENATOR MICCICHE said fiscal terms can artificially create a
high or low cost environment and asked if he considered fiscal
terms in creating his analysis.
MR. MAYER responded that fiscal terms either improve or detract
from project economics and that is why they were having this
discussion; and this is a hypothetical about if the proposed
change was sufficient enough in terms of improving project
economics to create substantial future production and what that
might look like in terms current revenues.
4:31:24 PM
Inherent to this discussion is oil price. It's not only the key
determinant of Alaska's future revenues, it was in many ways the
substance of the last presentation about progressivity, because
Alaska currently has a highly progressive system that responds
very dramatically to changes in oil price. It seemed worth
presenting a few slides about the question of the global oil
price environment in the future and if it will be $200 or $60.
There is no such thing as an accurate oil price forecast,
because ultimately no one knows, but they can talk about trends
and the major structural factors shifting things in one way or
another that might lead to an over or under-supplied global
trade market.
It's also of relevance, Mr. Mayer said, because it ties into
something else that is a key factor in talking about fiscal
systems, which is the biggest shock of the last five or ten
years: the dramatic change in production in North America. It's
relevant both because the fixed royalty is relatively low
particularly at high price jurisdictions in the Lower 48 that
are key competitors at the moment for investment dollars, and
the production coming from that has the potential to have
significant impact on prices in the future. In 2003 through 2005
dollars harvested in North America were reinvested elsewhere in
the world (major international companies in Sub-Sahara Africa)
and paying back shareholders.
In the last recent couple decades, suddenly, North America is an
overall investment destination among international oil and gas
companies, because of the extraordinary revolution in
unconventional production like the shale play and oil sands in
Canada, but not in Alaska.
4:35:51 PM
MR. MAYER explained in the context of the overall profile of US
oil production US over the last more than half century (referred
to by PFC as the Great American Energy Reset) was in steady
decline since the late 1960s. The extraordinary reverse in that
trend came from the technological revolution in shale production
combined with high oil prices. The sorts of growth coming out of
the Lower 48 combined with what PFC sees coming on line between
now and 2020 is really comparable and greater than the growth in
production that occurred in the post war years.
4:37:07 PM
SENATOR MICCICHE asked if he knew the decline rate generally in
US energy from 1984 until 2007/8.
MR. MAYER answered that he didn't have that information. In the
context of what this means for future oil prices in the world
market for crude, demand comes from final products, whether that
is in the form of transportation fuels or from being in almost
every economic good that anyone uses, and from the refineries
ultimately. How that demand is met could be described as two
buckets of supply: all of the supply that comes from non-OPEC
countries without a say in the price versus the large producing
countries that coordinate output through the auspices of OPEC,
but as a result have some degree of say in setting what the
future price of oil will be.
4:39:21 PM
In looking at the structural factors in the world oil market,
Mr. Mayer explained that first one looks at what is coming on
line in non-OPEC sources over the foreseeable future and what
that means for the OPEC crude and the sorts of decisions that
OPEC is going to be making, and one sees quite extraordinary
growth based on projects that have been sanctioned and coming on
line over the next decade and more. That comes from a range of
sources: a substantial wedge is in oil shale, a lot of which is
in North America, and some oil sands in Canada along with less
obvious sources of growth in natural gas liquids and condensates
that actually come from OPEC producing countries but aren't part
of OPEC (places like the enormous fields that will soon be
coming on line in the deep water Pre-salt off of Brazil) and a
range of sources of new production coming on line between now
and 2020 and 2025, that will create substantial challenges for
OPEC as they look to coordinate and balance supply and demand.
SENATOR FRENCH asked him to explain the subheading on slide that
says, "In the past production not affected by price swings," and
why that isn't a contradiction with slide 2 saying how
production also responds "deeply" to price.
4:40:58 PM
MR. MAYER answered that that particular subheading was put
together by an oil markets colleague and he would like to defer
that answer to him. But in part it's the balancing function in
world oil market that the past has not been a factor of non-OPEC
supply; it's been much more a question of delivery policy by
OPEC-producing countries. Those delivery decisions are not made
on project economics; they're made on the interests of OPEC
producing countries and are not a function of whether they can
economically produce but rather what level of revenue they need
to balance their budget's external deficit.
SENATOR DYSON asked what makes the makers of the chart so
optimistic about biofuel growth.
MR. MAYER answered the substantial growth one sees so far and
the fact that biofuels is reaching a turning point
technologically speaking, and moving from corn and soy based
products that have relatively limited net energy value after
accounting for the fossil fuels that went into creating them to
crops that don't compete with food crops from grass to algae.
4:44:27 PM
He said that shale was a relatively small wedge of the total in
rising non-OPEC supply, but to view it in the context of the
traditional role of Saudi Arabia in balancing the world by
either increasing or decreasing production to meet certain price
level goals, shale oil is now forecast to reach 4 million
barrels by the end of the decade, which is almost double the
last Saudi supply swing. It's interesting to think about in the
context of shale as a form of production that is particularly
respondent to oil price, because it consists of drilling so many
relatively small low producing wells that have high initial
production and decline very dramatically - so that the way one
maintains shale production is by drilling and drilling. That
means that shale more than any other resource is respondent in a
very short timeframe to oil pricing - because you either drill
or you don't depending on whether it's economic to do so or not.
In that sense, shale oil production joins the ranks of potential
short term global oil supply/demand balances that were
traditionally either made up of Saudi Arabia producing or not
producing or things like the International LNG Association or
the US Strategic Petroleum Reserves stocks. PFC thinks that OPEC
has yet to grasp the scale of its impact on its role, as it is
only now beginning to address the consequences of rising
production in Iraq.
4:46:25 PM
MR. MAYER said that Iran has recently decreased its production
as a result of sanctions. If that is held flat for the next
several years and looking at what will come on line out of Iraq
over that period and the coming shock of all the new non-OPEC
supply coming onto the market between now and 2020, means if
Saudi Arabia were to take its traditional approach and be the
country (because it has the lowest cost of production) to be
able to swing with demand and absorb it all they would have to
go from producing 9 million barrels/day to producing 5 million
barrels/day, which is hard to see how they will be able to
economically do so. And if they aren't, that has substantial
implications for the direction of crude prices between now and
2025.
4:47:52 PM
He related that as US production has more impacts on oil price,
particularly shale, that also in many ways increases the
volatility of where things could head - both about the immediate
responsiveness of shale production to changes in the price
signal but also because of how easy it is to be disrupted in
some ways, because the very steep decline from an individual
shale well can be 50-60 percent in the first year. This means
one has to keep drilling and as you keep drilling the overall
decline in terms of annual production gets steadily steeper and
compounds. He showed a slide of the Bakken Shale by vintage of
wells drilled that illustrated how more wells have to be drilled
every year in order to keep the production growing along with
changes in things like the price that can lead very dramatically
to an immediate change in production in a way that hasn't
necessarily been the case in the past.
Someone asked what a breakeven price for shale production in
Lower 48 is and the short answer is there is on one breakeven
price for shale production in the Lower 48, and Mr. Mayer said
there is an extraordinary variation. The reason for that is that
while it generally costs about $8 million to drill a shale well,
what you get for that varies "massively" depending on where in
the play you are drilling it and the initial productivity of the
well that you get as a result.
MR. MAYER said if one separates wells drilled - for instance, in
the Bakken - into quintiles of the most productive down to the
least productive, the most productive well it makes sense to
drill even at $41 or $44 in the Bakken if you include the cost
of the acreage that goes with the well. It doesn't make sense
for the least productive until prices are north of $126. That is
simply a function of the enormous variation and initial
productivity that comes with these wells.
SENATOR FRENCH said they were given several presentations on
Capex and Opex costs in the Bakken and asked how this jibes with
the Opex and Capex cost estimates of $21/barrel all in in North
Dakota and the Bakken.
MR. MAYER replied that these are phrased in different and more
granular terms, the more granular terms being used to create his
estimate of $8 million - more or less - to drill a well at
certain fixed and variable costs to operate it. He also noted
that this more granular analysis considered that both acreage
and royalty rates vary dramatically across the plane of well
productivity and a highly productive, highly economic well can
support a royalty rate of up to 18 percent in the Bakken and up
to 25 percent in the Eagleford and premium costs for acreage.
A lower productivity well can support acreage costs and royalty
rates that are much lower than that, because no one would be
willing to pay them. That is also the case at Eagleford in the
context of fiscal systems benchmarking, because a lot of people
look at reports of 25 percent or higher royalty in some of the
shale plays and think that is actually quite a serious
government take. The comparison is only partly fair because only
a very limited number of leases get signed with royalty rates,
because only a very limited number of leases have the sorts of
economics that can support them.
SENATOR FRENCH said he wasn't sure he understood that answer and
it sounds like this is an overly simplistic view - to give him
one fixed Capex and Opex when he sees a much broader range given
the productivity of the wells.
MR. MAYER responded that there is almost no range on the cost
front. It's going to cost on the order $7.5 million to drill a
well in the Eagleford whether or not it's productive and
operating costs will be similar. But Senator French was right on
a per barrel basis, those costs being greater for a low
productivity well than for a high productivity well, because the
barrels over which those costs are amortized are substantially
different. His analysis took a particular average, probably a
second quintile well, and generalized it.
4:54:37 PM
A third example for a more marginal play where you need to have
a first quintile well at current prices to be worth drilling is
the Granite Wash in the Panhandle of Texas. What this means for
future crude prices, Mr. Mayer said they could think about this
in terms of sources of potential upside and sources of potential
downside. On the upside, strong globally economic growth will
obviously lead to strong demand and a tightening supply/demand
balance and upward pressure on prices; similarly whether the
various geopolitical events could remove substantial barrels
from the market (another Libya-type event or a confrontation);
lots of things could lead to enormous spikes in the oil prices
and sustain prices that are higher.
He said there are also an enormous number of downside risks to
the oil price outlook. The "American energy reset" was an
enormous boom in US production that is now supporting production
from most of the world's incredible demand growth and leaving
relatively little room for additional growth from other
countries. And there is probably greater likelihood at this
point of economic slowdown whether because of ongoing weakness
in the Eurozone, here in the US and China than there is of
enormously robust global growth (the challenges he laid out in
terms of the difficulties ahead for OPEC's traditional role and
what they do in the wake of all the new non-OPEC supply).
With specific relevance to Alaska, Mr. Mayer said, there is the
question of if it will continue to receive the premium of WTI,
for instance, that it has received for the last couple of years
as WTI has traded at a discount to Brent or could various things
combine to mean that actually that US WTI discount extends more
broadly across the country. There are a number of things, at
least in a world and in the US where production growth was
robust enough that it could increasingly meet its own demand
that can cause that to be the case.
SENATOR BISHOP asked what inflation in Europe does to oil
production.
MR. MAYER replied that ultimately economics of oil production
are economics in real terms rather than nominal terms. Inflation
may impact the price in which barrels are equated, although US
inflation has a much bigger impact on that than anything, but it
doesn't change the fundamental economics of whether production
is economic or not. Demand affects price, but that is several
steps removed from inflation unless one gets into "very
difficult territory."
4:58:24 PM
Finally, in response to a particular question he was asked in
the other chamber, but is relevant in thinking about this, was:
What is the potential floor for ANS West Coast crude? In the
short term, you could see prices in the $30/barrel range. It's
not absurd to think about where prices have been between May
2008 and now. A chart of prices ordered highest to lowest showed
the relative lengths of time in no particular chronological
order that have been spent at different price levels. Obviously,
on the furthest right, dips occurred around late 2008/09 where
price levels got down to the $40s. Prices that low would require
substantial global oversupply like a combination of OPEC getting
things completely wrong in terms of managing supply and demand
and booming US production. And the oil price wouldn't stay there
for long, because to begin with, as seen from the breakeven
prices on shale, there is no shale production that is going to
be economic at those prices and production would rapidly fall in
a short period of time.
In the medium to long term, assuming the US remains an
integrated part of a global crude oil market, it's hard to see
crude oil prices go much lower than $70/barrel as the lower
possible limit to where crude oil prices could go.
5:01:33 PM
He said there five key problems with ACES:
- One is that overall high levels of government take reduces
competitiveness for capital especially at high prices.
- The high marginal tax rates reduces incentives for spending
control.
- The complexity of the system makes meaningful economic
analysis and comparison relatively difficult.
- There is significant state exposure in low price environments
at high-cost developments.
- The impact of large-scale gas sales have a substantial
potential impact on tax rates in a way that seems like something
that one would design out of intention.
5:03:21 PM
Benchmarks:
At $80/bbl, ACES is at the highest end of government take
compared to other jurisdictions in the OECD or anywhere else in
the U.S. in terms of conventional production, although it's
quite possible unconventionals might see high government take
solely because of the relatively higher cost structure compared
to conventional production - combined with a fixed royalty
(which, because it's a regressive regime, means that at low
prices and high costs you can get high government take).
At $80/bbl for a new development on a standalone basis (not part
of the overall cash flow of an existing producing company) ACES
is already the second highest level of government in the OECD
and above the average for production sharing contracts around
the world. Testimony on the question of progressivity from the
department prior to this presentation indicated that government
take is substantially lower for an existing producer. This has
been modeled with two reasons for that in mind: the biggest is
the question of the impact of being able to claim capital
expenditures (in this case just capital expenditures from base
production not from new development because that is not being
included) but against your tax liability. Another source of the
difference is that consistent with the approach that Econ One
takes, which is sensible, they have included for new development
a 16.67 percent royalty rather than the 12.5 percent, which is
more common on the base, and which accurately reflects what one
sees in the actual data under ACES.
SENATOR FRENCH asked if any of his models take into account the
effects of royalty modifications that are available if a
development is shown to be stressed financially.
MR. MAYER replied no; and at $80/bbl most developments would not
have royalty relief.
SENATOR FRENCH said the reason they don't see much royalty
relief is because they couldn't demonstrate any economic
difficulty to the DNR - basically.
MR. MAYER replied that might be the case. This is only one
metric among many that are important as a way of comparing
regimes for competitiveness where Alaska stands.
SENATOR FRENCH said he would probably ask him to run some graphs
with royalty relief, because it might be instructive for folks
to be able to see how much you can move down in take if royalty
relief is granted.
CHAIR GIESSEL said Alaska doesn't offer much royalty relief in
reality.
MR. MAYER replied to the extent that Alaska does offer royalty
relief, it's not unique among any jurisdictions in doing so, but
it's not something that would be very easy to model since it's
more about specific circumstances than something one can easily
run through a model.
5:08:22 PM
MR. MAYER said ACES at $100/bbl for a new development and 16.67
percent royalty is substantially above Norway and is the highest
in the OECD and getting into the company of countries like
Angola, Turkmenistan, and Azerbaijan. ACES for the existing
producers moves up to the second highest in the OECD after
Norway, and is approaching the average for production sharing
contracts regimes around the world. ACES for a new development
is now close to Norway, but only because Norway has moved up not
the other way around; for an existing producer second in the
OECD behind Norway and above the overall average at that price
level.
5:09:03 PM
At $120/bbl, ACES for a new development is close to Norway,
again, but only because Norway has moved up and not the other
way around, and for an existing producer - again second in the
OECD behind Norway and above the overall overage at that price
level for production sharing contract regimes.
5:09:40 PM
MR. MAYER moved to Senator French's question about net income
per barrel for ConocoPhillips because they are the only company
that splits out Alaska as a separate reporting region and said
that these are not all of ConocoPhillips reported categories (he
selected the major ones and particular ones for which there is
more time series for a backward look). The biggest comparison is
how much higher the net income per barrel in Alaska is than it
is in the Lower 48 and why ConocoPhillips is investing there and
not here. In answer to that he said the net income per barrel in
Alaska is comparable to what net income per barrel for
ConocoPhillips is in many other parts of the world. But the
first thing to notice is that the stacked bars add up to total
revenue supporting the categories of income, production taxes,
operating costs, depletion, depreciation, amortization,
exploration expenses and finally - once all those things are
taken out - what's left is income per barrel for the producer.
So, the first thing you notice is that the biggest reason for a
difference in net income per barrel of oil equivalent (BOE)
between Alaska and the Lower 48 for ConocoPhillips is that they
get half of the revenue from a BOE in the Lower 48 that they do
in Alaska and the reason is that ConocoPhillips/Lower 48
production is overwhelmingly gas as opposed to almost entirely
oil in Alaska. That in turn is a function of various decisions
including the particularly ill-fated one to have acquired
Burlington Resources in the middle of the last decade and having
paid a premium price at the top of the gas price in the U.S. -
seeing an ongoing heavy demand for gas and not seeing what was
about to come. As a result they have a very heavy gas-based
portfolio that doesn't produce a lot of revenue for each barrel
of oil equivalent.
5:12:25 PM
This comparison tells you little to nothing about new
investment. If the question is, given how much greater net
income per barrel is in Alaska than in the Lower 48 and why
ConocoPhillips isn't therefore doing more of that, the question
is doing more of what. To begin with ConocoPhillips isn't
invested in the Lower 48 because the senior management is
deranged and wants to destroy its value; it's because they see
enormous opportunities in liquid rich plays that have economics
that are very different than the base portfolio of gas
production.
Similarly, if one looks at their relatively high net income per
BOE in Alaska and asks why they wouldn't want more mature
largely depreciated assets that were all paid for 20 years ago
and are now harvesting a nice cash flow, there isn't any more of
that. And by definition, mature regions produce income because
the costs were paid 30 years ago and most of the depreciation is
gone and you get relatively a lot of income from them. But that
is not indicative of what the opportunities are for new
investment in new projects. Yes, ConocoPhillips net income per
BOE is relatively high in Alaska versus the Lower 48, not
particularly remarkable compared to other regions, and not at
all indicative of the question of economics in new investment,
which is why they are currently investing enormous amounts in
liquids or shale plays in the Lower 48 and less so here.
5:14:31 PM
SENATOR MICCICHE asked if he hadn't been able to determine a way
to give them a comparison based on barrel of oil (BO) as opposed
to BOE.
MR. MAYER responded if one is to limit one's analysis to
publically available data, the way companies report is by
revenue overall; however, they report production by oil versus
gas. So, there isn't a good way for publically reported data to
split where the revenue comes from.
SENATOR MICCICHE said the legislature uses these numbers and
they are displayed on the paper as though they mean something
that they should consider, and it would be nice to have apples
to apples for a comparison.
MR. MAYER replied that this data comes from a subscription set,
a service that PFC Energy offers, which is precisely by
comparing international oil companies to each other and it would
be very nice to be able to compare apples to apples, but
unfortunately the nature of comparing companies' publically
reported data is that it's very rarely possible and you have to
make the best of what you can do.
SENATOR DYSON asked when the equipment in a mature field has
been depreciated if the owner can write that depreciation off
against their income taxes along with non-depreciated equipment
that got a huge deduction against their business taxes.
5:17:06 PM
MR. MAYER said that was correct, but on the other hand
depreciation also reduces your taxable income, which is
ultimately effectively the same as what is reported here in
terms of net income per barrel. In that sense, one of the
reasons why the Lower 48 looks bad other than the much lower
revenue that is being received is because there is substantially
more depreciation.
He moved on to the question of high marginal tax rates and
incentives for spending control. To look simply at the
production tax component of the regime, ACES has two different
steps of progressivity: the .4 percent rate that extends from
$30/barrel of production tax value to the shallower rate that
starts at $92.50/barrel of production tax value. Because it's an
unbracketed system, every dollar increase in the price increases
the rate that is applied to all of the previous dollars of
production and you get an slightly counterintuitive spike in a
very high marginal rate of tax so that every dollar of oil price
increase very dramatically increases your tax rate to the point
that the marginal dollar between $91/barrel of production tax
value and $92/barrel of production tax value essentially is
taxed at a marginal rate that is close to 90 percent. So,
movements along the price curve in either direction from there
have a dramatic impact on the level of tax that is paid. That
means because production tax value is not on the oil price, that
there are various ways of moving along that curve. One is a
change in the oil price; another is a change in costs that can
be deducted to reduce production tax value per barrel, which
lets one shift down that steep curve and into a lower marginal
and average rate of tax. This point was particularly well made
by Econ One in their presentation two days ago on slide 23
modeling additional spending given an initial background level
of spending and what that does to a producer's tax liability in
different oil price environments and how enormously different
that impact is at higher oil price environments, such that when
you reach $120/barrel that 95 percent, effectively on an after
tax basis, has been essentially recouped as a function of
reduction in tax. So that, in particular for relatively small
limited term spending (that can be financed from the cash flows
of the business unit) it doesn't need to be evaluated in terms
of performance in a wide range of economic environments and the
fundamental economics of a project, it's easy to see why this
can provide a significant incentive for undertaking projects
that one might not otherwise undertake if one had to finance
their cost.
5:20:21 PM
SENATOR FRENCH asked if he was aware of any projects on planet
earth as an example of how industry is taking "perverse
incentives" and wasting money on the North Slope.
MR. MAYER replied no; it's much easier to look at incentives. In
terms of gold plating, a good example of a regime designed to
encourage gold plating spending was a particular production
sharing contract in India that is a subject of challenges by the
Indian government. It gets very difficult even at that level
when there is a particular accusation to get down to say this
was accurate spending or not. It's almost never possible for
governments to identify what was reasonable spending and what
wasn't, because they don't have the resources or capacity to do
so. What can be done is try to design a regime that doesn't
incentivize it in the first place.
5:22:19 PM
SENATOR FRENCH commented that he was afraid that regime would
leave him without many feathers.
MR. MAYER said on the question of complexity and why the
economics of new developments don't that look fantastic for an
existing producer and as a result why they're not all madly
investing in every opportunity that they get, one interesting
comparison is looking at a new development on a standalone basis
versus an incremental capacity (50 million barrel/day,
$16/barrel Capex) development - taking the costs and revenues of
an existing base producing company, layer on the cost of
revenues of the new development, and run that through the model
and get the cash flow results, then compare that to the cash
flow results from just base production and subtract the base
production from the combined and look at the difference. His
charts looked very similar to Econ One charts in terms of what
different metrics look like on an incremental basis. One sees a
small significant difference in government take, but a more
substantial difference in present value, but then there is
enormous difference in internal rate of return: the basic reason
being that viewed on the incremental basis when you're looking
at the impact of spending after tax what you're looking is "buy
down" or the ability of spending to lower the tax rate on the
base production. Because of the cash flows, a lot of the
spending is being returned in the form of lower tax, despite the
fact that there may be high government take and therefore,
relatively little cash flows from the investment. Overall you
can get a high internal rate of return, because actually
engineering one isn't very difficult. You just need to reduce
the initial capital to a point. That doesn't mean you're
creating a project with large amounts of economic value; it just
means that you're on an after tax basis investing relatively
little enough that the limited cash flows you get provide you
with a high internal rate of return.
5:25:57 PM
SENATOR FRENCH asked if this was the difference between an
incumbent producer and a new producer.
MR. MAYER replied yes. The most important thing about this is
that incremental economics are important for a range of reasons:
they are important to companies but they are vital to the state,
because from the state's perspective it really is foregoing
revenue compared to what it would otherwise get of the high
level of government take under ACES in return for investment.
The question is what it gets for that. And the reason he says
incremental analysis is important but not the only thing is
because it's absolutely one thing that companies look at in
making investment decisions.
He stressed that oil companies look for two things and that
ultimately they are in the business of putting large amounts of
capital to work in order to get large amounts of future cash
flow from those large and efficient investments. The fact that
one can engineer a situation where they get a great internal
rate of return purely on an architect's basis doesn't by itself
make an investment compelling - in particular when it must
compete with a whole range of other projects internationally in
a portfolio. Simply on a standalone basis, a project needs to
make sense economically and if it passes that threshold and has
the benefit of buying down your tax rate, that is great and
probably pushes it forward in the queue, but the fundamental
purpose of investing in a major oil and gas project, of spending
more than $1 billion, is not to purchase tax equity; it's to get
substantial rewards in return. It's also an investment that
needs to work over decades and over a broad range of price
environments. Whereas a system like ACES will get one absurd
rates of return (90 percent) on an incremental basis, but it
will do that as long as the oil price is exactly $120 for the
rest of the project life. But that isn't the real world and not,
therefore, the way projects are evaluated.
On the one hand ACES is a system that on an architect's basis
gives back a lot of cash compared to the high level of take the
system is designed for in return for spending, but it's not
clear that in doing so it substantially incentivizes new
production investment. It's much easier to see how in any given
year one could spend on a particular bit of maintenance; one
isn't looking at the 30 year economics. It's much easier to see
how the effective rate is an incentive for spending, and by and
large what they have seen over the last several years has been a
growth in spending but not a growth in spending about new
development. And he thought the question of the difference
between standalone versus incremental analysis goes a long way
to understanding that.
5:30:51 PM
Another metric one can consider, a really important one, is
return on capital employed. There is almost no more important
way at the highest possible level in terms of how large
international oil companies are viewed by the market in terms of
their capability than return on capital employed as an overall
measurement of efficiency of how well management is used. It is
a metric that is completely unaffected by any of the architect's
benefits that come from buy down. A $50-plus billion large scale
investment in a North Slope gas development is a good example.
5:33:25 PM
SENATOR MICCICHE asked if he was saying there is very little
value given to credits in overall evaluation of projects in the
board room.
MR. MAYER answered that much more impact comes from
progressivity and buy down, but they are only one part of the
picture. If the fundamental standalone economics of the project
don't make sense, having the state provide credits to make it
economic won't make any difference. The most pessimistic
interpretation one could put on that is the idea of Alaska
returning a lot of money that would otherwise be taken in in the
form of revenue under the system in the hope of improving
economics of making investment in new production more viable and
actually getting very little for doing so.
5:35:56 PM
So, drawing from the same key things that have driven the
previous two issues: high marginal rates that reduce incentives
for spending control and potentially can mean talking cross
purposes in what is incentivizing production also create
significant exposure for the state both in low price
environments and for high cost developments. There is no better
way of explaining this than the Econ One slide he had already
presented: the basic point being that particularly with the
highest cost possible developments, on an incremental basis they
actually reduce the tax burden for the company undertaking it by
more than the value that they create for the state and in that
sense the state is improving that value, at least on an
incremental basis, to its own detriment.
SENATOR DYSON asked where it says dollars per BOE what the
dollars were.
MR. MAYER answered the four charts are all measuring returns,
but to the producer and the state in terms of net present value
at a 12 percent discount rate per barrel of oil equivalent.
5:38:02 PM
SENATOR DYSON asked if the dollars running up the vertical axis
was money in the companies' pocket or the states'.
MR. MAYER said the top two were from the perspective of the
company (left is an incumbent and on the right a new producer).
The bottom axis is the crude price and lateral axis is a
question of value.
SENATOR FRENCH mentioned that in the upper left corner ACES
significantly improves the MPV to an incumbent producer versus
no production tax.
MR. MAYER said that was correct, but it does so on an
incremental basis and it doesn't change the underlying economics
of the project, and it does so at enormous cost to the state.
SENATOR FRENCH asked if ExxonMobil, ConocoPhillips, BP would be
subject to incremental economics.
MR. MAYER replied that was only one way of viewing the problem
and only one lens through which to screen economic opportunity.
SENATOR FRENCH said that investment in Alaska is up
substantially in the last few years and it's expected to go up
again next year according to the DOR's Revenue Sources Book by
about $500 million. That's a 37 percent increase!
MR. MAYER referred him back to his comments about the type of
spending that is occurring that is going to maintaining existing
facilities. That kind of spending can be financed out of the
cash flows of existing operations versus spending that has to
compete with an international portfolio for capital and face the
numerous screens and hurdles one has to in order to do that.
SENATOR FRENCH said next year capital spending would increase in
Alaska by 37 percent and asked if that was good.
MR. MAYER answered unless it's spending to create new production
that is not necessarily the case.
CHAIR GIESSEL remarked that Mr. Mayer had made that point
several times.
SENATOR FRENCH said he wasn't quite sure, because he already
said he is unaware of spending on the North Slope that is being
misdirected. So, he has to believe that the oil company
investors are spending money on the North Slope towards making
more production, but Mr. Mayer seems to be resisting that and he
didn't know on what basis.
MR. MAYER responded there are a couple of reasons: this is a
mature basin in decline and one where the major capital
investments were made to last 20 years and have substantially
outlived that. A lot of spending needs to go on just to maintain
existing production, and one would expect at this point in a
basin's life to see rising expenses; spending like in field
drilling programs and things that don't have challenged
economics that are profitable to do and are going on today. The
question is if one wants to go beyond that to actually try to
turn around production decline, what economics of substantial
new investments that have to compete in a company's portfolio
for capital look like, and the answer to that is they are not
occurring now and when you compare even incremental economics on
many counts except for IRR they are not necessarily competitive
with other regimes, particularly when you look at pure
standalone economics of the projects. In many cases they don't
make a lot of sense.
SENATOR FRENCH said that was an excellent answer, but he was
still curious about the quality of spending on the North Slope
and how Mr. Mayer was able to tell him it's not being spent on
things that will turn around the production decline.
5:44:02 PM
SENATOR MICCICHE said they had asked staff to calculate the
value of the production that had been returned to the state for
the checks to new entrants that had returned 5 percent of the
North Slope overall production. The state has expended a
significant amount of effort and hundreds of millions of dollars
in trying to create a secondary producer base that may or may
not result in investment ever that results in additional
production.
He wanted to make sure they didn't continue focusing on spending
that is not related to production and seemed very unlikely to be
related to significant production in the future. They were
trying to collect some data on what the state has spent on very
tiny increments of new production and said, "I think we're
upside down and I don't think it's a good way to do business."
MR. MAYER said finally the whole idea because production tax is
levied on a btu equivalent basis (treats oil and gas as the same
thing based on their heat content) and pulls them together in
terms of a company's gross revenue and production value after
allowances, that on a per barrel basis large scale sale of gas
has the ability to substantially reduce production tax value and
is a feature that would not have come about through intended
design.
5:45:54 PM
To address these five key problems he listed the available
solutions.
-Addressing the overall high levels of government take that is
about the base rate can be tackled by reducing, bracketing,
capping or eliminating progressivity.
-In terms of incentives for spending control under marginal tax
rates, one can reduce, bracket, or eliminate progressivity or
reduce or eliminate credits.
-In terms of complexity, other than the question of overall
simplifying the system design, it seems that what one wants to
do is to get rid of a lot of the interaction of progressivity
with credits to create a system that doesn't hand back a lot of
cash for things that don't actually fundamentally improve
project economics and when it comes to the question of the very
different economics for a new development, particularly when
there is no possibility of incremental analysis to try to even
out the disparity.
-The question of state exposure in low price environments for
high-cost developments reveals the same sorts of questions, in
particular the question of reducing, eliminating some or all
credits. One can eliminate the ability to claim the credits from
the state treasury and require them to be taken from future
production, and there are various ways if they are going to be
carried forward to production that one can do that by either
keeping their value constant or trying to maintain their time
value of money.
-In terms of the question of large scale gas sales on tax rates,
some of the other solutions, such as simply reducing, bracketing
or capping the rate of progressivity, don't do a lot to change
this feature. The things that would get rid of the de-coupling
problem are either eliminating progressivity altogether, keeping
it in place but on a gross rather than a net basis, or finding
some other way like a gross revenue exclusion similar to one in
SB 21, but a progressive one rather than a flat one.
5:50:41 PM
He said the solution SB 21 chooses is eliminating progressivity,
getting rid of the capital credit and making the net operating
loss credit one that is carried forward to production in a way
that tries to maintain its value, and improving economics for
new developments through the gross revenue exclusion.
Coming back to the benchmarking slides, Mr. Mayer said that at
$80/barrel (assuming costs in the new development for an
existing producer that are essentially the cost structure seen
in a mature producing field at Prudhoe Bay), SB 21 is basically
about the same at $80/barrel as ACES. It would be slightly worse
a little bit lower because of the effect of taking the credits
away.
Under SB 21, the new development is the lowest because despite
the impact of taking the credits away it has the gross revenue
exclusion. So for an entirely new development in an entirely new
producing area even at $80/barrel from a government take
perspective it's substantially lower. That disparity only grows
as one moves up through the price deck until at $120/barrel, for
the existing producer and the new development is just over the
63 percent government take mark under SB 21 - a much more even
range between the two of them.
5:51:43 PM
What it doesn't show is that the impact of taking the credit
away is the point at which SB 21 goes from being a tax increase
to a tax decrease and that it can happen at very different price
levels depending on the level of capital spending that is going
on by the company involved. So, for base production with only
$10/barrel in Capex at anything above $75/barrel it's a tax cut;
below $75/barrel it's a tax increase. This ties back to the
question of a possible floor price for ANS West Coast that he
started with.
If one is involved in a capital intensive new project - whether
that's at Point Thomson or taking sanction on a number of new
projects - if one is a smaller new producer, still very much in
the development phase of an asset - the price at which this is a
tax increase is substantially higher. If he is spending
$25/barrel in Capex, then it's only when prices reach
$110/barrel that this actually reduces government take.
SENATOR FRENCH asked if an established producer at Prudhoe Bay
with all costs amortized is on the red line, is it a tax
increase? But it's a tax decrease at anything above $80/barrel?
If you're trying to produce heavy oil or shale you're further
out because of higher prices and it doesn't get to be a tax
break until it gets to $110/barrel?
MR. MAYER said that was correct. If one has substantial
satellite developments in Kuparuk that are currently going on,
those are also things that take one's capital spend above that
to somewhere in the $15-20 range.
SENATOR FRENCH asked if you are Great Bear looking at this, you
go "oh oh."
MR. MAYER answered yes at current prices and said that concluded
his presentation.
CHAIR GIESSEL thanked Mr. Mayer.
[SB 21 was held in committee.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 21 Progressivity by DOR SRES 2013.02.15.pdf |
SRES 2/15/2013 3:30:00 PM |
SB 21 |
| SB 21 Fiscal System PFC Energy Mayer SRES 2013.02.15.pdf |
SRES 2/15/2013 3:30:00 PM |
SB 21 |