Legislature(2011 - 2012)HOUSE FINANCE 519
04/23/2012 09:00 AM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB3001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB3001 | TELECONFERENCED | |
HB 3001-OIL AND GAS PRODUCTION TAX
9:08:56 AM
CO-CHAIR SEATON announced that the only order of business would
be HOUSE BILL NO. 3001, "An Act relating to adjustments to oil
and gas production tax values based on a percentage of gross
value at the point of production for oil and gas produced from
leases or properties north of 68 degrees North latitude;
relating to monthly installment payments of the oil and gas
production tax; relating to the determinations of oil and gas
production tax values; relating to oil and gas production tax
credits including qualified capital credits for exploration,
development, or production; making conforming amendments; and
providing for an effective date."
9:09:13 AM
JANAK MAYER, Manager, Upstream and Gas, PFC Energy, speaking as
the project manager hired by the Legislative Budget and Audit
Committee, reported that PFC Energy is a global energy
consultancy which specializes in oil and gas with a focus on
above ground risk, including fiscal terms, commercial risk, and
geo-political risk. He explained that upstream refers to the
exploration and development of crude oil, as opposed to
downstream which refers to the refined product.
9:10:27 AM
CO-CHAIR SEATON asked the committee to save any philosophical
questions until after the presentation.
9:11:23 AM
MR. MAYER introduced a PowerPoint presentation entitled
"Discussion Slides: Alaska House Resources Committee," which was
included in members' packets. He then said he would provide a
brief background of Alaska's oil and gas competitive context,
particularly in terms of the current fiscal system in the
context of other hydrocarbon regimes. Drawing attention to
slide 3 entitled "Fixed royalty Jurisdictions in US Lower 48 Are
A Key Competitor to Alaska for Investment Dollars," which
compares the time periods, 2003-2005 and 2008-2010, for the
areas around the world where companies were taking cash and
significantly investing cash for a base of new production. He
stated that for much of recent history, North America and Europe
have been cash surplus regions of established production where
investments have been made in the past. He noted that
essentially, companies harvested cash from those mature regions
and used it to build assets in new regions. During the first
half of this last decade, a notable cash deficit area was Sub
Saharan Africa where companies made significant investment in
plays, particularly in deep water Sub Saharan Africa. He
reported that in the last couple of years high oil prices and
the unconventional oil revolution in North America, the Lower
48, has created a remarkable turnaround from an exporter of cash
within companies' portfolios to a destination of cash. He
declared that there is now a lot of investment in the Lower 48
to take advantage of the Lower 48's onshore unconventional play.
MR. MAYER stated that the fiscal regimes across the Lower 48 are
by and large fixed-percentage royalty regimes. Five years ago
major competitor jurisdictions for investment dollars were
likely to be developing countries with large production sharing
contracts in terms of their fiscal systems, relatively high
levels of government take, and fiscal systems that negotiate
terms directly with companies. The significant difference today
is that one of the main competitive jurisdictions for Alaska is
the Lower 48 as a destination for cash and there, in the Lower
48, is significantly lower government take. The aforementioned
makes it more difficult for Alaska to compete within companies'
portfolios for investment dollars.
9:15:37 AM
MR. MAYER moved on to slide 4 entitled "Alaska's Days of Easy
Oil Are Gone: High Costs and High Government Take Present
Challenges" and stated that there are steadily rising costs of
oil development in Alaska. He listed the development cost for
New Light Oil, Mid-High Cost Development, and High Cost
Development in Alaska. He declared that capital costs of $17
per barrel and operating costs of $15 per barrel are reasonable
estimates for the existing infrastructure. However, for those
developments that are farther from existing infrastructure,
target smaller reservoirs, require horizontal wells or hydraulic
fracturing, or are reservoirs for viscous oil, the capital costs
increase to $25 per barrel. In fact, for developments well
outside of existing infrastructure toward the National Petroleum
Reserve-Alaska (NPR-A) the capital costs can be as high as $34
per barrel. In comparison, the Lower 48 capital costs for
conventional onshore plays is $2-$5 per barrel, with the total
operating and capital cost being less than $10 per barrel. The
total [capital and operating] cost for unconventional oil plays
in the Lower 48, such as the Bakken or Eagle Ford, could reach
$20-$25 per barrel. Therefore, the cost for new development in
Alaska is significantly more expensive than the Lower 48,
regardless of the fiscal terms.
9:18:23 AM
REPRESENTATIVE GARDNER expressed her understanding that Alaska's
very high costs had been a reason to move to a net profits tax.
She asked if Texas, North Dakota, and Louisiana were based on a
net profits tax.
MR. MAYER replied that those states are on a fixed royalty
system with some variations in the royalty such that there is
greater predominance of private land. He declared that fixed
royalty systems can have high levels of government take when
costs are high and prices are low because from any given barrel
a fixed percent is being taken. However, when costs are low and
prices are high, the fixed rate jurisdiction is more attractive
than the net profit jurisdiction.
9:19:53 AM
REPRESENTATIVE GARDNER asked if, in comparison, net profit
blunts the impact of high cost. She pointed out that Alaska is
at risk when the price of oil falls, which was a trade off when
the tax structure was initiated. Therefore, Alaska would take
more at the high end and share the risk at the low end.
MR. MAYER stated that the impact of a net profit system of the
sort that's in Alaska is to make the overall system relatively
neutral with regard to cost. The presence of a fixed royalty
component makes Alaska's system slightly regressive in terms of
cost because as costs increase, the government take may increase
slightly. However, fixed royalty systems are very regressive in
terms of cost, and thus the greater the costs, the higher the
government take. Mr. Mayer agreed then that a net profit system
blunts some of the impact [of high cost], but it is not a
progressive system with regard to cost. As costs increase,
government take does not decrease, and he stated that the level
of government take in Alaska is high compared to many other
regimes.
9:21:41 AM
REPRESENTATIVE SADDLER asked to clarify that the referenced high
cost of development is not for viscous oil or future high cost
of development.
MR. MAYER expressed agreement, adding that in the recent past
there have been developments within the range of the new light
oil to the mid to high cost. Although he was not aware of any
developments at the high cost level, he suggested that there are
projects in the planning and evaluation stages that could entail
the higher costs. However, those projects are very challenged,
he further suggested.
REPRESENTATIVE SADDLER asked for an example of an Alaska field
that would fall into the specified categories: new light, mid-
high cost development, and high cost development.
MR. MAYER offered his guess that Nakaitchuq and Oooguruk would
fall somewhere between the new light oil and mid-high cost
development, but opined that the oil companies would need to
share the details. He anticipated that some of the viscous oil
projects planned within existing fields by the current operators
would also be in the mid-high to high cost of development.
Similarly, projects in NPR-A as well as serious heavy oil
projects could fall in the high cost of development.
REPRESENTATIVE SADDLER asked if there are any examples for new
light oil or mid cost projects.
MR. MAYER responded that he did not have specific examples for
new development, but characterized the estimated costs as a
reasonable benchmark based on other recent developments.
9:24:09 AM
CO-CHAIR SEATON pointed out that the unconventional oil projects
of the Bakken and Eagle Ford and new light oil projects in
Alaska had the same capital cost requirements as specified on
the chart. He asked if the Eagle Ford and Bakken projects,
which required continuous drilling and capital costs, had
capital costs related to the graph.
MR. MAYER replied that the figures on slide 4 were done on an
annual operating cost per barrel produced, but the capital costs
were based on per barrel of reserves. He pointed out that,
depending on the size of the reserve, spending could come at the
front or be stretched out, which could significantly impact the
project economics. He stated that even though the
unconventional projects have much higher capital costs than
previously seen in the Lower 48, these costs were lower than
many costs in the planning stages in Alaska. Other than having
lower capital costs than in Alaska, the Lower 48 projects have
the advantage of the capital costs being spread out over time.
Therefore, with comparable costs between the new light oil and
the unconventionals, it may look better for the unconventionals
because the capital spending is spread out over time.
9:26:27 AM
MR. MAYER moved on to slide 5 entitled "Relative Government
Take," which defined relative government take as government take
divided by divisible income. He explained that divisible income
is gross revenues less all the costs, including operating and
capital costs and transportation costs. The government take is
that portion of the divisible income remaining after the private
company's take. Dividing the absolute government take by the
divisible income results in the percentage of the income the
government receives on a project.
9:28:09 AM
CO-CHAIR SEATON inquired as to when private royalty comes into
play.
MR. MAYER clarified that the benchmark slides he will present
today treats private royalties as though the private landholder
were government. From a company's perspective, funds that go to
a private landholder or the government are the same because they
are funds that the company does not receive.
REPRESENTATIVE P. WILSON asked how the private royalty can be
determined when, in fact, some of the contracts are private.
MR. MAYER said that although there are significant variations
between leases with the private contracts, there are fairly well
documented reasonable averages available for estimations.
Therefore, Mr. Mayer used the reasonable averages and when there
was a question, he erred on the high side.
9:30:00 AM
MR. MAYER, addressing slide 6 entitled "Fixed Royalty v Profit
Based Fiscal Systems," answered Representative Gardner's
question regarding the impact of fixed royalty systems versus
net profit-based tax systems. He compared the first example,
which depicted five different projects each with a 30 percent
fixed royalty to five projects with a 50 percent profit-based
tax. He pointed out that these were five different projects
with five different cost levels. He noted that each project
included capital cost, operating cost, normal return to a
private investor on capital, and economic rent or income surplus
required to achieve a normal return on the capital that is
sometimes known as super profits.
MR. MAYER declared that the amount of economic rent generated by
a project would vary enormously depending on the cost structure
of that project, and thus project one would generate a lot of
economic rent while project five would generate a relatively
small amount of economic rent. Referring to the graph of the 30
percent fixed royalty in terms of five different cost structures
with five different projects for the same $100 per barrel price,
he pointed out that the black rectangles represent divisible
income, that is all of the cash and none of the costs. The bar
graph depicts a line straight across the graph at 30 percent
fixed royalty, which is at the $70 because $30 of the $100
barrel of oil goes to the 30 percent fixed royalty. In the case
of project one, then, there is a lot of economic rent and an
even larger portion is going to the private investor. In the
case of project five, all of the economic rent is being taken
through the 30 percent royalty as is all of the ordinary return
on capital. Clearly, that's a project that wouldn't move
forward under this stylized regime because there is no economic
rent or even a basic ordinary return on capital to be made.
MR. MAYER explained that part of the notion behind a profits-
based tax is that it eliminates the distorting impact such that
there are relatively lower taxes on the highest cost projects
and relatively higher taxes on the lowest cost projects, which
generate the most economic rent. He noted that this is a
stylized profits-based system, not like the Alaska system that
is progressive in regard to costs and may take even more of the
rent in certain cases. "The analogy being, in a sense, to the
25 percent ... base profits tax in Alaska. If we imagine a
system that was that at 50 percent with no other fiscal element,
that's sort of what we'd be looking at here," he said.
9:34:15 AM
MR. MAYER explained that the bar graph for the 30 percent fixed
royalty could be viewed as a percentage of a barrel of oil for
any given price per barrel, with each of the five projects
reflecting different oil prices. Therefore, the graph could be
viewed as the same project with the same cost structure in five
different price cases such that price case one would have very
high oil prices and price case five would have very low oil
prices. He reiterated that in a high oil price environment
fixed royalty is more attractive for investors, whereas the
profit-based tax is more attractive in a lower oil price
environment because the tax is reduced as the available profit
is reduced. In that sense, the system on the [50 percent
profit-based tax] is more economically efficient, as it does not
distort the investment choices as much. However, that does not
necessarily mean that it's competitive with what one can obtain
as a private investor in a jurisdiction with the investment
profile of [projects] one, two, or three. Mr. Mayer opined that
that the aforementioned is important in understanding how a
profit-based system, particularly one with a relatively high
government take such as Alaska, looks as compared to a fixed
royalty system elsewhere. A profit-based system with a
relatively high government take is very attractive at lower oil
prices, while less attractive, from a competitive standpoint, at
high oil prices, particularly when those jurisdictions have
relatively lower costs.
9:36:16 AM
REPRESENTATIVE GARDNER inquired as to the contextual definition
for rent and normal return of capital. She asked if normal
return of capital is part of the profit or the cost.
MR. MAYER explained that normal return on capital differentiates
the perspective of accountants versus economists. For an
accountant, profit is what remains after the costs are
subtracted from the income; however, for an economist profit is
what remains after all the capital invested in the project,
including the physical structures and the working capital, is
subtracted [from the income]. For an economist, anything above
the normal return on capital is economic profit. Therefore, on
the bar graphs on slide 6 the yellow and red bars represent
accounting profit, but only the red bars are economic profit,
which is the same as rent.
REPRESENTATIVE GARDNER asked what risk was calculated for a
normal return on capital.
MR. MAYER explained that the required rates of return for
capital are connected to the levels of risk, with lower risk
investments requiring lower rates of returns. He pointed out
that the standard benchmark is the U.S. Treasury rate, which is
a completely risk-free rate of return on capital. Any rate of
return required above the guaranteed return is considered a risk
premium. The significantly higher rate of return required for
an oil and gas project located in a stable jurisdiction versus a
project that holds a U.S. Treasury bill is reflective of the
risk one is taking in undertaking the project. Therefore,
projects in jurisdictions that are viewed as riskier by
investors require significantly higher rates of return to
compensate for the risk involved.
REPRESENTATIVE GARDNER asked for the benchmark of the U.S.
Treasury rate.
MR. MAYER replied that the rate varied depending on the
investment time frame. He stated that, although 5 percent had
historically been financially used as a risk free rate of
return, the current economic environment is a substantially
lower rate.
MR. MAYER, in response to Representative Tuck, said that Alaska
is "progressive with regard to price, but not particularly
progressive with regard to cost." He then turned to the bar
graph in terms of the same project in five different cost
environments and suggested layering in Alaska's progressivity
would result in the diagonal bar curving down and taking more of
the rent at the highest price environment.
9:41:33 AM
CO-CHAIR SEATON surmised that Mr. Mayer would be going into more
detail on the Alaska price structure.
9:41:52 AM
MR. MAYER, in further response to Representative Tuck, clarified
that he was referring to the chart entitled "Incidence of a 50%
Profit-Based Tax on 5 Different Projects" on slide 6 with the
angled line being a fixed 50 percent of the profit for a given
project. A system that is progressive with regard to price
would result in "1" being the highest price case that would
yield the most economic rent such that 60-70 percent of the
[profit] is taken and perhaps less than 50 percent in the lowest
price case, "5". Therefore, the line would steadily increase
from right to left to reflect more economic rent in high price
environments, which is what makes it progressive in regard to
price. Alaska's system is deliberately crafted such that at oil
prices net of cost above $30 per barrel, the share going to the
state through the petroleum profit-based tax (PPT) steadily
increases. He stated that although this is progressive with
regard to oil price, it is not progressive in the same way for
cost. Therefore, as costs rise, the amount of government take
stays the same and may, in certain circumstances, slightly
increase as costs increase.
9:43:20 AM
REPRESENTATIVE TUCK, recalling earlier testimony that a normal
return of capital is about 15 percent, surmised that the yellow
block on the bar graphs on slide 6 is 15 percent of everything
below it.
MR. MAYER expressed agreement that the yellow block is 15
percent of the capital costs, shown in green, with some portion
of the ongoing working capital required to maintain the project.
9:44:05 AM
REPRESENTATIVE HERRON asked how the bar graphs would change if
Alaska became an investor, instead of approving the tax
reduction in the proposed legislation.
MR. MAYER, directing attention to the equation on slide 5, said
that government take does not include the government earnings
directly from an equity stake. However, he said that government
take would be impacted if the government, as Alaska does to some
extent, provides tax credits as cost contributions to the
project with a correspondingly high tax rate afterward.
9:45:27 AM
MR. MAYER offered a brief overview of slides 7 and 8, "Regime
Competitiveness: Average Government Take," which compared Alaska
to a range of global fiscal regimes at $100 per barrel of oil,
slide 7, and $140 per barrel of oil, slide 8. He directed
attention to the two red bars, which represented the Alaska
take, under Alaska's Clear and Equitable Share (ACES), for new
oil developments and for an existing producer. He noted the
difference: an existing producer could claim capital costs
against existing costs for production, while a new development
producer could only claim upfront incurred capital costs against
net operating lost credit, which results in a slightly higher
government take. He stated that the yellow bars were all
Organization for Economic Cooperation and Development (OECD)
jurisdictions, which are developed, not developing, countries.
He explained that the benchmark analysis offers a range of
actual economic modeled projects as opposed to how this exercise
is frequently performed in which a single stylized field is run
through a range of different regimes. The idea, he specified,
is that in each regime there should be review of something that
comes close to approximating the actual levels of cost, field
sizes, and etcetera in order to view representative development
for each of the basins in terms of field size, production,
costs, and the resulting government take.
9:48:18 AM
MR. MAYER reported that oil price levels significantly below
$100 per barrel would reflect an impact on fixed royalty
regimes. He said when oil price was compared at $100 per barrel
and above, Alaska's fiscal regime was significantly higher than
all other OECD jurisdictions, with the exception of Norway;
whereas, below $100 per barrel, ACES was comparable to many
other jurisdictions. For an existing producer, [Alaska under
ACES] has the second highest level of government take in the
OECD countries. At a price of $140 per barrel, the government
take [in Alaska] for an existing producer is about the same or
slightly above Norway and is slightly higher still for new
development. For oil prices higher [than $140 per barrel],
Alaska finds itself among the very highest taxing jurisdictions
in the world. He clarified that he had focused on $100 per
barrel and $140 per barrel as these were the most recent price
boundaries over the last few years. He stated that the fiscal
regime in Alaska had been designed for high levels of government
take for existing production, and is notably higher for
government take of new development in the Lower 48.
9:50:32 AM
CO-CHAIR SEATON requested a copy of this same graph using an oil
price of $80 per barrel.
MR. MAYER agreed to do so.
9:50:52 AM
REPRESENTATIVE GARDNER inquired as to why Saudi Arabia, Kuwait,
and Iraq, which she opined to be some of the largest oil
producers in the world, are not included on the chart.
MR. MAYER explained that Saudi Arabia entirely owns and produces
its oil resource, and thus it is not relative to these other
fiscal regimes. The aforementioned is true, to some extent, in
Iraq and Kuwait as well. Iraq is a unique case because it has
recently invited service contracts with overseas oil companies
to invest capital and introduce new technology in an effort to
increase the oil production of long existing mature oil fields
that have been produced by the state. He offered his belief
that those [existing mature oil fields in Iraq] have a
relatively high level of government take, but that the fiscal
structure rewards contractors for increases in production over
certain benchmark levels. Companies have been willing to invest
in Iraq because it is viewed as a long-term strategic
investment.
REPRESENTATIVE GARDNER asked whether Norway is a hybrid model
similar to Alaska.
MR. MAYER concurred, declaring that, although Norway has high
levels of government take, it ensures ongoing investment
regardless of the private sector appetite. Norway has a large,
sophisticated national oil company, Statoil, which is a major
participant in Norwegian oil development. Norway also has a
state equity arm, Petoro, which also holds directly on behalf of
the state in those projects.
MR. MAYER, in response to Co-Chair Seaton, said that PFC Energy
has analysis of what HB 3001 looks like in comparison to ACES in
terms of government take. Although he did not have it in terms
of the benchmark chart [on slides 7 and 8], but he offered to
provide it.
REPRESENTATIVE SADDLER asked to also see the countries ranked by
annual volume of oil produced and cost of production.
MR. MAYER replied that it could be done, but it might be a
significant process. He noted that there is a correlation
between desirability of hydrocarbon basins and levels of
government take.
9:55:43 AM
MR. MAYER, referring to slide 9 entitled "Effect of
Progressivity on Price Upside," explained that the two graphs on
slide 9 reflect net present value (NPV) and internal rate of
return (IRR) over a range of various price environments. He
explained that the cost profile used is from the average North
Slope capital and operating costs directly from the Department
of Revenue (DOR) Revenue Sources Handbook and was graphed under
ACES versus with a flat 25 percent profits-based tax without any
progressivity. The graphs illustrate that under progressivity
as the price, economic rent, increases, the state is steadily
able to take more and more. The graphs use a relatively low
cost development and illustrate that the system works quite well
such that there is a 15 percent rate of return around the $60-
$70 price. As one reaches higher and higher price levels, the
idea behind the progressivity is that more and more rent is
taken for the state. In the low cost example, the impact of the
state taking [more] economic rent should not impact the economic
viability of the project. However, if one compares this to a
more neutral or regressive regime, a very economic project does
not alone make the project economic for capital. For example,
there are projects in the Lower 48 at high price environments
that look much better. Therefore, the question of
competitiveness remains. He declared the basic lesson from this
chart to be: ACES worked very well, in a harvest regime, when
there were low development costs while maintaining existing
production from existing fields with no significant new
investment.
10:00:31 AM
REPRESENTATIVE GARDNER expressed her understanding that the
desired outcome of the progressivity tax rate is to encourage
the industry to re-invest its profits in Alaska, rather than
elsewhere because their tax rates in Alaska would drop with each
dollar re-invested. She asked for clarification regarding
whether high prices were instead discouraging industry
investment and that industry would prefer a higher progressivity
rate in a harvest mode rather than re-invest and decrease the
rate on everything.
10:01:20 AM
MR. MAYER, noting that there were the two approaches, said that
progressivity is an approach to encourage investment such that
the high level of taxation could be lowered through re-
investment. The other approach would be for a lower level of
government take with an upside for higher oil prices, which is
more desirable for capital investment. High government take,
high costs, and the lack of an upside combine to make Alaska
less competitive, he said.
REPRESENTATIVE GARDNER opined that this made sense for a new
investment, without a broad infrastructure.
CO-CHAIR SEATON questioned whether progressivity would really
make a difference if companies had decided prior to the current
tax regime in Alaska that Alaska's mature oil basins were a
harvest regime.
10:03:44 AM
MR. MAYER related that there are various gradations to determine
that a jurisdiction is a harvest region, even if the investment
is limited to a low cost, easy investment. The decision would
be made at the corporate level, in large part, because of the
interplay of costs and economics of a new investment. However,
the fiscal system is but one component. There are issues over
which the state has no control, including the cost environment
and other competing uses of capital. He stated that the harvest
designation is not made in the abstract, but is a function of
the other possible uses of capital, returns available on the
uses of capital, and the returns available given the cost
structure and tax environment in Alaska. The question would be
whether Alaska is a place to invest and draw the capital in the
future, or to invest and draw cash now.
10:06:06 AM
CO-CHAIR SEATON asked if those decisions had been made prior to
the current tax system in Alaska on a low tax environment, and
whether lowering the taxes would reverse the decision made in a
lower tax environment.
MR. MAYER expressed his agreement that the oil producers had
taken cash out of Alaska long before ACES was implemented, as
Alaska was a cash surplus region. Therefore, he said he would
not suggest that the implementation of ACES created a harvest
system where none existed before. On the other hand, since [the
implementation of ACES], oil prices have become significantly
higher, technological advances have been made, and the Lower 48
is no longer a harvest regime. The question, then, is whether
there are projects that might be viable given the high oil
prices and technology in Alaska that are less viable because of
[Alaska's] fiscal system.
10:08:01 AM
CO-CHAIR FEIGE questioned whether it is the fiscal regime or the
actual field mechanics driving [Alaska] toward a harvest mode,
when it could be moving in a different direction with the
current increase in oil prices.
10:09:29 AM
MR. MAYER moved on to slide 10 entitled "Low Cost Light Oil:
Hypothetical 10 mb/d Project Cashflows ($13/bbl Capex, $10/bbl
Opex)," which presents the stylized impacts of cash flow for a
brand new development with a cost structure of $13 per barrel
capital expense and $10 per barrel operating expense. He noted
that the horizontal axis is at zero and anything above it is
revenue, as depicted in the blue bars, whereas anything below
the horizontal axis is capital development costs during the
initial years and then ongoing operating costs of $10 per
barrel. He specified that the black line is the after tax cash
flow (ATCF). The graph relates that in the early years, the
difference between the negative capital expenditure bar and the
slightly less negative ATCF line is the impact of the 20 percent
capital credit and the net overriding loss credit under ACES.
He noted that this capital credit reduces the negative cash flow
in the early years, thereby improving the overall project
economics. However, if the costs are subtracted from the
revenue [blue bar], that would amount to all the cash the
project produces. On the other hand, the ATCF [black line] to
the producer is "a relatively small portion of the overall
revenues generated from the project." The difference in that is
that the operating and the capital costs have to be covered as
well as the almost 80 percent of the revenue that goes to either
the federal or state government, which is a significant amount
at $100 per barrel. The amount left is the ATCF [black line] to
the producer that is shown at $100 per barrel in the graph, but
a small table on slide 10 indicates the NPV and IRR for oil at
$40, $60, and $100 per barrel. A hypothetical project, new
development, at a cost structure equivalent to some of the
current existing mature assets would result in a hurdle rate of
return at about $60 per barrel and $100 per barrel would look
quite attractive.
10:13:20 AM
MR. MAYER declared that this graph hypothetically reflects a new
development with the cost structure of an existing field and an
attractive rate of return at $100 per barrel. However, this
analysis for IRR would be different for actual existing
production as there is no longer an [upfront] lump sum creating
a return; the NPV would be higher, as there was no lump sum
upfront investment and only annual capital and operating costs.
The graph shows that this cost structure under ACES looks
relatively attractive.
10:13:56 AM
MR. MAYER moved to slide 11, "New Light Oil: Hypothetical 10
mb/d Project Cashflows ($17/bbl Capex, $15/bbl Opex)," which
uses the same production profile, but increases the capital
expenses to $17 per barrel and the operating expenses to $15 per
barrel.
REPRESENTATIVE SADDLER requested clarification that the blue bar
below the ATCF [black line] represents the producer's profit,
and above the black line represents the government take.
MR. MAYER replied that, although government take is not shown
explicitly, divisible income is the difference when the red and
yellow bars are subtracted from the blue bar. The divisible
income is all of the cash a project generates.
REPRESENTATIVE SADDLER asked what the blue bar above the black
line represents.
MR. MAYER replied that the blue bars represent the total revenue
for the project.
REPRESENTATIVE SADDLER agreed that he understood that the blue
bar is the total revenue, but he asked again for an explanation
of the blue bar above the ATCF [black line].
MR. MAYER said that the black line itself represents the ATCF to
the private investor.
REPRESENTATIVE SADDLER asked again what was represented by the
blue bar above the ATCF black line.
MR. MAYER replied that the portion of the blue bars above the
black line does not represent anything specifically. He
explained that if the operating expenses [red bar] and the
capital expenses [yellow bar] are subtracted from the revenue
[blue bar], the difference between that result and the black
line, would be the government take. In this hypothetical case,
the government take would be a bit less than 80 percent of the
total.
10:16:31 AM
CO-CHAIR SEATON stressed the need to better understand this
graph before moving forward with testimony.
10:17:14 AM
MR. MAYER said that to explicitly plot government take as a
third cost component, along with operating and capital costs,
there would be another negative bar which would roughly
counterbalance the blue revenue bar. He pointed out that, as
the result would not be as negative as the blue was positive,
the difference would be the ATCF black line. He clarified that
the difference of the total of the operating cost, the capital
expense cost, and the government take with the revenue would be
the "cash that the producer themselves gets."
10:18:11 AM
CO-CHAIR SEATON surmised then that the blue bar is for revenue,
and the cash for the producer is between the black ATCF line and
the axis. He asked if the area of the blue bar above the ATCF
black line is equivalent to government take.
MR. MAYER replied that it is equivalent to government take plus
costs. In response to Representative P. Wilson, he confirmed
that government take is not included on the graph.
REPRESENTATIVE TUCK related his understanding that the graph
doesn't include any tax structure or government take structure;
the graph, he surmised, is not explicit to one taxation system
versus another rather it is total costs and expenditures.
MR. MAYER specified that the after tax cash flow (ATCF) line,
which is based on ACES, is specific to a given tax structure.
10:20:20 AM
MR. MAYER directed attention to the graphs on slides 11, 12, and
13 that reflect the same production profile and revenue as slide
10, but each slide depicts increased operating and capital
expenses. Referring to the graph on slide 11 entitled "New
Light Oil: Hypothetical 10 mb/d Project Cashflows ($17/bbl
Capex, $15/bbl Opex)" that includes capital expenses of $17 per
barrel and operating expenses of $15 per barrel, he determined
that the acceptable rate of return begins at the $100 per barrel
price, whereas any lower price is "actively destroying economic
values." At $60 oil per barrel, the NPV is negative and the
rate of return is 9 percent, which is less than the 10 percent
discount rate that is used in this case. The graph on slide 12
entitled "Mid-High Cost Project: Hypothetical 10 mb/d Project
Cashflows ($25/bbl Capex, $15/bbl Opex)" depicts capital
expenses of $25 per barrel and operating expenses of $15 per
barrel, and states that the rate of return at the $100 per
barrel price is only 11 percent. Finally, the graph on slide 13
entitled "High Cost Project: Hypothetical 10 mb/d Project
Cashflows ($34/bbl Capex, $15/bbl Opex)," reflects a capital
expense of $34 per barrel and an operating expense of $15 per
barrel, with a 7 percent rate of return at $100 per barrel. The
initial yellow bars depicting the capital being spent on the
project become more and more negative and to obtain a rate of
return on that a correspondingly relatively higher amount of
cash flow afterwards is necessary. However, the cash flow only
changes marginally after the initial investment, which is why
the very low rates of return are experienced. In fact, at $34
in capex per barrel, there is a negative NPV at a 10 percent
discount rate, even at $100 per barrel of oil.
10:22:20 AM
CO-CHAIR SEATON, directing attention to slide 11 with the
$17/bbl capex, posed a scenario in which there is new light oil
new field development with a 65 percent exploration tax credit
and convertible tax credit. He then asked if the exploration
tax credits would affect the 2011 and 2012 bars on the graph.
MR. MAYER responded that this graph depicts a development
forward basis and does not include exploration costs, only the
capital costs required for development and the resulting
revenue. He declared that the 20 percent capital credit and the
25 percent net operating loss credit should both be applied, but
he noted that, they may be applied with a year lag.
Furthermore, under ACES, those credits are spread over two
years. He reported that the biggest impact should come in the
third year, 2013, after there have been a couple of years of
capital spending.
10:24:11 AM
CO-CHAIR SEATON pointed out that one provision of HB 3001 is
that the credit would be for one year, instead of spread over
two years, which he surmised would move the cash flow line
(indisc.) negative for the first two years.
MR. MAYER agreed that for a new project it would make a small
difference in the first couple of years.
REPRESENTATIVE TUCK related his understanding that on the graph
development is represented prior to the blue bars and the blue
bars are production.
MR. MAYER expressed his agreement, but reminded the committee
that there are ongoing capital expenses for drilling.
REPRESENTATIVE TUCK surmised then that the blue revenue bars
reflect the usual peak and then subsequent decline as an oil
field moves into production.
MR. MAYER replied yes, noting that the decline would be more
dramatic if it represented volume rather than revenues. The
graph is an illustration based on a nominal cash basis, and thus
there is about 2.5 percent inflation, which offsets the actual
underlying decline of the production by the 2.5 percent
inflation and each year the value of the dollar is less and the
revenue from it is 2.5 percent greater. He pointed out that the
graph is a stylized hypothetical profile which could look
different under different circumstances, or relative to
unconventional production fields. In certain places one may be
able to achieve a production profile with a faster and higher
peak and a faster decline, which is in many ways economically
preferable. Such a situation would mean that one could recover
cash much faster, which improves one's economic metrics.
However, production profiles for Oooguruk, for example, do not
look particularly like earlier "peakers" with sharp declines but
rather steadier producers with a shallower decline and a less
significant initial peak, which makes projects more economically
challenged than those with higher initial production. On the
other hand, the unconventional resource plays in the Lower 48
would require less initial capital for any given level of
spending but more ongoing capital spending throughout the life
of the project as more wells are drilled, which is not
necessarily the case in conventional oil development.
10:28:04 AM
MR. MAYER, referring to slide 13, stated that as the yellow bar
[capital expenses] increases the corresponding cash flow
[revenue] needed to offset the initial expenses needs to be
higher, but is not. As is evidenced on the slide, the rates of
return and present values are steadily lower. Referring to
slide 12, Mr. Mayer said that the $25 per barrel capital cost
was not attractive to oil producers, even at a price of $100 per
barrel, and, noting slide 13, said that $34 per barrel capital
cost is "actively destroying economic value," even at a price of
$100 per barrel.
10:29:05 AM
MR. MAYER, moving on to slide 14 entitled "Project Value Under
ACES: Cost and Price Sensitivity", compared project present
value over time under a number of different cost cases,
including low cost light oil and capital costs of $17 per
barrel, $25 per barrel, and $34 per barrel. He pointed out
that, as costs increase, the break even points of these high
cost developments increase, such that the $25 per barrel capital
cost did not break even until a price of almost $90 per barrel.
In terms of the internal rate of return, the graph entitled
"IRR" on slide 14 illustrates that a 15 percent rate of return
was not achieved until the price per barrel was $130-$140,
whereas a constant government take would achieve a 15 percent
rate of return at a price less than $100 per barrel. He
declared that ACES works well for existing, mature, low cost,
light oil fields that capture the most economic rent for the
government from the production while ensuring that production
remains ongoing and economic. However, this structure could be
a significant inhibitor for developing new projects with higher
costs.
10:31:27 AM
REPRESENTATIVE P. WILSON asked how much this would change at a
price of $120 per barrel.
MR. MAYER explained that the horizontal axis of each graph is
the oil price. The graphs illustrate the sensitivity of four
different projects of project value measured by two different
economic metrics, NPV and IRR, in different price environments
and what the specified price increase does to the project value.
The bending of the curve, he pointed out, is the impact of the
progressivity such that the marginal benefit of each additional
dollar is less and less.
10:33:00 AM
MR. MAYER, in response to Representative P. Wilson, explained
that when oil is priced at $120 per barrel, the economics is
challenging for all the heavier [oil] projects, except for low
cost light oil. For example, in the $34 capex case it has yet
to break even on a 10 percent discount rate, and therefore it
has negative NPV at the $120 price per barrel.
REPRESENTATIVE P. WILSON opined that it would be easier to
understand this if the current prices were used.
MR. MAYER reminded the committee that the aim of the chart is to
show a broad range of prices and how, as prices changes, the
value of the project is impacted. The curvature is from the
progressivity, which takes away the upside of high oil prices.
The chart reflects that the higher cost cases impact the basic
breakeven economics of the project, which makes it challenging
for a project to meet the basic hurdle rate for returns on
capital, not to mention being cost competitive with investments
in other jurisdictions. In further response to Representative
P. Wilson, Mr. Mayer explained that the IRR chart reflects a
healthy rate of return, approaching 25 percent, for the low cost
light oil project at a price of $120 per barrel, whereas the
most expensive development, $34 per barrel for capital expenses,
results in less than a 10 percent rate of return on the project.
10:36:06 AM
CO-CHAIR SEATON related his understanding that the chart
represents a stand-alone project. He also related his
understanding that under ACES, a high cost environment would be
written off against existing production, which would lower the
tax rate on the oil. He then asked how [ACES] changes the chart
for incremental production at the higher tax rate when there is
no higher cost investment to lower the overall tax rate by
lowering the marginal tax rate on progressivity.
MR. MAYER returned attention to slide 13 and said that it is
related to the impact of the capital credits, particularly in
the early years when there is very little oil production. He
said that on a stand-alone basis, for a company with no existing
production, the most credit that could be claimed would be the
20 percent capital credit and the 25 percent net overriding loss
credit. He stated that this would be the same for an existing
producer in a price environment without progressivity; however,
once the existing producer has triggered progressivity, the
capital could be written down at a higher rate, because of the
higher rate that comes with progressivity. He declared that in
the first few years an ATCF line would appear less negative for
an existing producer if this was viewed as a stand-alone, with
the ability to write it off against the existing portfolio.
10:38:52 AM
MR. MAYER, in further response to Co-Chair Seaton, said that the
curves might shift up a teeny bit if the existing production is
considered with higher costs and the marginal tax rate, but that
overall there would be no change in the deduction.
10:39:04 AM
REPRESENTATIVE GARDNER asked if the model for capital and
operating expenses used by Mr. Mayer is in anticipation of
realistic expenses.
MR. MAYER explained that the figures were similar, as they are
an average of all capital expenses divided by all production
across the North Slope in any given year. He allowed that the
average did hide a lot of variation, as projects would differ.
He explained that, for an aggregate analysis to the generated
revenue of a taxation system, "plugging in that sort of average
number is a good way of getting an approximate answer."
However, just looking at the aggregate did conceal the enormous
disparity between the capital expenses required for existing and
new developments.
10:41:41 AM
REPRESENTATIVE GARDNER asked to verify that the evaluation and
calculation of NPV and IRR for a prospective investment does not
include the state participation in capital costs. She also
asked why that should be the case when the decision is not
impacted by it.
MR. MAYER opined that project economics are determined by after
tax cash flow (ATCF), which credits definitely impact. He
pointed out that Alaska is unusual as its credits are paid at
the outset, as opposed to being deducted from future production,
which has a significant impact on project economics. Although
Alaska is a high government-take regime, these upfront credits
work for low cost production.
REPRESENTATIVE GARDNER, confirming that the prompt payment of
credits is "a plus in an evaluation," asked whether [the
credits] are included in NPV or IRR.
10:43:06 AM
MR. MAYER established that the credits are included in the NPV
and the IRR and are implied by the ATCF black line on the chart.
Directing attention to slide 13, he pointed out that to the
extent in the early years that the black line is not as negative
as the capital expenses is the positive impact generated by the
credits and improves the economic metrics of the project.
CO-CHAIR SEATON suggested that this same question be asked to
the upcoming oil industry witnesses for verification.
10:44:17 AM
REPRESENTATIVE TUCK, directing attention to slide 14, related
his understanding that the low cost light oil is equivalent to
the $13 per barrel costs. He then asked if all of the lines on
the graph are for newly developed fields or wells.
MR. MAYER replied that they represent newly developed fields at
different cost structures.
REPRESENTATIVE TUCK surmised then that these aren't existing
fields but rather are fields in which the find is known and it
is set to be developed and come online.
MR. MAYER agreed, and explained that the red line for the low
cost light oil is used to compare the hypothetical development
of a new project at that cost structure in order to be able to
compare it to the other cost structures.
10:45:23 AM
MR. MAYER summarized that slide 14 reflects ACES in various cost
environments. Moving on to slide 15 entitled "ACES - Effective
as a Harvest Area Fiscal Regime," he declared that ACES works
well as a harvest regime, particularly when the policy goal is
for maximum extraction and economic rent and the belief is there
is no significant additional oil production, regardless of price
or technological advancements. However, ACES inhibits the
development of new projects and resources that have higher costs
than the existing production base for a number of reasons. As
has been mentioned, ACES is not progressive with regard to costs
and it is a high government take system that has a high
government take, even for very high cost projects. He
acknowledged that ACES has capital credits that go far in making
a lot of existing capital work and takes projects from a 15
percent natural decline of fields to a 6 percent level.
Although that combined with the high government may encourage
some of the renewal capital expenditures, it is not enough for
new high cost development to be economic or competitive in a
broader global company portfolio. Furthermore, although
progressivity can be effective in capturing maximum rent with
low cost projects, it can have a "significant detrimental impact
on break even prices and hurdle rates of return, and all the
rest for high cost projects at current oil prices."
10:47:58 AM
MR. MAYER, moving on to slide 16 entitled "Options to Spur New
Developments," suggested there are different approaches,
including uniform lowering of government take and
differentiation between old and new production. In order to
lower the uniform government take one can bracket progressivity
as was the case with HB 110, increase the thresholds for
progressivity, reduce the coefficients on progressivity, cap
progressivity at different rates, or lower the base rate tax.
He offered that there are some advantages to a lower government
take; as ACES is already a complex system, thereby lowering the
government take would not add any increased complexity or
ambiguity with regard to which projects apply for the various
tax regimes. He declared that this could even present
opportunities for simplification.
10:49:50 AM
MR. MAYER then pointed out that a big disadvantage of proposed
HB 3001 is that incentivizing new high cost resources through
lowering government take alone would require lowering government
take quite a lot, and thus give back substantial economic rent
on the already producing low-cost assets that were clearly
economic.
10:50:16 AM
MR. MAYER reflected that the simplest approach, with the least
ambiguity and possibility for misalignment for unintentional
consequences, requires returning the most cash back for
activities that are currently economic. An alternative to the
aforementioned is to find ways of differentiating between old
and new production. He acknowledged that it is relatively easy
to differentiate completely new production from areas that are
not currently in production, which is included in HB 3001.
Although it is more difficult to differentiate existing
production that is the result of existing levels of investment
in legacy fields versus production from increased investment in
the legacy fields, it could be achieved by defining the base
decline rate and applying a significantly lower level of
taxation. The regulatory process could also be used to apply a
lower rate of tax, but not to the base production. The
advantage of the regulatory process is that it does not require
returning a lot of cash for existing activities that are
currently economic. However, it is more complex
administratively and increases the opportunities for "perverse
incentives, whether that be ... alignment of partners on
different projects ...."
10:53:49 AM
MR. MAYER provided that there is a third option to further
enhance some of the cost progressivity of ACES, although this
would also increase the already high complexity and opacity of
the system. He declared that almost any solution would
exacerbate existing problems of relatively poor incentives for
cost control that currently exist. He emphasized that there are
no perfect answers, as it is a policy trade-off between the
degree to which one is willing to return cash for currently
economic activities versus the degree to which one tries to
avoid that and reaches greater complexities and greater
likelihood of "perverse incentives" by trying to create a system
that preserves as much cash as possible for the government while
providing significant new incentives for development.
10:55:43 AM
The committee took an at-ease from 10:55 a.m. to 11:21 a.m.
11:21:11 AM
CO-CHAIR SEATON brought the committee back to order at 11:21
a.m.
11:21:20 AM
MR. MAYER moved on to the section of the presentation entitled
"Analysis of HB 3001." He directed attention to slide 18
entitled "Options to Spur New Developments," which he declared
to be a range of imperfect options to spur new developments,
with specific attention to the uniform lowering of government
take versus the differentiation between old and new production.
He stated that proposed HB 3001 overwhelmingly takes the
approach of uniform lowering of government take, but with more
complexity by putting in place a gross revenue exclusion that
applies in calculating the progressive tax. The overall effect
is to reduce the progressive tax on the existing base of North
Slope production. The legislation also includes an allowance
for new oil production areas outside the legacy fields, which is
from the Senate's initiative at the end of the regular session.
The allowance for new oil production areas outside the legacy
fields uses a gross revenue exclusion at a lower rate, while
applying both to the 25 percent base tax and the progressive
tax, all of which results in the uniform lowering of government
take. He then turned to the approach of HB 3001 that offers
enhancements to the cost progressivity of ACES and said it
increases the capital credit from 20 percent to 40 percent for
well capital expenses.
11:23:28 AM
MR. MAYER then directed attention to slide 19 entitled "HB 3001
- Main Aspects," which specifies that the main aspects of HB
3001, as follows: a 30 percent gross revenue exclusion for
production from new North Slope fields, which would apply to the
calculation of both the 25 percent base tax and the progressive
tax amounts, but would not apply to the progressivity rate
calculation and would apply for 10 years; a 40 percent gross
revenue exclusion for all other North Slope production, which
would only apply to the calculation of the progressive tax
amount, not to the base tax or the progressivity rate
calculation and would apply indefinitely. Additional features
of HB 3001, are as follows: the maximum progressive tax rate is
capped at 60 percent instead of 75 percent; the well lease
expenditure credit of 40 percent would now be applied to the
North Slope; and the capital credits could be redeemed in a
single year rather than spread over two years.
11:24:44 AM
MR. MAYER reviewed slide 20 entitled "Understanding the Gross
Revenue Exclusions." He said that the framework used by the
Department of Revenue (DOR) in the Revenue Sources Handbook
considers the total annual production and subtracts the royalty
barrels to reach the taxable barrels. He compared the resulting
calculations under ACES versus proposed HB 3001. The results
are the same for the gross value at the point of production
(GVPP), which was the gross revenue from production minus the
transportation costs. He explained that the capital and
operating expenses were also deducted to determine the
production tax value (PTV), which is the same under ACES and
HB 3001 for both existing and new fields.
11:26:29 AM
MR. MAYER pointed out that he had included the calculations for
both new fields and existing fields under proposed HB 3001 to
show how they would work and how they would differ from each
other and ACES. He pointed out that the bottom line [of the
chart] represents the likely revenue from the state in 2013
under ACES and HB 3001 for existing fields. However, the bottom
line of the [column entitled "HB 3001 New Fields"] is a
hypothetical bottom line that would apply if the regime for new
fields was applied to all production. He clarified that the
[column entitled "HB 3001 New Fields"] is included to illustrate
how the calculation works. With a PTV of $12,385 million, under
ACES that is the PTV used in calculating the 25 percent base tax
amount and it's the amount used in calculating the progressive
tax. He then explained that 25 percent of $12,385 billion
amounts to about $3 billion under ACES and if the 16.72 percent,
which is the progressivity that would apply at the 2013 forecast
number, is multiplied by the PTV, it amounts to a progressive
tax just over $2 billion and a total production tax before
credits of about $5.167 billion.
11:28:08 AM
MR. MAYER said, in comparison to HB 3001, the calculation of the
25 percent base production tax is the same for both ACES and
HB 3001 for existing fields such that the $12,385 billion PTV is
multiplied by 25 percent, which amounts to $3,096 billion in
base tax. The difference, however, is the amount that's
calculated for the progressive portion of the profits based tax,
which amounts to $12,285 billion under ACES and $5,423 billion
under HB 3001 [existing fields]. Under HB 3001, 40 percent of
the GVPP is taken from the PTV to reach $5,423 billion. As a
result, the progressive production tax under HB 3001 is much
less than under ACES, and thus the total production tax
liability before credits decreases from about $5.1 billion to $4
billion. Under [HB 3001] there is also an increase in the
credits, which he partly attributed to the question of claiming
credits for one year versus two years but mostly because of the
40 percent well credit. Therefore, the overall impact to the
state amounts to an estimated $4.7 billion of income to the
state in 2013 through the production tax in 2013 versus $3.2
billion under HB 3001 for existing production. In terms of
calculating the exclusion for completely new areas, the
difference is that gross revenue adjustment is calculated at a
lower level of 30 percent rather than 40 percent but it applies
to both the production tax value as it is used to calculate the
base and the progressive tax. Therefore, the 25 percent base
production tax for existing fields is significantly lower than
it is in the aforementioned two cases because of the 30 percent
gross revenue exclusion. The progressive tax [under HB 3001 for
new fields] is higher than it is under HB 3001 for existing
fields but lower than it is under ACES because the 30 percent
exclusion but not the 40 percent exclusion applies. The fact
that it applies to the base as well as the progressive tax means
that overall the tax liability is lower than is the case for
HB 3001 for existing fields. Therefore, in the purely
hypothetical case [HB 3001 for new fields] applying a regime
that would apply to all production would result in production
taxes of oil credits decreasing from $5.1 billion [under ACES]
to $4 billion [under HB 3001 for existing fields], and
ultimately to $2.9 billion [under HB 3001 for new fields].
11:31:30 AM
CO-CHAIR SEATON, referring to slide 19, related his
understanding that the 30 percent gross revenue exclusion does
not apply to the progressivity rate calculation.
MR. MAYER concurred, and stated that it applies to the
progressive tax but not to the rate calculation. He highlighted
the importance of the fact that the 16.72 percent tax rate is
the same for all three scenarios and that the price per barrel
is calculated by dividing a PTV by the number of available
barrels, which amounts to PTV per barrel of $71.80. He said
that this calculation is done before the GVPP allowance, which
is the reason it does not affect the progressive rate. However,
in the new fields case [the 30 percent gross revenue exclusion]
does impact the progressive tax because although the rate does
not change, the taxable base does by the 30 percent.
REPRESENTATIVE SADDLER inquired as to whether saying that the 30
percent gross revenue exclusion does not apply to the
progressivity rate calculation means it does not apply to the
gross revenue as reduced by progressivity. In response to Mr.
Mayer, Representative Saddler clarified that he is referring to
new fields.
MR. MAYER replied that it applies to the calculation of the
progressive tax base, but it does not change the rate that is
calculated through progressivity.
REPRESENTATIVE SADDLER surmised then that the 30 percent applies
to the gross revenue, exclusive of the progressivity rate
calculation.
MR. MAYER clarified that the amount of progressive tax paid is
lower because the taxable base is less, even though the
percentage is the same.
11:33:57 AM
CO-CHAIR SEATON surmised that 30 percent of the barrels are not
taxable and the rate calculation based on price does not change.
MR. MAYER expressed his agreement, but noted that although 30
percent of the revenue is not taxable, the cost deduction that
came from those barrels remains.
11:34:22 AM
REPRESENTATIVE SADDLER, referring to slide 20, inquired as to
the basic assumptions of the hypothetical case presented for
HB 3001 new fields.
MR. MAYER replied that the column entitled "HB 3001 New Fields"
is hypothetical in so far as there are no known fields producing
in 2013 that meet the criteria for new production under HB 3001.
Therefore, the figures merely reflect how the calculations work
as there is no production that is new.
11:35:14 AM
CO-CHAIR SEATON inquired as to whether the exclusion of 30
percent of the oil from taxation allows the cost to be offset
against the other 70 percent and essentially becomes an uplift
or escalation of costs by 30 percent. In other words, instead
of making that calculation on the production tax value, the 30
percent is taken prior to the costs and basically allows a 30
percent increase in the cost per barrel that will be taxed.
MR. MAYER offered his belief that the "basic intuition of what
you said rings true to me," although he expressed the need to
run a few numbers before providing a conclusive answer.
11:36:29 AM
REPRESENTATIVE TUCK returned attention to slides 16 and 18 and
the statement that ACES inhibits the development of new
projects. He also recalled that it is possible for the State of
Alaska to go "upside down" on these tax credits. He questioned
how that's not an incentive to go into these new oil fields.
MR. MAYER agreed that there could be cases in which the tax
credits, on a discounted basis, could outweigh the production
tax from those credits in the future. However, the government
take across the entire system still does not change very much
whether it is a low cost or a high cost project. He declared
that the initial investment by the state through the tax credits
pays off through taxes and royalties on future production and in
almost all cases the cash flows/income from those revenue
streams is usually greater than the investment from the credits.
For example, if the initial tax credits are considered a roughly
35 percent tax credit investment in the project, the cash flows
from those are usually significantly greater than 35 percent of
other project cash flows, though the production tax itself in a
very high cost project may not be. That said, Mr. Mayer said
that he has not observed many cases of consistently high enough
costs that overall the value from the project, just in the
production tax, would not be greater than the initial credits.
He reminded the committee that high costs mean that there isn't
very much divisible income because much of the barrel is taken
out in costs. There is a cost and price case for which the 12.5
percent royalty alone would take all the divisible income.
Therefore, some high cost projects need a lower government take
than the system offers in order to be economic, but the problem
is providing incentives without sacrificing the overall
government take structure.
REPRESENTATIVE TUCK surmised then that it is a greater advantage
to an existing producer than to a new developer for investment
in heavy oil.
MR. MAYER expressed agreement, as there is a bigger benefit for
writing off those costs against an existing progressivity tax
base as opposed to the tax credits.
11:41:04 AM
REPRESENTATIVE TUCK asked whether reserve taxes are a viable
option for increasing production.
MR. MAYER answered that he is aware of reserve taxation as an
idea in principle, but not aware of many regimes that practice
it. It is more common for jurisdictions to include into lease
agreements more powerful relinquishment clauses for development
within a given time period or the rights to the asset are
relinquished. He said he has not seen enough modeling on
reserve taxation to offer any insight to the efficacy of it.
However, he offered his belief that it is more likely to have
adverse impacts.
11:43:31 AM
REPRESENTATIVE SADDLER, addressing slide 20, asked if there is
any significance to the red and blue colors assigned various
numbers.
MR. MAYER explained that the idea is to illustrate in color
where there had been a change due to the application of the
allowance. The three numbers in red are the result of the 30
percent gross revenue exclusion applied to the base calculation
and the blue numbers represent the resulting tax calculations,
whereas the black numbers are "common across all regimes."
11:46:21 AM
MR. MAYER, returning to his presentation, directed attention to
slide 21 entitled "Purpose of Gross Revenue Exclusion Concept."
He began by highlighting that the ACES production tax is a
profit-based tax as it taxes wellhead revenue net of costs.
Under the ACES structure, varying the base amount of tax, the
progressive rates, or anything to do with the production tax for
different streams of production is extremely difficult and would
require "ring fencing" to allocate different costs to different
streams of production. The aforementioned adds complexity to
ACES. He reported that the basic concept of the Gross Revenue
Exclusion would allow a reduction in government take on some
streams of production, but not others, without the requirement
for "ring fencing." He explained that it could reduce the
progressive tax without having to account for the costs that
accompany a particular asset, by subtracting the gross revenue
as an allowance in calculating the overall production tax
liability for a producer. The aforementioned would be used as a
way to reduce the base in the progressive tax on a particular
stream of production that is desired to be incentivized. Mr.
Mayer reminded the committee that the Senate worked the
aforementioned into its legislation at the end of the regular
session as a way in which to address incentivizing completely
new areas without ring fencing. However, if one wants to
utilize ring fencing, then progressivity can be reduced or
eliminated altogether for specific assets while maintaining a 25
percent base. If one wants to avoid ring fencing, the Gross
Revenue Exclusion is a useful concept to obtain similar
economics over the life cycle by taking out the gross revenue
that comes from a particular stream of production from the
producer's overall tax liability. He said that this would
provide a simple manner in which to calculate the impact of new
assets without needing to know what costs went where.
Interestingly, HB 3001 applies the gross revenue exclusion
across all North Slope fields. He noted that [the gross revenue
exclusion] was only applied to the progressive tax not the base
tax, which basically results in lowering progressivity. Drawing
from his initial analysis, he related that reducing
progressivity from .4 to .15 [percent] would result in about the
same impact as the 40 percent gross revenue allowance in
HB 3001, and would do so in a simpler, more transparent way.
The benefit of a gross revenue exclusion is the ability to only
apply the benefit to a specific stream of production and it is
easy to implement within the structure of ACES. "It seems to
me, an odder way of achieving the aim of lowering government
take overall when one could achieve the same aim just by
reducing the progressivity coefficient," he opined.
11:51:08 AM
CO-CHAIR SEATON, referring to modeling, inquired as to how
viewing a 30 percent exclusion as being equivalent to a 30
percent increase in costs is different than having a higher cost
field.
MR. MAYER answered that [viewing a 30 percent exclusion as
equivalent to a 30 percent increase] increases benefits to the
producer from the higher costs, particularly early on. For
instance, the overall economics of a 30 percent gross revenue
allowance for new production under HB 3001 versus eliminating
progressivity under ACES for the early years looks fairly
similar to the producer, in terms of net present value and
internal rate of return. However, the overall government take
on a discount basis is probably higher under the gross revenue
exclusion because the impact of the exclusion is that the cash
flow looks better in the early years. Capital expenses are
higher in the early years of production, while there are more
operating costs in the later years. He pointed out that the
high capital expenses combined with the gross revenue exclusion
results in low tax payments in the early years. However, when
all that is left is the operating cost, the level of tax paid is
probably more than would be paid under ACES with no
progressivity. The fact that the benefit is front loaded to the
early years makes the project economics look relatively good,
while the overall undiscounted government take is probably
higher than it would be, for instance, under a flat 25 percent
base tax.
11:53:36 AM
MR. MAYER then turned to slide 22 entitled "FY 2013 Revenue
Comparison," which charts the overall impacts on revenue to the
State of Alaska from HB 3001 with oil prices ranging from $40 to
$200 per barrel. He listed the various categories to include
Production Tax, Total State Take, Total Government Take, Cash to
Companies, and FY 2013 % Government Take. He then pointed to
the example in the chart of the revenue generated from the
production tax at $110 per barrel, which relates the revenue
generated: Under ACES $4.782 billion; under HB 3001, without
the 40 percent well credit, $3.597 billion; under HB 3001, with
the 40 percent well credit, $3.302 billion; and under HB 110,
$3.210 billion.
11:55:42 AM
REPRESENTATIVE TUCK asked whether the examples are for existing
production or for new fields.
MR. MAYER replied that this is the same high level calculations
the Department of Revenue presents in its Revenue Sources Book,
in particular in the appendix pages. "If one assumes away all
of the data, all of the complexity of different producers and
different fields and different costs, and just says 'We can get
pretty close to the overall tax liability here, from assuming
all of this production comes from one enormous field with one
owner, with ... a cost that's equal to the average cost of the
Slope.'" In that case it's going to be around $13 a barrel in
capex and ... under $10 a barrel in opex, if you do it on a per
barrel rather than a per taxable barrel basis."
11:56:50 AM
REPRESENTATIVE SADDLER inquired as to the amount of production.
MR. MAYER replied that the total production amount equals the
2013 DOR forecast of 555,000 barrels per day or annual
production of just over 200 million barrels.
REPRESENTATIVE SADDLER surmised then that slide 22 is a stylized
chart based on 555,000 barrels of daily production, with a
capital expense of $13 per barrel, and an operating expense of
$10 per barrel.
MR. MAYER expressed his agreement, and noted that these figures
were all based on Department of Revenue fiscal year (FY) 2013
forecasts.
11:57:51 AM
MR. MAYER, continuing his review of slide 22, pointed out the
similarity in the revenue generated by both ACES and HB 3001
without the 40 percent well credit when oil prices are $60 per
barrel and below, as progressivity has not yet been triggered.
The difference illustrated is the result of the increased
capital credit. He noted that the impact is magnified as the
price per barrel increases, with a revenue difference of almost
$4 billion between ACES and HB 3001 when the price of oil is
$200 per barrel. The impact is greatest when the progressivity
is greatest. He then directed attention to the FY 2013 percent
of Government Take columns, and explained the difference between
the take for the life cycle of a project and for a fiscal year.
He explained that the life cycle of a project is impacted by
inflation, but since the thresholds at which progressivity kick
in for ACES are not linked to inflation the impact under ACES is
such that government take steadily increases over time as in
real terms the threshold through which progressivity kicks in
comes down. Therefore, the life cycle analysis of government
take for ACES is more likely to be 82-83 percent, whereas for
only FY 2013 the high reaches about 78 percent for ACES. He
reiterated that the government take at the $60 barrel price is
the same, about 66-67 percent, for HB 3001 without the 40
percent oil well credit. The 40 percent oil well credit in both
HB 110 and HB 3001 is what makes the difference at the $60
level. Still, HB 110 and HB 3001 look relatively similar in
terms of overall government take, and therefore progressing at a
much lower slope from a level in the mid 60 percent to a maximum
of about 70 percent versus ACES, which reaches 78 percent in the
highest price cases.
12:00:51 PM
MR. MAYER, in response to Representative P. Wilson, explained
that the columns entitled Total State Take represent the total
take to the State of Alaska that is all of the components of the
fiscal regime, including production tax, royalty, property tax,
state income tax, and federal income tax. The federal income
tax in Alaska is calculated assuming the nominal rate of 35
percent.
12:01:21 PM
MR. MAYER addressed slide 23 entitled "FY 2013 Government Take
Comparison." Comparing the government take in more detail for
FY 2013, he pointed to the steeper upward slope of the ACES
graph until the percentage of take reached 75 percent and it
began to flatten. He then pointed out that the government take
for HB 110 and HB 3001 for existing production is very similar,
especially for $100 per barrel and above although HB 3001 has
slightly lower government take for existing projects in the $50-
$80 per barrel price range, which he attributed to the 40
percent well credit. With regard to new production, HB 3001
looks better than HB 110 at low price levels, but at higher
price levels of $120 per barrel there is a higher level of
government take than occurs for HB 110 for new production.
12:03:11 PM
MR. MAYER moved on to slide 24 entitled "$17/bbl Field: Project
Value Under Different Fiscal Options," and compared the graphs
for NPV and IRR at $17 per barrel under various fiscal regimes.
He noted that a flat tax would create a straight line, as
opposed to the curved line from progressivity. He pointed out
that all of the proposed changes effectively reduces
progressivity and gets closer to the straight line. Although
the $17 price per barrel does not make a huge difference in
terms of breakeven economics, the IRR is affected such that the
level at which the 15 percent rate of return is achieved moves
from about the $90 range to the $80 range, if the field is taxed
under the existing production level and down to the $70 range if
it is taxed under the rate for new production. Those
differences become further magnified for the higher cost fields,
as shown on slide 25 entitled "$25/bbl Field: Project Value
Under Different Fiscal Options." If the same exercise is
performed for the $25 per barrel field, the NPV10 breakeven when
the economic value starts moves from $90 to $80 and then to the
high $70s, depending upon which tax regime is applied. Again,
there is a large difference at the level at which the 15 percent
rate of return is achieved, such that the $130-$140 per barrel
can decrease to $100 or $90 per barrel. Similarly, in the
highest case, a $34 per barrel field [as illustrated on slide 26
entitled "$34/bbl Field: Project Value Under Different Fiscal
Options,"] the NPV10 breakeven was not achieved until $130 per
barrel. That price can be brought down to $100 or below in the
difference that is made through progressivity. He attributed
that to the divergence such that the ACES line bends away due to
the high progressivity and the breakeven point is significantly
reduced as is the point at which the 15 percent IRR is achieved.
For a project this challenged, particularly on a stand-alone
basis without the benefit of some of the other benefits, the
economics remain challenged at the various cost levels
presented, even under HB 110 or HB 3001 for new production. He
declared that this is the impact on improving the economics on
new higher cost development.
12:06:24 PM
MR. MAYER, referring to slide 27 entitled "40% Well Credits
Create High Levels of Government Support," said the question of
how much revenue one is willing to forgo to have that impact and
whether that impact should be targeted at new incremental
production as opposed to all production remains. He then spoke
about the high levels of effective government support which
occur under the 40 percent exploration credit combined with
progressivity under ACES, or the 40 percent well expenditure
credit. He reported that the tax benefit of writing off an
expense against the existing taxable production base, including
the ability to reduce the payable tax under progressivity, and
then include the 40 percent credit, would result in very high
levels of government support. For example, when the oil price
is $120 per barrel, under progressivity an approximately 50
percent production tax is being paid. Further, if a company
spends $100 million on work that qualifies for the credit and
can, in addition, obtain a 40 percent credit, the after tax cash
flow would only be worse off by 10 percent of the cost of the
well work, with the remaining 90 percent of expense covered by
the 40 percent credit or the 50 percent effective production tax
that the company is not paying on that amount. A 60 percent cap
rather than the 75 percent cap on progressivity results in
exceeding 100 percent when the price of oil reaches $210-$220
per barrel. Overall, the 40 percent well credit creates very
high levels of effective government support.
12:09:29 PM
CO-CHAIR SEATON asked whether the state corporate income tax
reduction would be added to this as well.
MR. MAYER replied that he was unsure, as it would depend on what
portion of the spending is capitalized and hence, depreciated,
and what portion is expensed. To the extent that it is
capitalized and depreciated, it would be spread over a longer
time and have a lesser impact.
CO-CHAIR SEATON surmised that government support referred to
state dollars used in the project, whether they are offset by
reductions in property tax and credits.
MR. MAYER answered, "That's certainly one way of looking at it."
However, it is a view that the companies would not necessarily
agree with because they are spending the actual dollars. Still,
at the end of the year, when all the tax implications come to
bear, the after tax cash flow is only worse off by 10 percent of
the total cost at the $120 price per barrel.
12:11:20 PM
CO-CHAIR SEATON replied "if they're looking at it in those terms
when they are calculating the competitiveness of the project, do
all those terms get added in on the competitiveness of the
project ...?"
MR. MAYER replied that the economic metrics of IRR and NPV are
impacted when the after tax cash flow is minimized. To the
extent that this minimizes the impact on ACTF of significant new
spending, of which only a small amount appears as a negative to
the company, then it has a significant impact on the ACTF for
the IRR and NPV of that spending. He offered his belief that
there are other important economic metrics, including return on
capital employed, are not affected. The return on capital
employed is important to large oil and gas companies,
particularly of the sort that operate the major assets in
Alaska, that tend not to be "high growth companies" but rather
rely on the efficiency of their operations. One of the most
important measures of efficiency, from the perspective of uses
of capital, which is frequently used in judging oil companies,
is the return on capital employed. The question of implicit
government support does not impact that metric because it is
about what was spent, that is actual dollars the company spent
by the company without taking into account the after tax
benefits, and what return was gained from it.
12:13:33 PM
CO-CHAIR SEATON surmised that the effect on the competitiveness
of a project would be influenced by the structure of the
modifications to the entire fiscal regime.
MR. MAYER replied yes, but added that some economic metrics will
be more impacted than others.
12:14:17 PM
MR. MAYER, concluding with slide 28 entitled "Key Issues,"
summarized that the largest question with regard to proposed
HB 3001 is the merit of across-the-board reduction in government
take versus trying to limit a benefit from reduced government
take and possibly even greater reduced government take that is
limited to a more targeted production stream. An across-the-
board reduction in government take is the simplest approach and
avoids the potential for complexity, adverse outcomes, or
perverse incentives; however, it requires foregoing significant
revenue on activities that are currently economic. The
alternative is a more targeted approach that forgoes less
revenue on activities that are currently economic, but also has
a greater risk of creating a less significant incentive or
creating particular perverse incentives or adverse outcomes. He
noted that, although the current proposed across-the-board
reduction in government take would be about $1.2-$1.5 billion at
$110 per barrel, if the decline on the legacy fields could be
reduced from 6 percent to 2 percent by [proposed HB 3001], then
the revenue from FY 2020 onward could be higher than the current
projected scenario. Even with such a reduction in the decline
of the legacy fields, revenue until 2020 would be significantly
lower than under maintaining the current tax structure; however,
there would be a cross-over point at which the possible reduced
decline could result in increased revenue.
12:17:09 PM
MR. MAYER declared that this critical question, which is
difficult to answer without the details that only the operators
have, is with regard to how viable it is to the decline from 6
percent to 2 percent. He opined that although it is "not beyond
the scope of imagining, but also far from certainty." He
offered that the only alternative would be to differentiate
between existing and incremental production in the legacy
fields, and there are significant complexities and
administrative difficulties to doing this effectively so that
when the benefit is provided companies are able to run the
economics on their project applying the economics that come from
that benefit rather than the economics of the base production.
Mr. Mayer opined that the key issue with proposed HB 3001 is the
approach to take to reduce government take to stimulate new
investments, while keeping in mind that in the future with heavy
oil there may be even higher [production] costs and even greater
reductions in government take necessary to stimulate some
things. There comes a point at which it is clear that one does
not want to apply a regime, for example, that incentivizes heavy
oil to the light, highly economic, existing production from the
base fields. He further opined that HB 3001 does not address
other key issues that have been raised with ACES, such as oil
and gas decoupling. If there is large scale gas production,
because under ACES progressivity is assessed on a per Btu basis
based on the price of an average barrel or Btu equivalent barrel
of production, at significantly lower prices, then gas prices
vary far below oil parity. The aforementioned can reduce a
taxpayer's production tax value per barrel, and therefore
substantially reduce the amount of progressivity they pay. In
effect, there would be a cross-subsidy between gas and oil such
that the simple fact of gas production reduces the tax the
taxpayer pays on oil. This legislation does not address the
aforementioned issue nor does it address the issue of high
levels of spending support for particular activities through the
interaction of high credits with progressivity, which has
principally been the case with the 40 percent exploration credit
in the past. The legislation only addresses [the 40 percent
exploration credit] in so far as it reduces the maximum rate of
progressivity from 75 percent to 60 percent. Although that
reduction in the rate of progressivity takes "the very worst of
it out ... there's a lot that still remains." Furthermore,
taking the 40 percent credit probably contributes to that
problem further.
12:20:48 PM
CO-CHAIR FEIGE, referring to the incremental and existing oil
production, asked whether the application of a credit or a
reduction in the gross value would have more impact on a
company's decision at the point of production or some other
point. He acknowledged that there is an increasing complexity
for the various proposed points of application.
MR. MAYER stated that there are a number of issues to consider.
He explained that to some extent the gross revenue allowance
avoids the complexity of determining the costs to specific
fields and assets. He suggested that one way to target a
substantially reduced government take to a specific production
stream and then differentiate between existing production and
new production would be to draw the decline curve using past
production data, calculating the decline, and extending it
forward. He pointed out, "The more granular the level of
calculation is done at, the better the forecast one can
produce." He clarified that a decline curve using past
production data for specific wells is far more accurate than
using the data for an entire unit or an entire company. He
considered that this analysis, although complex, would only have
to be performed once. He allowed that the complexity would
arise for an investment decision today knowing that there is the
potential for substantially reduced government take above a
target rate set by a decline curve, the question is where is the
[company] in relation to the target today. If a company is
already substantially over the target with a comfortable buffer,
then any new investment made can run on the lower rates for the
production over the decline curve. However, if a company is
substantially underneath [the target of the decline curve] or
even close to it and uncertain about the performance of some of
the company's base assets, the company could think the decline
would be worse than the forecast predicts. There are many
circumstances under which a company, driven by caution, would be
more likely to run its base case economics using the government
take that applies below the line than above it.
12:27:14 PM
REPRESENTATIVE HERRON asked where Alaska would be ranked on the
bar graph on slide 7 should proposed HB 3001 pass.
MR. MAYER responded that although he would have to perform some
analysis and get back to the committee, he offered his belief
that Alaska would be ranked close to the average government take
of "US - LA (Haynesville)."
12:27:55 PM
REPRESENTATIVE HERRON, referring to slide 23, recalled that last
year there was a proposed amendment to HB 110 that would flatten
out ACES at a certain price per barrel. He asked if other
regimes do the aforementioned.
MR. MAYER replied that many financial regimes are neutral at
specified price levels, and many also have a steady downward
slope. He declared that it was easy to structure a financial
system with the cost parameters to achieve neutrality at a
specified level of government take.
12:29:46 PM
REPRESENTATIVE PETERSEN, referring to slide 28, recalled the
comments regarding the high amount of credits that would be
involved with the development of heavy oil, which should also
apply to shale oil development because of the significant amount
of drilling required to maintain production levels of shale oil.
He then asked whether Mr. Mayer was suggesting that Alaska
should propose a separate tax regime for those types of oil
developments.
MR. MAYER, drawing from his limited work reviewing the likely
cost of [heavy oil and shale oil development], offered his
belief that the development of heavy oil and shale oil would
require a level of government take lower than what is currently
proposed in HB 3001. Therefore, he surmised that one would not
want a structure that applies one level of government take to
everything because that would result in applying a low level of
government take to existing profitable production.
12:31:09 PM
CO-CHAIR SEATON held over HB 3001.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Alaska House Resources - April 23.pptx |
HRES 4/23/2012 9:00:00 AM |
HB3001 |