Legislature(2011 - 2012)SENATE FINANCE 532
03/29/2012 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB192 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 284 | TELECONFERENCED | |
| += | HB 285 | TELECONFERENCED | |
| += | SB 192 | TELECONFERENCED | |
| + | TELECONFERENCED |
SENATE BILL NO. 192
"An Act relating to the oil and gas production tax;
and providing for an effective date."
9:07:16 AM
JANAK MAYER, MANAGER, UPSTREAM AND GAS, PFC ENERGY, began
the PowerPoint presentation titled "Discussion Slides:
Alaska Senate Finance Committee." (copy on file) He
indicated that the presentation would look in particular at
the ideas of removing progressivity from the net production
tax, having the net production tax be a flat 25 percent
tax, and levying progressivity in the form of a gross tax
on oil instead; the gross tax would begin at a certain rate
and increase similarly to the progressivity under the
current measure.
Mr. Mayer discussed slide 2 titled "Difficulties in
Existing Fiscal Structure."
· The incorporation of progressivity into the Profit-
Based Production Tax (Net) in ACES creates two
significant problems
· Large-scale gas production at low gas prices
could in the future significantly reduce
production tax revenue from existing oil
production
· Resolving this problem within the framework of
ACES requires significant complexity
· Approach to decoupling in CSSB 192 requires
ability to split costs between oil and gas
production, creating high degree of
administrative burden, and limiting capacity of
state to effectively audit
· Options for incentivizing new production are
limited, and relatively complex
· Proposed incentives within existing framework
focus on either allowances to reduce Production
Tax Value, or revenue exclusions
9:10:02 AM
Mr. Mayer spoke to slide 3 titled "Summary of Progressive
Severance Tax(Gross) Option."
· A Progressive Severance Tax (Gross) option would
instead remove progressivity from the Profit-Based
Production Tax (Net), instead levying this tax at
the flat, base rate of 25%
· To retain an element of progressivity, a new
Progressive Severance Tax (Gross) would then be
added to the system. The tax would:
· Be non-deductible for Profit-Based Production Tax
purposes
· Be levied on gross production (net of royalties)
· Be levied solely on oil
· The tax would use a progressivity structure not
dissimilar to that under the current system, with
progressivity coefficients that apply at
different thresholds. The optioned modeled here
has the following parameters:
· Base rate of 0%
· Progressivity of .25% commencing at a threshold
of $65 (gross value at point of production)
· At $125 GVPP, a tax rate of 15% is reached. At
this point, progressivity is reduced to 0.05%
· Progressivity is capped 20%
Mr. Mayer noted that previously presented analyses had
shown what a new progressive severance tax would look like
if it was deductible for profit-based production tax
purposes; however, for the sake of simplicity and from the
perspective of retaining progressivity, the modeled tax was
non-deductible for profit-based production tax purposes. He
added that if the tax was deductible for the purposes of
production tax, each increment of progressivity would have
a partial offset in the form of reduced production tax and
that it would result in smaller overall progressivity than
might have otherwise existed. He pointed out that the
progressive severance tax option would be levied solely on
oil and would eliminate the decoupling issue because
instead of having a variable rate applied, the flat 25
percent tax rate would be applied. He related that if
everything was taxed at the 25 percent rate, the cost of
gas versus the cost of oil no longer mattered. He furthered
that the option eliminated the decoupling issue without
having to answer questions regarding the separate
accounting of costs for oil and gas, separate tax returns
for industry, and the abilities of the state regarding
auditing powers. He related that based on the wishes of the
committee, what was modeled was a system with revenue
similar to CSSB 192 at the $100 per barrel level, but one
that also diverged and flattened the split between
companies and the state at higher oil prices.
Mr. Mayer discussed slide 4 titled "Benefits of Progressive
Tax (Gross) Structure."
· By removing progressivity from the Profit-Based
Production Tax (Net), and having the progressive
element of the structure be a Progressive Severance
Tax (Gross), two things become much easier to achieve
· The issue of gas production reducing production
tax revenue ceases to be a problem without
progressivity in the Profit-Based Production Tax
· Complex provisions to split costs between
oil and gas production under CSSB 192 are
thus no longer required
· Significant incentives can be provided to new
production, by eliminating or reducing the
Progressive Severance Tax (Gross) for new
production
· A wide range of levels of government take can be
achieved using this structure, depending on the
parameters applied
Mr. Mayer addressed the fourth bullet and stated that the
incentives could be offered for a particular period of time
or on an indefinite basis. He furthered that under this
system, incentivizing was easier because the only
information needed was what a particular production stream
was, as well as the oil price. He reiterated that the
model's parameters were aimed to have similar revenue to
the state as CSSB 192 at a price of $100 per barrel and
have an evening of the split between companies and the
state at current price levels.
9:15:21 AM
Mr. Mayer explained slide 5 titled "FY 2013 Revenue
Comparison." He stated that the slide showed, on an FY 13
basis, the levels of production tax, total state take,
total government take, and cash to companies of the three
listed options at crude prices ranging from $40 to $150 per
barrel. He observed that at the $100 per barrel price
level, the total revenue under ACES was about $3.7 billion;
Under CSSB 192, the revenue generated at same price was
reduced to a little over $3.5 billion. He pointed out that
CSSB 192 with the progressive severance tax option had
slightly reduced revenue from CSSB 192 at a price level of
$100. He warned that it was very difficult to attain
exactly the same revenue at $100 per barrel and that there
was a significant margin of error involved with the
calculations at the macro level. He explained that, given
the high margin for error, the structure seemed to "get
quite close" to CSSB 192 at the $100 price level. He
related that at prices upwards of $100 per barrel, in
particular above the $130 level, the government take under
the progressive severance tax flattened and resulted in a
more even split; whereas, the model showed that
progressivity under ACES and CSSB 192 continued to escalate
at prices above $100 per barrel, which resulted in a higher
take for the state.
Co-Chair Stedman noted that the committee did not have time
prior to the meeting to review the charts in the
presentation. He stated that prior testimony in committee
had indicated that the current tax system functioned well
at a price of $100 per barrel, but that it became
problematic at prices north of $100. He added that the
committee was zeroing in on the $100 range due to the
current system's problems at prices over that level.
Co-Chair Stedman clarified that the government take numbers
on slide 5 included property taxes, severance taxes, income
taxes, and royalties. He inquired if the model showed that
at a price of $100 per barrel, CSSB 192 with the
progressive severance tax option was close to CSSB 192 and
was within $70 million. Mr. Mayer responded in the
affirmative.
Co-Chair Stedman noted that he had been looking at the
wrong line and corrected that under the severance tax
option, the difference in the cash position was closer to
$130 million. He observed that the progressive severance
tax option was pretty close to CSSB 192 at prices of $90
and $80 per barrel.
Co-Chair Stedman requested a clarification on slide 5 and
asked for an explanation of the $40 and $50 per barrel
price range. Mr. Mayer responded that at prices below $65
per barrel, there was no difference between the two CSSB
192 options because progressivity did not occur until
higher oil prices.
Mr. Mayer discussed slide 5 and stated that although the
two CSSB 192 options were identical to each other at the
$40 and $50 per barrel range, they were higher than ACES at
those price levels due to the 10 percent floor that was
entailed in both the CSSB 192 options.
9:20:43 AM
Co-Chair Stedman spoke to slide 5 and noted that the FY 13
revenue projections from the Revenue Sources Book
represented the homogenized numerics and that it included
companies with no production. He added that companies with
no production were absorbing around $400 million in credits
and that it had an impact on the numbers.
Co-Chair Stedman requested PFC Energy to run the tables
again using only current producers in FY 13 as inputs. He
furthered that he would like to get a feel for how the
numbers moved in the currently producing category and
inquired if Mr. Mayer had looked at that aspect yet. Mr.
Mayer responded that he would see if additional analysis in
the requested area was possible.
Co-Chair Stedman noted that there was a lot more work to be
done, but that it was his goal to keep the committee
informed throughout the process.
Co-Chair Hoffman noted that under the projections for FY 13
and at the current price of around $109 to $110 per barrel,
the revenue generated from the progressive severance option
would represent a reduction of one-third of $1 billion in
revenue to the state over ACES; however, the total cash
returned to companies at the same price was $217 million
and was substantially lower than the reduction in revenue
to the state.
Co-Chair Stedman interjected that the figures Co-Chair
Hoffman was referring to were reflective of oil prices at
$110 per barrel.
Co-Chair Hoffman reiterated that the figures represented
the current projections for revenue in FY 13.
Mr. Mayer inquired if Co-Chair Hoffman was pointing out
that the additional cash received by companies would be
lower than the reduction in take to the state. Co-Chair
Hoffman responded in the affirmative. Mr. Mayer replied
that the gap between the two numbers was a function of the
federal government take being increased.
Co-Chair Hoffman queried if the state had any control over
the increase in federal take. Mr. Mayer responded in the
negative.
Co-Chair Hoffman opined that oil futures were currently
selling for roughly $200 per barrel. He pointed out that
slide 5 did not go up to the $200 price level, but that
there was an even more substantial reduction to the state
and oil companies at that price. He observed the need to
examine where oil futures were at currently. He offered
that a common mistake made during the formulation of ACES
was that people had looked at the $40 to $70 per barrel
range; however, futures at the time were way above that
price range and the oil prices rose as expected.
Co-Chair Stedman reiterated the comments of Co-Chair
Hoffman and clarified that the figures on slide 5 would
change when the non-producing companies were excluded from
the data.
Co-Chair Hoffman stated that the committee needed to
examine what futures were selling for and what the take
would be under those scenarios. He reiterated that he
believed futures were selling for around $200 per barrel.
9:25:32 AM
Co-Chair Stedman pointed out that the numbers on slide 5
showed that at prices north of $130 per barrel, the
percentage split between the industry and the state should
remain fairly close to constant. He requested that Mr.
Mayer explain how the split worked above $130. Mr. Mayer
responded that Co-Chair Stedman was correct regarding the
government to industry take above $130 per barrel and
directed the committee's attention to slide 6.
Mr. Mayer spoke to slide 6 titled "FY 2012 Revenue
Comparison" and discussed the top left chart. He stated
that at the $100 per barrel price level there was very
little difference between the three options, that there was
a slightly increasing divergence from $110 to $130, and
that there was flattening out of government take above a
price of $125. He added that the $125 per barrel price was
the inflection point at which the decreased progressivity
of the progressive severance tax option occurred. He noted
that the purpose of the minimal .05 percent progressivity
was to offset the slightly regressive nature of the royalty
and hold government take flat from that price onward.
Co-Chair Hoffman offered that there was another way to view
the difference in the split. He stated that at prices above
$130 per barrel, the state's take under the CSSB 192
progressive severance option would continue to decline and
the industry's share would continue to rise in comparison
to ACES. Co-Chair Hoffman asserted that he agreed with this
view.
Co-Chair Stedman agreed that Co-Chair Hoffman's perspective
was another way of looking at the situation.
Co-Chair Stedman stated that currently, the percentage of
the pie would shrink to the industry, even though their
dollars increase. He furthered that currently, the state's
percentage of the pie continued to get larger. He observed
that under the CSSB 192 progressive severance option, the
percentage sharing would stay constant at prices north of
$130 per barrel; however, if you compared the progressive
option to ACES, a substantial reduction could be seen. He
commented that the $200 per barrel range could be
calculated and represented on the slide in dollar terms. He
pointed out that at a price of $200, the costs would move
because the state was under a net system. He opined that if
the price was at $200 for very long, there would be an
incremental rise in costs which would "pull that down a
bit." He pointed out that the idea was to stabilize the
sharing relationship between the industry and the state
without sending the state into a regressive environment.
Co-Chair Hoffman pointed out that one of the primary
concerns from industry was that there was no advantage for
development because it kept losing more share at the high
end. He added that industry had expressed concerns
regarding high end pricing scenarios and concluded that the
CSSB 192 progressive severance tax option addressed those
concerns.
Co-Chair Stedman requested an explanation of the four
quadrants on slide 6.
9:30:24 AM
Mr. Mayer spoke to the four charts on page 6 and stated
that the top left chart reflected revenue from the
production tax, including the severance tax. The red line
represented ACES, the yellow line reflected CSSB 192, and
the blue line represented CSSB 192 with the progressive
severance tax alternative. The bottom right chart depicted
the cash to companies for each of the three given options.
He stated that cash to companies experienced the same
divergence and evening at higher price levels as the prior
chart, but that the two CSSB 192 options returned more cash
to companies at those price levels when compared to ACES.
He observed that all three scenarios had a very similar
result at prices below $100 per barrel; however, at very
low price levels, both the CSSB 192 options resulted in
reduced cash to companies and increased take to the state
as a result of the 10 percent tax floor that was in CSSB
192. He continued to speak to slide 6 and stated that the
bottom left and the top right charts depicted what the
total state and government take would be under the given
scenarios. He added that because there were other elements
at play, the gap between the options looked significantly
smaller when you compared the total state take to the total
government take.
Co-Chair Stedman requested that PFC Energy include some of
the take numbers in percentages when it removed the non-
producing companies in its calculations. He pointed out
that the state based its numbers on the homogenized data,
which represented the entire revenue stream to the state,
while the industry ran its own numbers. He stated that the
industry and the state numbers did not match up and that
the disparity between the two was partly a function of the
approximately $400 million impact of non-producer credits.
Co-Chair Hoffman commented that if oil futures were selling
for $200 per barrel, it would be nice to have the graphs
depict that price range. He requested that PFC Energy
provide the $200 pricing scenario in future graphs and
opined that the numbers would probably reflect a difference
north of $1 billion.
Co-Chair Stedman reiterated the request of Co-Chair
Hoffman. He clarified that he had requested PFC Energy to
bring the x-axis to $150 per barrel because the lines ran
parallel at prices north of $125 to $130, but that the
graphs could be remade with the x-axis stretching to a
price of $200. He added that it might be a distraction to
look at prices such as $230 per barrel when the price was
currently at $120.
Co-Chair Hoffman commented that if futures were selling at
$200 per barrel, looking at that price should be
considered. Co-Chair Stedman voiced agreement with Co-Chair
Hoffman and reiterated that the charts would be produced
for the committee.
Mr. Mayer remarked that he could look into the question of
what the ANS West Coast and crude oil futures in general
were trading at; however, given that spot prices were
currently around the $120 per barrel mark, he would be
"very surprised" to see futures trading dramatically above
that price to the levels that had been suggested. [The
comment was in respect to the recently discussed oil
futures price of $200 per barrel.] He furthered that he
would look into the matter of oil futures and get back to
the committee.
Co-Chair Stedman directed the presentation to slide 7 and
stated that incentives for new production was another area
of challenge.
9:34:56 AM
Mr. Mayer spoke to slide 7 titled "Incentives for New
Production."
· Significant incentives can be provided to new
production, by eliminating or reducing the Progressive
Severance Tax (Gross) on any combination of:
· Production from new areas
· Production from new plans of development
(determined through the regulatory process to be
for "new production")
· Production above a fixed decline rate
· Here, a reduced rate of Progressive Severance Tax has
been modeled, using the following parameters for new
production:
· Base rate of 0%
· Progressivity of .05% commencing at a threshold
of $65 (gross value at point of production)
· Progressivity is capped 5%
· Following slides show a new, high-cost 10 mb/d
development under
· The regular rate
· The reduced rate (with a time limit of 7 years)
· The reduced rate (with no time limit)
Mr. Mayer recapped that one of the benefits of the
progressive severance option was that it overcame the
decoupling issue without addressing the complex issue of
accounting for costs; furthermore, it also created a number
of ways to provide significant incentives for new
production. He added that the progressive severance tax's
increased options for incentives were a result of not
having to look at the question of which costs came with a
particular production; under this system, only the
production numbers associated with the production stream
and the crude oil price needed to be determined.
Mr. Mayer began to speak to slide 8.
Co-Chair Stedman requested a clarification on slide 7 and
asked for an explanation of the third bullet point. Mr.
Mayer responded that the following slides were based on a
stylized, 10,000 barrel per day (bbl/d) high-cost
development that had been used in previous analysis in the
committee; furthermore, using the hypothetical development
as a benchmark, the slides examined the levels of
government take and the project economics in each of the
three scenarios.
Mr. Mayer explained slide 8 titled "Severance Tax-20%
Maximum (New Producer)." He stated that using the
hypothetical development and applying a 20 percent maximum
on the severance tax, the slide's model showed levels of
government take that were relatively steady at the 75
percent to 76 percent mark. He added that the slide showed
a little regressivity, but that the structure was more
perfectly steady when it was applied to base production or
an existing producer. He reiterated that the scenario
represented a very high-cost field and that it only broke
even at oil prices a little south of $100 per barrel. He
added that the scenario had a negative net present value
(NPV) in the $40 and $60 per barrel cases and did not
achieve a positive NPV until the $100 level; furthermore,
the $100 price level only gave the scenario an internal
rate of return (IRR) of around 11 percent. He concluded
that the scenario's development was marginal, even at an
oil price of $100 per barrel.
Co-Chair Stedman requested an explanation of the expenses
that were used in the slide. Mr. Mayer responded that the
expenses were based on capital expenditures (CAPEX) and
operating expenditures (OPEX) of about $17 per barrel. He
stated that the OPEX costs in particular were accurately
reflective of recent high-cost new developments. He shared
that the expenses were particularly indicative of the newer
producers who may have to share facilities and incorporate
implicit costs and back-out agreements. He added that the
high level of CAPEX was reflective of the significant
increases in capital costs for new developments,
particularly in areas where there was little or no existing
infrastructure. He noted that the costs associated with the
slide reflected a light oil development, but that the CAPEX
and OPEX rose significantly in some of the viscous oil
projects that had been proposed.
9:40:00 AM
Co-Chair Stedman observed that there were members of the
public who were probably unfamiliar with the charts and
requested a walkthrough of the four quadrants on slide 8.
Mr. Mayer responded that the top left portion of slide 8
depicted a basic cash flow diagram and that capital
spending was reflected in the yellow. He continued to
describe the cash flow diagram and stated that it showed
negative production in the early years, followed by
production, and then positive revenue over time with
declining production. He pointed out that the revenue curve
came from production and that it was represented in the
blue; however, as a result of inflation, the actual
production decline curve was steeper than what was
depicted. He explained that the impact of inflation partly
offset the slide's decline curve and resulted in higher
nominal cash flows in the forward years, even as production
itself declined. He shared that the red represented the
operating costs, while the black line represented the
after-tax cash flow that was produced. He added that in the
early years, the diagram showed an after-tax cash flow that
was not as strongly negative as the yellow of the CAPEX and
that the disparity between the two was a result of the
impact of the 20 percent capital credit.
Mr. Mayer discussed the blue table next to the cash flow
diagram and stated that it depicted the basic economic
metrics of the NPV and IRR for the stylized project at
prices of $40, $60, and $100 per barrel.
Mr. Mayer spoke to the table on the upper right portion of
slide 8 and stated that it depicted the total levels of
government and state takes at each of the prices ranges. He
shared that different elements, such as royalty, severance
tax, or production tax were examined as a portion of
divisible income and that they were summed horizontally on
the chart to equal the total state or government take.
Mr. Mayer discussed the two bottom charts on slide 8 and
stated that they depicted the particular development's
total state and government take figures in dollar terms and
in percentages.
Mr. Mayer addressed slide 9 titled "Severance Tax-20%
Maximum with first seven years at a 5% maximum (New
Producer)" and stated that the slide showed the same
discounted rate as the previous slide, but with a maximum
rate of 5 percent for the first seven years; the maximum
rate would then revert to the 20 percent after the seven-
year period. He remarked that if you compared this scenario
to the previous slide, the economics of the two options
were identical in the $40 and $60 per barrel cases because
the progressive severance tax did not apply below that
price range; however, at higher price levels, the NPV of
the project rose from $29 million to $77 million, which
resulted in an increase to the IRR from 11 percent to 12
percent. He concluded that slide 9 showed a further
reduction in government take from the previous slide,
particularly at the higher price levels, and that the
government take levels peaked at around 73 percent,
regressing only slightly from that point onward.
Co-Chair Hoffman inquired if the having the maximum rate at
5 percent for the first seven years could be considered a
tax holiday. Mr. Mayer responded that it was a tax
reduction, but that it was not a tax holiday entirely
because every barrel was still taxed, only at a lower rate.
Mr. Mayer spoke to slide 10 titled "Severance Tax-5%
Maximum (New Producer)." He stated that the slide
illustrated the same scenario as the previous slide, but
had the maximum rate stay at 5 percent indefinitely. For
the first seven years, the cash flows of the scenarios on
slides 9 and 10 were identical; however, after that period,
the cash flow from slide 10 increased significantly due to
the 5 percent maximum being applied across the board. He
noted that the NPV from slide 10's scenario had increased
to $119 million when compared to slide 9's NPV of $77
million. He concluded that the increase in slide 10's NPV
represented a gain of 1 percentage point to the IRR of the
stylized project. Slide 10's scenario had a flattening of
government take from the $70 per barrel price range and
upwards. He concluded that the scenario had a government
take figure of about 65 percent if you looked at the
lifecycle of the project as a whole.
9:45:09 AM
Mr. Mayer explained slide 11 titled "20-year Revenue Impact
of Reduced Rate for New Production" and stated that it
examined the potential impact, over a 20-year period, of
offering the discussed benefits for new production. He
reiterated that there were a variety of ways to identify
new production and offered that the simplest way was to
provide incentives for production from new areas, such as
the incentives for new oil under HB 110. He warned that the
problem with only defining new production on the basis of
being from a new area was that most of the new production
was expected to come from within existing areas. He
furthered that the second option for incentivizing new
production would be to apply the benefits through the
regulatory process, such as providing authority to the
"executive" to approve that particular new plans of
development provided new production; if the determination
was made that the development plans provided new
production, the lower rate of taxation could be applied to
those projects. He added that with the first two options
for defining new production, it was easy to apply a time
limit to the reduced rate because there was clear initial
start of production. He related that the third option
available for incentivizing new production, particularly
for existing producers, was to incentivize production above
a set decline level. He mentioned the current 6 percent
base rate of decline and stated that the decline at a given
time could be determined and the curve of the decline could
be projected forward. In this third option, any production
above that determined curve of decline would have the
preferential rate of taxation applied to it. He observed
that with the third option, it would not be possible to
apply a time limit because there was not a particular
stream of production and starting date from which to set a
stopping point. He added that if a time limit was applied
to the first two options and the goal was to equalize the
impact of the benefit for new production, a different
gradient might be applied to new production above the 6
percent base rate "so that over time, the benefit of those
two options were more equal. If one doesn't apply a time
limit at all, then one doesn't need to differentiate on
that basis."
Mr. Mayer drew the committee's attention back to slide 11
and stated that the purpose of the slide was to determine
an initial figure that would result from the 20-year impact
of a policy for new production. He observed that the 2013
impact would be next to nothing because there would be very
little production that would count as new during that year.
He shared that the slide examined the increasing impact of
the policy over time and that it used the Department of
Revenue's (DOR) 20-year production figures, as well as the
department's cost forecasts. He added that the 20-year
production figures extended to 2032 and that the cost
figures ran to approximately 2021.
9:49:04 AM
Co-Chair Stedman interjected that the committee had not yet
seen cost figures from DOR extending to 2021, but that it
had seen figures that went through 2016. He observed that
the cost figures extended farther out than the committee
had been aware of and requested that the document be
produced for committee members.
Mr. Mayer continued to address slide 11. He stated that
using DOR's production profile and cost estimates enabled
the modeling of the cash flows under a range of scenarios.
In order to get a rough estimate based on DOR's forecast,
which included projects in development and anticipated new
development, the slide used the 6 percent decline curve and
applied the differential between old and new production
over the course of 20 years. He furthered that the slide
examined the difference in the NPV of the cash flows if the
20 percent maximum rate was applied to all production
versus applying the 5 percent maximum rate indefinitely to
all production above the 6 percent decline. He pointed out
that there was approximately a $10 billion difference in
the NPV of the cash flows for the production tax over that
20-year period at the $100 per barrel price level. He added
that when production above a 6 percent decline was taxed at
the lower rate, the slide's NPVs of the 20-year cash flows
dropped from about $40 billion to $30 billion. He related
that his intention with the analysis was not to suggest
that the figures would represent how policy would work in
practice because significant parts of the production were
new projects, while relatively little would come from
increased production in existing fields. He furthered that
the analysis did not suggest that the 6 percent decline
curve would be applied the way it depicted, but that it
showed how big, in theory, the potential difference could
be if the preferential rate was applied.
9:52:03 AM
Co-Chair Stedman recalled that one of his concerns during
previous discussions with Mr. Mayer had been that when the
committee conceptualized a process or adjustment for
incremental production, the state was not put into a
position where "several years out, we have walked down some
curve and we have no revenue." He expressed the need for
caution regarding how to transition into new production in
a manner that treated state and industry fairly.
Mr. Mayer spoke to slide 12 titled "Regime Competiveness:
Relative Government Take (Existing Production)." He stated
that the slide benchmarked competiveness against a range
other regimes, particularly the Organisation for the
Economic Co-operation and Development (OECD) countries,
which were represented by the yellow bars. He related that
at a price of $100 per barrel, the ACES existing producer
scenario was a little under Norway, who was the highest
taxing OECD producer; however, if the price was increased
to $140, ACES for an existing producer would be
significantly above Norway. He shared that CSSB 192
represented only a slight reduction in government take in
comparison to ACES and that it was a difference of only
about 1 percentage point. He stated that under the
severance tax option for CSSB 192, the scenario's
government take dropped from 73 percent or 74 percent down
to about 70 percent.
Mr. Mayer explained slide 13 titled "Regime
Competitiveness: Relative government take (New
Development)" and stated that the slide examined the same
competiveness but in the case of a new development. He
reiterated that under ACES, the levels of government take
were frequently higher for new developments than they were
for existing production, partly due to the development's
higher cost structure, but also because without an existing
base production portfolio there was not as much benefit
from writing down existing expenditures on current
production. He pointed out that both the CSSB 192 and ACES
scenarios for new developments were above Norway on the
slide. He stated that the severance tax option with the 5
percent maximum for seven years took the government take
down significantly, but that it was still around some of
the higher taxing jurisdictions; however, if the 5 percent
maximum was applied indefinitely, the levels of government
take became quite competitive with some of the higher-cost
developments, such as the unconventional developments in
Louisiana and Texas.
9:56:10 AM
Co-Chair Stedman inquired why Alaska would want to be below
developments in Louisiana and Texas in terms of government
take. Mr. Mayer pointed out that the chart made a
distinction that the Louisiana and Texas plays were
different from conventional developments and added that the
reason that there was a difference in government take
"between the two" was because that, relatively speaking,
costs were higher for unconventional developments than they
were for regular onshore drilling. He stated that higher
costs led to a higher government take; however, the costs
from plays like Louisiana and Texas remained below the
costs on the North Slope. He stated that although
government take was one part of the metric, the associated
costs were another factor that determined if something was
economic or not. He concluded that a jurisdiction being
competitive on government take did not necessarily make it
an attractive destination for investment.
Co-Chair Stedman inquired if the variable severance tax
option with the 5 percent maximum for seven years could be
tweaked by either stretching the seven-year time period or
by changing the maximum rate in order to enable the state
to adjust as needed in the range between the two severance
tax options on slide 13. Mr. Mayer responded in the
affirmative and that by changing the seven-year period to a
greater timeframe, the bars could be adjusted within the
specified range.
Co-Chair Stedman further inquired if this method of
adjustment could potentially be used to target different
hydrocarbons. Mr. Mayer responded in the affirmative and
added that one benefit of taking progressivity out of the
production tax was that question of costs was no longer
important; the only information needed for calculations
under this system was to know the production volumes
associated with a given production stream and the price of
oil. He added that for a particularly challenged
hydrocarbon type, such as heavy oil where a greater
incentive might be required, one alternative was to reduce
the production tax on all production and then make up the
difference for existing production by further raising the
progressive severance tax; this would enable the overall
take for existing production to remain close to the same,
while still enabling additional incentives for particularly
challenged development.
Senator McGuire inquired if the regime competiveness slides
could be remade to include oil prices at $140, $150, and
$160 per barrel. Mr. Mayer responded that he would do so.
Co-Chair Stedman offered that it might be easier if the
regime competiveness slides were remade in $20 increments,
such as $80, $100, $120, $140, and $160 per barrel.
Senator McGuire observed that Co-Chair Hoffman had
requested that the slides display up to a price of $200 per
barrel. Co-Chair Stedman responded that $200 per barrel
could also be displayed.
10:00:24 AM
Senator Thomas wondered, given the large number of
variables, how regime competiveness was calculated. He
inquired how much investment was actually taking place in
the top four countries on slides 12 and 13. He stated that
the top four countries were not places that he would do
business in and observed that there several other countries
above Alaska on the slide that also fit that profile. He
pointed out that the slide depicted Alaska below Venezuela,
which had nationalized its oil fields and opined that there
were a variety of countries that might be undesirable for
oil companies to do business with. He furthered that there
were jurisdictions within the U.S. that Alaska would
probably never be "directly" competitive with, based on the
cost of doing business in those areas versus the costs on
the North Slope of Alaska. He concluded that he was
struggling with the concept of how a determination was made
regarding what was competitive, other than using strict
dollar terms.
Co-Chair Stedman added that Ireland and Greenland had very
low government take on the regime competiveness slides,
even though the two countries essentially had no oil. He
furthered that the numbers could look attractive in these
two areas, but that prospectivity was pretty low.
Mr. Mayer agreed that the points made by Co-Chair Stedman
and Senator Thomas were valid. He concurred that at the
higher level of the scale, there were a number of countries
that may be significantly less attractive destinations for
investment; however, government take was only one variable
regarding a destination's competiveness and desirability
for investment. He related although some jurisdictions may
have greater political risks or a higher government take,
they might have resources that could be developed at
minimal cost; therefore, in certain circumstances, projects
remained attractive despite high levels of government take.
He stated that Ireland and New Zealand had a very
attractive fiscal regime, but that they did not have
significant resources. He pointed out that Alaska did have
a higher government take than regimes in the Lower 48;
however, the costs in Alaska were also much higher,
particularly for conventional onshore production. He shared
that in Alaska, the competiveness difference was
compounding because there was a higher government take and
higher associated costs. He concluded that all of the
aspects needed to be considered regarding a regime's
competiveness, but that the slides examined government take
because the committee had been relatively focused on that
metric. He added that the slides excluded other factors and
compared Alaska to other jurisdictions on the basis of
government take.
10:04:10 AM
Senator Thomas asserted that the production level "per
well" was another important aspect to consider and inquired
if Mr. Mayer agreed. Mr. Mayer responded in the
affirmative.
10:04:23 AM
AT EASE
10:05:37 AM
RECONVENED
10:05:41 AM
Co-Chair Hoffman pointed out that there was an article in
that morning's newspaper that quoted the governor regarding
his comments on commitments from industry. He related that
the article had quoted the governor as saying that he would
veto legislation if it did not include commitments from
industry. He stated that he did not recall any commitments
from industry in HB 110, and inquired if Co-Chair Stedman
had received any communications from the governor regarding
that topic or any proposed ideas of commitments.
Co-Chair Stedman replied that he had not been contacted by
the governor's office regarding industry commitments and
stated that he was only aware of what he had read in the
newspaper regarding that issue. He recalled that EXXON
Mobile had testified that the state would need additional
production every year matching the Oooguruk and Nikaitchug
fields in order to flatten out the oil decline. He
continued that Alaska's oil decline was $3 billion to $5
billion a year, and was not $5 billion over an eight or
ten-year period. He related that the scale and magnitude
that was discussed in the press and the magnitude of what
was needed to flatten out the oil decline were not
comparable. He opined that if additional production in the
magnitude of Oooguruk and Nikaitchug was needed, the
expectation of advancing production to 600,000 bbl/d on
state lands was problematic; however, he was open to ideas
of how to achieve that goal.
Co-Chair Stedman noted that Iraq did not appear on any of
the slides and inquired if Mr. Mayer had any comments on
where Iraq would be on the list. He noted that Iraq had a
service contract regime where companies were paid per
barrel. Mr. Mayer responded that Iraq had a relatively high
government take and that it was mostly due to the service
contract fiscal structure for new developments involving
international oil companies. He furthered that in Iraq's
service contract system, a number of points were negotiated
as part of the awarding of the contract and that
international oil companies were paid for oil produced
above existing levels of production. A country using the
service contract system would have a set level of
production that it was unable to go above; the country
would then pay a company for the barrels that it could
produce above that existing production plateau, but paid
"very little" for anything below that level.
Senator McGuire thanked Mr. Mayer for his hard on work on
SB 192.
SB 192 was HEARD and HELD in committee for further
consideration.
Co-Chair Stedman discussed the following meeting's agenda.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 192 PFC Presentation Alaska Senate Finance - March 29.pdf |
SFIN 3/29/2012 9:00:00 AM |
SB 192 |