Legislature(2013 - 2014)SENATE FINANCE 532
03/14/2013 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB38 | |
| SB62 | |
| SB21 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | SB 62 | TELECONFERENCED | |
| + | SB 38 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| = | SB 21 | ||
SENATE BILL NO. 21
"An Act relating to appropriations from taxes paid
under the Alaska Net Income Tax Act; relating to the
oil and gas production tax rate; relating to gas used
in the state; relating to monthly installment payments
of the oil and gas production tax; relating to oil and
gas production tax credits for certain losses and
expenditures; relating to oil and gas production tax
credit certificates; relating to nontransferable tax
credits based on production; relating to the oil and
gas tax credit fund; relating to annual statements by
producers and explorers; relating to the determination
of annual oil and gas production tax values including
adjustments based on a percentage of gross value at
the point of production from certain leases or
properties; making conforming amendments; and
providing for an effective date."
3:18:31 PM
Co-Chair Kelly MOVED to ADOPT the proposed committee
substitute for SB 21, Work Draft 28-GS1647\Y (Bullock,
3/13/13).
Senator Hoffman OBJECTED for the purpose discussion.
SUZANNE ARMSTRONG, STAFF, SENATOR KEVIN MEYER, referred to
"Proposed Changes in Senate Finance CS SB 21 Version 28-
GS1647\Y" (copy on file).
Maximum Base Tax Rate:
Established in Section 9 (page 4, lines 30-31 and page
5, lines 1-11)
January 1, 2014 - December 31, 2016: 35 percent
Effective January 1, 2017: 33 percent
Repeals Progressivity:
No Change from Senate Resource Version
No Change from Governor's Version
Per Bbl Allowance: $5.00/bbl
Established in Section 23
Gross Revenue Exclusion:
Established in Section 30 (part of Section 12 as
Payment of Tax)
· Produced from a lease or property not within a
unit on January 1, 2003: 20 percent
In Senate Resources Version at 30 percent
In Governor's Version at 20 percent
· Produced from a participating area established
after December 31, 2011: 20 percent
In Senate Resources Version at 30 percent
In Governor's Version at 20 percent
· Produced from a well that has been accurately
metered and measured by an operator and that DNR
has certified was not contributing to production
before January 1, 2013 (certified through
required POD): 20 percent
Net Operating Loss, Monetizable:
Section 16, Section 17, Section 19
Monetizable or carry forward annual loss credit
(in the amount equivalent to production tax
rate):
January 1, 2014 - December 31, 2016: 35 percent
January 1, 2017: 33 percent
Manufacturing Credit against State Corporate Income
Tax:
Established in Section 7
Provides for a manufacturing credit applied
against a taxpayer's corporate income tax
liability for a qualified oil and gas service
industry expenditure that occurs in the state.
· The total amount of credit may not exceed the
lesser of 10 percent of expenditures or $10
million.
· Must be a taxpayer to qualify for the credit.
· Non-transferable
· The expenditure cannot be the basis of another
deduction under the Corporate Income Tax Law
· Reduces the shelf life of the credit to five
years
Eliminates Qualified Capital Expenditure Credit: For
Expenditures after 1/1/2014
Exploration Incentive Credit:
Not extended to 2022
Will sunset July 1, 2016
Small Producer Tax Credits:
Not extended to 2022
Will sunset 2016
*Small producers that currently receive the
credit. If production started after April 1,
2006, then the small producer is allowed to take
the credit for 9 years after the start of
commercial production. Very likely that even
though the credit sunsets in 2016, there will be
companies that are allowed to take the credit in
years after 2016.
Interest Rate for Delinquent Taxes:
Amended under Section 4
Adjusts how the interest is calculated on
delinquent taxes: 3 percentage points above the
annual rate charged member banks for advances by
the 12th Federal Reserve District. Alternative to
the greater than approach (current statute) or
the lesser than approach (in Version 28-GS1647\P)
Slide by Barry Pulliam of Econ One - 3/12/2013
Conforming Sections: 1, 3, 5, 6, 8, 14, 20, 31,
32, 33
Community Revenue Sharing Provision:
Removes reference and tie to corporate income tax
receipts. Does not change how the formula works,
or distribution of funds.
3:24:47 PM
Co-Chair Meyer requested an explanation of the fiscal note.
MICHAEL PAWLOWSKI, ADVISOR, PETROLEUM FISCAL SYSTEMS,
DEPARTMENT OF REVENUE, spoke to the fiscal note dated
3/14/13 at 12:10 PM. He related that while he had
participated in the development of the fiscal note from a
review standpoint, he had not developed the numbers
himself; however, he could walk committee members through
the components in the fiscal note in relation to the CS. He
looked at page 1 of the fiscal note. He pointed to the
inclusion of a $100,000 line item in the services section
for 2014 that was for the revision in the interest rate
that was in the CS and stated that although the Department
of Revenue (DOR) was moving towards the adoption of the tax
revenue management system, there was still work that needed
to be done on the existing tax systems to reflect the
change in the interest rate and the way it was levied with
the tax system; the $100,000 was the cost of the department
to implement the change in the interest rate.
Mr. Pawlowski spoke to page 4 of the fiscal note, which was
the table that itemized the 10 different pieces in the
legislation that had a fiscal impact. He noted that the
fiscal impact in the note did not include potential revenue
impacts from potential increases in productions; the fiscal
note was based entirely on the revenue forecast and the
forecasted price of oil across the time period in the table
on page 4. He pointed to FY15 on the second column and
related that it was the first full fiscal year of the
impact of the bill as the effective dates were designed in
the CS; line 1 showed the revenue impact of eliminating the
progressive portion of the tax, which was $1.5 billion in
FY15. He furthered that line 2 showed that the increase of
the bas tax rate from 25 percent to 35 percent would raise
an additional $1.075 billion and would essentially generate
$425 million less than what was being collected under
progressivity.
Mr. Pawlowski continued to speak to page 4 of the fiscal
note. He discussed line 4, which depicted a further revenue
increase to the state with the limitation of credits
qualified capital expenditures (QCE) for the North Slope;
this line represented the credits that were claimed against
a tax liability and was projected to result in additional
revenues to the state of $700 million in FY14. He spoke to
the net operating loss credit increase to 35 percent for
calendar years 2014 through 2016 and 33 percent for 2017
that was on line 4; these increases were refundable and
were dealt with below in the operating budget component. He
relayed that the gross revenue exclusion (GRE) on line 5
was provided as range, which was reflective of the fact
that in order to qualify for the GRE in the CS, there were
some portions that the Department of Natural Resources
(DNR) needed to certify to DOR; there was a burden of proof
by the industry and work that was conducted by DNR. He
pointed out that the team at DOR had identified the
possible potential range of projects that might, in
"perhaps the worst case scenario," qualify for a GRE based
on DNR's certification; in that year, it ranged from a low
side of $25 million to a high side of $175 million.
Mr. Pawlowski continued to address page 4 of the fiscal
note. He pointed to line 6 and the provision requiring that
credits that were taken over 2 years be eliminated. He
explained that the credits were reflected in FY14, but
because the North Slope capital credits were not continued,
the issue did not add to the revenue impact in the note
after that fiscal year; these credits were based on
expenditures in FY13 that would be taken over 2 years under
the existing Alaska's Clear and Equitable Share (ACES)
system. He pointed to line 7 and related that the minus
$250 million in FY14 was bringing an impact that would have
been spread into FY15 in order to close out the state's
obligation based on the expenditures. He related that the
next substantive change in the fiscal note was on line 8,
which reflected the $5 per taxable barrel (bbl) allowance;
this would be a reduction in state revenue of $825 million
in FY14. He stated that the credit under AS 43.20 for
qualified oil and gas industry expenditures was
indeterminate, but the more stringent language that Senate
Finance Committee had adopted limited the potential range
of companies that could qualify in expenditures; this
effect dropped to $25 million and the credits were no
longer transferable, but accrued directly to tax paying
entity. He discussed line 10 and the reduction in the
interest rate from federal funds rate plus 5 percent, or 11
percent, to the federal funds rate plus 3 percent; the
effect of this was indeterminate, but was projected to be a
$25 million reduction that would possibly rise over time as
delinquent taxes or true-ups carried a bigger interest rate
over a time period.
Mr. Pawlowski continued to discuss page 4 of the fiscal
note and stated that the total revenue impact in FY15
ranged from $575 million to $775 million. He pointed out
that the range of the revenue impact reflected a
combination of the impact of the GRE being applied to
potential projects that were not currently contributing to
production within existing units, the qualified oil and gas
industry expenditures, as well as the interest rate
provision; this was offset to a degree by the reduction in
the next section and was an impact in the operating budget.
He expounded that because qualified capital expenditure
credits would no longer be offered on the North Slope under
the current version of the bill, DOR projected that about
$150 million less would need to be appropriated to the tax
credit fund for the reimbursement of those credits;
additionally, the subsequent reduction was an impact of the
increase in the net operating loss credit rate to 35
percent and then 33 percent. He reported that the increase
in the net operating loss credit rate was projected to add
an additional $40 million to the operating budget and that
the net operating impact was actually $110 million; DOR had
wanted to reflect that increasing the rate for the net
operating loss credit did have a cost. He discussed the
bottom of page 4, which depicted a total fiscal impact of
$465 million to $665 million in FY15.
3:33:52 PM
Co-Chair Meyer noted that the fiscal note reflected an
increase in the 3rd year out, which was partially due to
the reduction in "base rate from 35 percent to 33 percent;
on the other hand, the fiscal note did not include any new
oil. Mr. Pawlowski confirmed that the note did not include
possible new oil. He stated that the "bump" in FY14 of "775
to 875" was really the addition of line 6 on page 4, as
well as the $150 million in the operating budget, which
combined represented an additional $400 million impact to
close out the outstanding qualified capital expenditure
credits that were accrued based on expenditures before the
effective date of the act. He stated that Co-Chair Meyer
was correct that the note's increases in the out years
reflected additional potential GRE eligible production
along with the decrease in the base rate.
Mr. Pawlowski directed the committee's attention to page 5
of the fiscal note and related that it was the standard
scenario sheet that used to walkthrough the fiscal
presentation that was given on the previous CS; he offered
that members would recognize the same scenarios, but that
based on the request of the committee, DOR had made a few
modifications. He stated that the "At Forecasted
Production" was depicted at different prices and that at
$90 per bbl, the state would see roughly $75 million in
additional revenue under the prosed CS over ACES in FY14;
this number rose to $325 million at $90 per bbl, but in
FY15 at $120 per bbl, that the CS would represent $925
million less revenue than ACES; these revenue impacts did
not include other impacts of the bill, such as the removal
of the credit split, the impact of the elimination of
qualified capital expenditure credits, or the net operating
loss credits.
Mr. Pawlowski continued to address page 5 of the fiscal
note and pointed to scenario B. He stated that the scenario
represented 4 rigs being added within the legacy units,
which were each drilling 4 wells that each produced 1,000
bbl at the begging of production with a decline of 15
percent. He explained that perhaps 50 percent of the
incremental production might not be contributing to
production, so the table for scenario B assumed that half
of the oil qualified for the GRE; however, if oil did not
qualify for the GRE, "this" number would be higher and
"lower at the higher prices."
Mr. Pawlowski discussed scenario C on page 5 of the fiscal
note and stated that it kept the same GRE application for
the 4 rigs, but also applied the GRE to the large new
development; the scenario assumed and showed the fiscal
impact of a large new development in a legacy field that
received the GRE. He stated that the scenario showed that
even at a price of $120 per bbl of oil, the revenues to the
state would surpass what would have been collected under
ACES by 2018 if ACES continued at the forecasted
production.
3:37:32 PM
Co-Chair Meyer remarked that 2018, or maybe slightly before
that, was the breakeven point and inquired how many bbl of
oil scenario C assumed. Mr. Pawlowski was unsure how many
bbl it would be in that year and explained that the
scenarios did not assume a set number of bbl, but instead
built decline curves to mimic actual production within a
field. He further explained that rigs would be drilling a
well that declined at 15 percent a year and that the
scenario C was more reflective of a realistic scenario. He
added that the scenarios were modeled based on activity and
production curves, but that he could provide the committee
with that information. He stated that the reason the tables
on page 5 were provided over a range of oil prices was to
show the sensitivity of revenues to price. He pointed out
that scenario B at the $100 per bbl price from FY15 through
FY19 showed increases and related the scenario showed
revenue increases of $225 million in FY15 at that price. He
concluded that determining the state revenues was a
function of the price of oil, the production, and the
spending.
Senator Hoffman looked at page 5 of the fiscal note and
concentrating on 2017 through 2019 because it was the
period that would show the long-term implications of the
maximum base tax rate. He pointed out that the price was
currently at $110 per bbl, but wondered if DOR had an idea
of what the price would be in 2019; furthermore, the range
between "425 and 1.3" was a wide range and the prices
depicted went from $100 per bbl to $120 per bbl. He
wondered what "those" impacts would be at the current price
of about $110 per bbl. Mr. Pawlowski responded that he did
not know offhand what the $110 per bbl number would be, but
that he could have the number run for the committee; the
reason that the $120 per bbl number was chosen was because
the range in the forecast period rose in that time period
in FY19 to about $118.29 per bbl.
3:40:44 PM
Senator Hoffman stressed that the information about the
impacts at current prices was very critical to the
committee and that it would not be doing its due-diligence
unless it saw those numbers from the department.
Senator Hoffman addressed scenario A on page 5 of the
fiscal note and directed the committee's attention to FY19,
which was when the base rate would be at 33 percent; he
inquired what DOR thought the state would be pushing across
the table in scenario A if it assumed the forecasted
production of a 50 million bbl field at a price of $110 per
bbl if only one 50 million bbl field was developed. Mr.
Pawlowski responded that he would have to run the $110 per
bbl number.
Senator Hoffman observed that the same question applied to
scenario B and C in order to help the committee do its due-
diligence before the legislation was moved on.
Senator Hoffman directed the committee's attention to page
4 of the fiscal note and FY17 through FY19; he noted that
that the maximum base tax kicked in at 33 percent in
January 1, 2017. He pointed to the bottom lines of the FY
17, FY18, and FY19 columns and observed that at the high
end, there was about $1.25 billion being pushed across the
table in FY17; this number increased in FY18 and FY19 to
$1.3 billion. He acknowledged that intent of stemming the
decline and offered that he was willing to take risks;
however, more information, particularly regarding "these
other numbers," would be required because the stakes were
tremendous at the high end. He expressed desire to see more
oil, but warned that the risks needed to be assessed
because the numbers were staggering. He requested that the
numbers be depicted at a price of $110 per bbl of oil and
opined that the numbers looked good when you only
considered prices of $90 per bbl and $100 per bbl. He
offered that the price of oil had continued to rise for the
last 6 years.
Co-Chair Meyer thought that it would be easy to find the
point in between $100 per bbl and $120 per bbl and asked
the department to provide the requested information. Mr.
Pawlowski responded that he would do so. He directed the
committee's attention to the fiscal line on the bottom page
4 of the fiscal note, which stated that the forecasted
price ranged from $109.61 per bbl in FY14 to $118.29 in
FY19 and explained that the generated number would look
very similar to the trend that was in the fiscal note.
3:45:39 PM
Senator Hoffman offered that at a price $110 per bbl, the
impacts in FY18 and FY19 would probably be north of $1
billion. Mr. Pawlowski responded that this would be true
for the forecasted production table in scenario A on page 5
of the fiscal note, but that DOR would generate the number
for scenarios B and C where additional production would
come into play. He added that it was a fair question and
that DOR would generate the numbers.
3:46:35 PM
AT EASE
3:46:56 PM
RECONVENED
3:47:00 PM
Senator Hoffman wondered if the numbers for when the GRE
kicked in after 2019 could be run by DOR because he thought
they would be significant. He acknowledged that normally a
5-year outlook was presented, but offered that the GRE
could very substantially; furthermore, the number that
included the effect of GRE needed to be considered, but was
not included in the charts before the committee. He
observed that the fiscal note had indeterminate amounts all
the way across and that it would be nice to have the
additional information when considering a piece of
legislation so large.
Co-Chair Meyer acknowledged that fiscal notes typically
looked 5 years out and thought that it would be pretty
speculative to ask DOR to forecast the note much farther
out. He asked Mr. Pawlowski if Senator Hoffman's request
was doable. Mr. Pawlowski stated that he would confer with
some of people at DOR who generated those numbers in the
long-term forecast and see what the range of
"comfortabilities" was in providing those numbers. He
recalled an answer that was generated by DOR for Vice-Chair
Fairclough that had a breakdown of the under development,
under evaluation, and currently producing bbl looking
forward that would or could potentially qualify for the
GRE; furthermore, the way the Senate Finance Committee's CS
was drafted, there was a burden of proof within the legacy
units to come to DNR to demonstrate through geological and
geoscience means that "that" oil was not contributing to
production in order to qualify for the GRE. He expressed
that DOR wanted to careful not to assume that too much or
not enough applied to the GRE, but that it was trying to
over-assume what would apply for the GRE in order to be
clear with the committee and public and put serious fiscal
impacts on table for the committee to consider. He
concluded that he would look at the request and get back to
the committee with a response.
3:50:34 PM
Co-Chair Meyer expressed frustration. He stated that the
committee had been working on the bill during mornings and
afternoons for 2 weeks and that DOR could have prepared the
analysis past 5 years out if it had known that it was
desired.
Senator Hoffman WITHDREW his OBJECTION.
There being NO further OBJECTION, the CS was ADOPTED as a
working document.
3:51:58 PM
RECECESSED
6:16:22 PM
RECONVENED
Co-Chair Meyer observed that Senators Stedman, Giessel, and
Wielechowski were present in the committee room.
6:18:02 PM
SCOTT JEPSEN, VICE PRESIDENT OF EXTERNAL AFFAIRS,
CONOCOPHILLIPS (via teleconference), addressed possible
confusion regarding a presentation that ConocoPhillips had
conducted on February 28 and offered that there might be a
misinterpretation that the comments about the future
development activities that were mentioned in the
presentation referenced a new initiative; however, the
referenced activities were not incremental and were a
continuation of what the company had already been doing.
Furthermore, the presentation's activities did not
represent a new initiative and was not something above and
beyond what ConocoPhillips had been previously doing. He
referred to a graph on slide 2 of a PowerPoint presentation
titled "Senate Finance Committee CSSB21" (copy on file);
the graph demonstrated that investment followed upside. He
pointed out that Alaska had resources, but that it was
hampered by the ACES tax regime; furthermore, the high
progressivity in ACES was a tremendous impediment to
increasing investment in Alaska. He offered that the graph
showed that ConocoPhillips had a constant budget of $900
million per year the last 3 years in Alaska and compared
this to Lower-48, which had high upside; ConocoPhillips'
investment in the Lower-48 had grown from about $1.5
billion to close to $5 billion during the same 3-year
period. He reminded the committee that these investments in
the Lower-48 were in oil plays and not in natural gas
plays; furthermore, ConocoPhillips was focusing its
attention on oil plays like the Bakken and Eagle Ford.
6:22:44 PM
BOB HEINRICH, VICE PRESIDENT OF FINANCE, CONOCOPHILLIPS
(via teleconference), spoke in support of CSSB 21(FIN), but
indicated that his company still had several areas of
concern regarding the bill. He discussed slide 3 titled
"Changes to ACES to Improve Alaska's Investment Climate."
He related that ConocoPhillips had been advocating for the
elimination of progressivity from the tax system, as well
as the creation of a flatter tax rate over a broad range of
prices; the third thing the company was advocating for was
establishing a tax structure that created an attractive
investment climate for Alaska. He discussed the need for a
competitive tax rate and potential incentives for both
legacy and new field development that would help balance
Alaska's high-cost environment. He related that although
ConocoPhillips' analysis of CSSB 21(FIN) was in its early
stages, the progressivity and flatter tax rate concerns had
been addressed well in the bill; however, there were still
several areas of concern. He opined that CSSB 21(FIN) still
represented a tax increase at lower prices, which was a
result of the higher base tax rate; furthermore, the second
issue surrounded the mechanics of how the new GRE language
would apply within the legacy fields. He recalled comments
that ConocoPhillips' CEO had made the previous week, in
which he had stated that ConocoPhillips would do more in
Alaska with the right tax framework. He concluded that
ConocoPhillips was doing what it could in Alaska under the
existing structure, but saw that it could do more if the
appropriate changes were made.
Co-Chair Meyer inquired if the bill had reached the point
where it would create a climate that would spur additional
investment and hopefully more production in Alaska. Mr.
Heinrich replied that although CSSB 21(FIN) was an
improvement over ACES that ConocoPhillips was pleased to
see, the company would have to examine projects on a
project-by-project basis; furthermore, because of the
current structure of the legislation, ConocoPhillips could
not say that the opportunity slate would improve across the
board. He explained that some projects would be improved as
a result of the bill, while others may not improve because
of the loss of the tax credit structure.
6:26:10 PM
Co-Chair Meyer recalled a graph that had depicted the
breakeven point to be 70,000 bbls per day (bbl/d) and
offered that another graph would show that figure to be
closer to 55,000 to 60,000 bbl/d. He noted that the state
would be looking at where it would find the additional new
bbl of oil and hoped that the industry would provide some
encouragement that the changes in CSSB 21(FIN) would result
in 55,000, 60,000, or more bbl/d. Mr. Jepsen responded that
ConocoPhillips was not at the point where it could tell the
committee how much it would do differently if CSSB 21(FIN)
was passed; additionally, CSSB 21(FIN) was a step backward
from the previous version of the bill. He acknowledged that
CSSB 21(FIN) was an improvement over ACES, but that
ConocoPhillips could not currently state which projects
would happen and which ones would not; whether projects
went forward would depend on whether the investment climate
in Alaska was sufficient to attract significant new
investment dollars. He concluded that some elements of CSSB
21(FIN) would take more analysis to determine their impacts
on investment decisions and spoke about the need to further
examine the way the GRE was described in the bill.
Senator Hoffman asked how long it would take ConocoPhillips
to determine whether the bill would spur it to invest in
Alaska, as well as what the size of the investment might
be. Mr. Jepsen replied that the company would make those
decisions as projects matured to a funding decision. He
recalled that ConocoPhillips had stated that there were
certain things it could do if HB 110 had passed because
that bill had provided a high degree of confidence about
the competiveness of Alaska projects over a broad price
range and offered that "this one does not." He expounded
that ConocoPhillips would have to look at projects in the
context of the price outlook at the time of funding, other
opportunities for investment, and how it competed on
margin. He concluded that some projects would fare better
under CSSB 21(FIN), while others would not.
Senator Bishop remarked that the committee had worked hard
on the bill, had done heavy lifting, and had moved the base
tax rate almost 7 percentage points down. He understood the
position of the oil industry, but offered that industry
needed to understand his position with constituents and the
people of Alaska. He thought that the ConocoPhillips'
presentation would have had an additional slide with a
check mark on the "increased activity box."
6:30:52 PM
DAMIAN BILBAO, HEAD OF FINANCE, BP ALASKA (via
teleconference), spoke in support of CSSB 21(FIN), but
expressed concerns that the bill's base tax rate remained
too high. He referred to his prior testimony on March 5,
2013 and recalled asking a question regarding whether the
current CS to SB 21 made Alaska more competitive for
investment. He explained that when BP made decisions every
year about where to invest, there were many global options;
furthermore, these options competed against each other on a
fiscal basis for investment. He reported that currently,
Alaska trailed other investment alternatives and failed to
compete globally for investment and offered that PFC Energy
had testified that a base rate of 30 percent with the $5
per bbl credit took Alaska from a lower tier of
competiveness to an average level of competition. He opined
that CSSB 21(FIN) raised the base rate back to 35 percent,
which was well above the ACES rate of 25 percent, and
lowered it to 33 percent after a few years; this made
Alaska less than average in competing for investment
globally. He stated that although the base rate in CSSB
21(FIN) remained too high, it made 2 significant steps
forward in making Alaska more competitive; the first step
was the elimination of progressivity, which was fundamental
as an obstacle to making Alaska competitive for investment.
The second positive change that CSSB 21(FIN) made was to
the GRE, which would be applicable to legacy field
opportunities as the bill was currently written.
Mr. Bilbao stated that BP had always testified that the
base rate of 25 percent under ACES was too high and offered
that consultants had shown that ACES had made Alaska not
competitive; over the last 7 years, investment had gone
elsewhere and production had continued to decline. He
concluded that Alaska currently failed to compete globally
for investment and that BP welcomed that positive shift in
the conversation to a policy focused on Alaska's future. He
offered that CSSB 21(FIN) could work and that it addressed
1 concern regarding the GRE; however, the base tax rate
remained too high in the legislation.
6:35:12 PM
Senator Dunleavy requested an explanation of the comment
that the base tax was still too high. Mr. Bilbao replied
that the base tax rate would be too high to compete for
investment and that the legislature's consultants had
stated that Alaska did not currently compete. He offered
that under the 25 percent base tax rate of ACES, Alaska
trailed other global alternatives for investment and
reiterated his prior comments regarding PFC Energy's
testimony; furthermore, CSSB 21(FIN) took the base rate
from 30 percent back up to 35 percent or 33 percent, which
was less than average relative to alternatives for
investment.
Senator Dunleavy asked if the base rate was too high to
compete and thus too high for BP to invest in Alaska. Mr.
Bilbao responded that CSSB 21(FIN) did provide some good
steps forward to making Alaska more competitive, but that
BP felt that it did not go far enough to attract the type
of meaningful investment that was required to make the
future look different than the last 7 years or the current
decline.
Senator Bishop asked what the appropriate number on the
base tax rate should be. Mr. Bilbao answered the
legislature's consultants had shown what a 30 percent base
tax rate would look like and had shown that at 30 percent,
Alaska would be in the middle of the pack. He stated that
Alaska had 2 fundamental challenges: the 1st was the fiscal
policy that was not competitive and the 2nd was the high
cost environment; therefore, if Alaska was simply average
on fiscal policy, the high cost of operating in the state
made it less than competitive globally. He concluded that
Alaska would have to move beyond the middle of the pack in
order to compete for investment and opined that this had
also been asserted by PFC Energy, Roger Marks, and Econ
One.
Senator Bishop observed that consultants were not producing
the oil in Alaska and inquired what BP's preferred number
was. Mr. Bilbao replied that the consultants had done a
good job analyzing how an average industry player would
look at "this" and offered that the issue involved all of
the players, not just the large producers. He furthered
that the numbers that the consultants were presenting were
showing a very good picture of what it would take to
attract an investment and explained that the most recent
analysis by PFC Energy reflected how BP would view the
investment opportunities; a 30 percent base tax rate with a
$5 per bbl credit still failed to move the needle for
significant new investment.
Senator Hoffman asked for verification that Mr. Bilbao had
stated that a 25 percent base tax rate was too high to
compete for investment. Mr. Bilbao replied that under an
ACES structure, the 25 percent rate was too high, which is
why Alaska did not currently compete globally for
investment.
6:39:40 PM
DAN SECKERS, TAX COUNSEL, EXXON MOBIL (via teleconference),
spoke in support of CSSB 21(FIN), but offered that the
bill's base tax rate was still too high. He spoke to the
need for Alaska to create a stable fiscal regime that
attracted the needed and desired investments and offered
that it was most critical issue facing the state. He opined
that while CSSB 21(FIN) made Alaska more attractive than
ACES, the state needed to make itself as attractive as
possible; being in the middle of the pack was desirable,
but Exxon Mobile thought that being attractive should be
the target. He reported that Alaska faced challenges and
obstacles that other states did not and that the more
attractive the state could make itself, the more
investments would flow. He believed that CSSB 21(FIN) was a
remarkable improvement over ACES and made Alaska more
competitive and that the removal of progressivity, by
itself, was a significant improvement over ACES; however,
Exxon Mobile was concerned that the base tax rate in CSSB
21(FIN) remained too high. He offered that consultants had
shown that Alaska was not competitive and that the fiscal
regime was broken and needed to be fixed. He pointed out
that imitation was the sincerest form of flattery and that
he was not aware of any regime that had copied the ACES
structure or any part of it. He expressed that Exxon Mobile
was concerned that while CSSB 21(FIN) was encouraging, it
might also be a regime that others would not duplicate
because the base rate was still too high. He supported
efforts of the committee and hoped that it would continue
working to make Alaska as attractive as possible.
Vice-Chair Fairclough remarked for the record that a major
producer would not pay 35 percent and that the $5 per bbl
of oil exclusion produced a reverse progressivity factor;
the effective tax rate was much lower than the 35 percent
base tax rate. She stated that the committee was doing the
math and understood that the industry wanted projects to be
competitive; however, she wanted the public to be aware
that even though the base tax rate was 35 percent, a
company that was producing oil would have a reduced
effective tax rate.
6:44:47 PM
Co-Chair Meyer noted that the committee had heard from
industry that it was uncertain if CSSB 21(FIN) was
significant enough to increase investment in Alaska. He
pointed to a PFC Energy PowerPoint presentation titled
"Senate Finance CS SB21 Analysis" dated March 14, 2013
(copy on file). He turned to slide 13 titled "Government
Take Competitiveness - $100/bbl" and noted that it showed
Alaska's government take competitiveness under the bill at
approximately 65 percent for existing producers at the 35
percent base tax rate with the $5 per bbl allowance. He
offered that the slide's chart appeared to show Alaska as
being pretty competitive. He acknowledged that Alaska had
disadvantages related to high costs, permitting, and
weather conditions, but thought that it appeared that the
current version of the bill put Alaska in the ballpark; he
requested Mr. Pulliam and Mr. Marks to comment on whether
CSSB 21(FIN) put Alaska in the "ballgame."
BARRY PULLIAM, MANAGING DIRECTOR, ECON ONE RESEARCH, INC.,
referenced a slide that he had presented the prior day that
had contained a series of investment metrics, such as the
net present value, the internal rate of return, the
government take, as well as the margin and depicted them
across SB 21, CSSB 21(RES), and CSSB 21(FIN); the
conclusion he had drawn was that CSSB 21(FIN) put Alaska in
the ballgame. He explained that CSSB 21(FIN) represented a
very positive change that should cause quite a bit of
excitement regarding Alaska's fiscal system, particularly
if it was viewed in conjunction with a commitment to
stability. He opined that CSSB 21(FIN)'s changes did put
Alaska in the ballgame and in a very attractive position.
He pointed out that Alaska had a lot of resources left to
offer and had billions of bbl of oil. He acknowledged that
Alaska had some cost challenges, but offered that many of
the areas that it was competing against globally had the
same cost issues. He concluded one could not find very low-
cost oil these days, but that it was all high-cost oil and
involved challenges; the easy oil, for most part, had
already been taken. He pointed out that the North Sea, the
Lower-48, and Alaska struggled with the same issues and
believed that when everything was put in context, CSSB 21
(FIN) would put Alaska in a good position to attract the
capital it was looking for.
Senator Dunleavy inquired what Mr. Pulliam had stated
regarding excitement. Mr. Pulliam responded that there
should be excitement over CSSB 21(FIN)'s changes from the
standpoint of the investors, which would be ultimately
measured in what investors actually did. He offered that
the last 3 speakers had expressed a combination of
excitement and a desire for a better deal, which he
understood as a tax payer. He opined that it would be nice
to hear from other entities pursuing projects in Alaska and
thought that Armstrong Oil and Gas would be a good company
to talk to. He offered that Armstrong Oil and Gas's
testimony in both the Senate Resources and Senate Finance
Committees had been very positive about the changes in CSSB
21(RES) and CSSB 21(FIN). He referenced changes in the
United Kingdom and the excitement it had generating for the
industry and opined that they were similar to the changes
in SB 21. He reiterated that the success of the bill would
ultimately be measured in what actually happened as a
result.
ROGER MARKS, LEGISLATIVE CONSULTANT, LEGISLATIVE BUDGET AND
AUDIT COMMITTEE, referenced the first presentation he had
provided to the committee (copy on file) related to getting
Alaska's fair share; he had defined "fair share" as what
one could get in a competitive environment. He stated that
he had used the government take metric for his paradigm as
the best apples to apples comparison. He reported that
government take reflected the percentage of one's net
income that went to government and that it automatically
adjusted. He explained that government take reflected high
costs or low costs and expounded that if there were high
costs, there would be a lower net income. He pointed to a
PFC Energy PowerPoint presentation titled "Senate Finance
CSSB 21 Analysis" dated March 14, 2013 (copy on file) and
slide 16 titled "Government Take Competitiveness." He
thought that the slide's peer group was appropriate and
represented the jurisdictions that Alaska was competing
with on a number of parameters. He reported that his
initial thought when looking across the competing
jurisdictions was that Alaska wanted to be at about 62
percent government take and pointed out that the slide
showed that under CSSB 21(FIN), low cost fields in Alaska
were at about 60 percent government take, while the high
cost fields were at about 64 percent. He thought that you
would get more investment at a lower tax rate and less
investment at a high tax rate; furthermore, he thought that
the tax rates under CSSB 21(FIN) would lead to more
investment and production than under ACES. He estimated
that each percentage point of government take was worth
about $140 million to the producers as whole annually and
pointed out that each percentage was important; however,
there was a lot variability in these numbers and it was
impossible to be pinpoint exact. He stated that CSSB
21(FIN) would result in more investment than the current
regime and it may result in more investment in new
development in the legacy fields because of the 4 percent
difference. He concluded that he judged that CSSB 21(FIN)
was in the competitive ballpark of where Alaska needed to
be.
6:54:31 PM
Co-Chair Meyer pointed to Mr. Marks' breakeven analysis
from the prior day and offered that it asserted that Alaska
needed about 70,000 bbl/d of new oil. He asked if the bill
would get the state another 70,000 bbl/d. Mr. Marks replied
that the analysis had covered how much increased production
the state would need over a 20-year period to breakeven
with ACES on total petroleum revenues, including royalties,
production tax, property tax, and income tax; however, that
analysis had been predicated on the CS that had been before
the committee the prior morning, which had 30 percent rate.
He expounded that the breakeven point had changed to 50,000
bbl in CSSB 21(FIN) because of its 33 percent base tax
rate; furthermore, he had made no representation in the
analysis that the state would get the additional bbl. He
pointed out that 70,000 bbl/d was really not that much
given the resource base of 10 billion bbl on the North
Slope. He could not guarantee that the per-bbl target would
happen, but that it was a very reasonable target that could
be exceeded, which would result in the state making more
money than under ACES.
Mr. Pulliam pointed to slide 2 of a PowerPoint presentation
titled "Comments on Senate Finance CS SB21" dated March 14,
2013 (copy on file). He spoke to slide 2 titled "Average
Government Take and Effective Tax Rate ACES v. SFIN CS SB21
for all existing producers (FY2015-FY2019)" and referenced
comments by Vice-Chair Fairclough regarding the effective
tax rate being lower than the base tax. He pointed to the
bottom chart on the slide and stated that at the current
price of about $110 per bbl of oil, CSSB 21(FIN), which was
depicted by the green line, had an effective tax rate of
about 28 percent when the per-bbl allowance was factored
in. He reported that at a price of about $150 per bbl, the
effective tax rate under the CSSB 21(FIN) would top out at
about a 30 percent; these numbers were important to think
about because one could not divorce the nominal rate from
the allowance, but the 2 were designed to work in tandem to
create the flat to slightly regressive curve on government
take that was depicted in the slide's top chart. He offered
that CSSB 21(FIN) was right about where ACES was in terms
of government take at $80 per bbl, but had significant
lower government take than ACES at the higher prices; he
offered that these kind of numbers put Alaska in a good
position.
6:59:42 PM
Mr. Pulliam discussed slide 3 titled "Projected Fiscal
Impact of SFIN CS SB21 Assuming No Production Change
(FY2014 - FY2043)." He related that the slide's analysis
examined the question of what it would take in terms of
additional production to make up for the fiscal impact that
was projected by DOR if a tax system was instituted based
on CSSB 21(FIN); furthermore, the slide showed the fiscal
impact for the 6 years that DOR calculated and then
extended that out in time for another 30 years. He reported
that DOR was projecting a fiscal impact of about $5.7
billion total, which was represented by the years that were
above the line on the slide's table; he noted that the
department's fiscal impact assumed no production change and
offered that there should be a production change with lower
taxes. He opined that if you carried that $5.7 billion
total over 30 years, the total impact was about $20
billion. He stated that because the impacts were happening
over time, the slide depicted money in current or real
dollars, as well as nominal dollars and reported that the
second column showed what the future dollars were worth in
today's dollars; the $19.9 billion projection over the 30-
year period actually reflected about $14.8 billion in
today's money.
Mr. Pulliam spoke to slide 4 titled "Additional Volumes
Need to Offset Projected Fiscal Impact of SFIN CS SB21 (FY
2014 - FY 2043)." He related that the slide used the 50
million bbl field development model that Econ One had
development and looked at the revenues that the state could
expect at DOR's forecasted prices, which worked out to be
about $105 per bbl over time in 2012 dollars. He pointed
out that most of the expected new production would fall
under the 1/6 royalty range, which was 16.67 percent; the
older fields would have a 12.5 percent royalty. he had run
the slide's analysis for both rates. He offered that all of
the production for the 16.67 percent would probably qualify
for the 20 percent GRE and pointed out that the slide
assumed that the 33 percent base tax rate, the $5 per bbl
allowance, and the 20 percent GRE would apply; it also
assumed development costs of about $20 per bbl. Under the
slide's assumptions, every bbl that was developed was worth
about $35 to the state, which was about $25 in 2012
dollars. He reiterated that the fiscal impact in 2012
dollars was just under $15 billion, which would translate
to about 590 million bbl that would need to be developed
over the next 30 years in order for the state to breakeven
on a revenue basis with ACES; this meant that the state
would need about 20 million bbl per year in additional oil
to bridge the revenue gap between CSSB 21(FIN) and ACES.
7:04:48 PM
Co-Chair Meyer inquired what the daily equivalent of 20
million bbl per year was. Mr. Pulliam responded that adding
20 million bbl of oil per year equated to about 55,000
bbl/d. He offered that when thinking about whether 55,000
bbl of additional oil per day was realistic, it was
important to think about the remaining resource base and
observed that there were about 3 billion bbl of
undiscovered conventional oil on state lands in Alaska; 20
million bbl represented a little less than 1 percent per
year of the undiscovered resource. He concluded that over a
30-year period, the 1 percent still represented less than
30 percent of the remaining resources and that from a
technical standpoint, 55,000 bbl/d in new oil should be a
reasonable thing to accomplish.
Senator Dunleavy inquired if Mr. Pulliam would be surprised
to learn that in 3 years, there was little additional
investment in Alaska above maintenance or routine
investment. Mr. Pulliam replied that he would be surprised
if CSSB 21(FIN)'s changes did not have an impact on
attracting new investment.
Senator Dunleavy inquired what Mr. Pulliam's advice would
be to the committee if CSSB 21(FIN) passing did not lead to
noticeable new investment. Mr. Pulliam answered that if
increased investment didn't occur, he would look hard at
what was still standing in the way of increased investment
in Alaska. He pointed out that there were some things that
were not under the state's control such as federal
permitting issues and that those types of issues could
potentially get in the way. He noted that the state was
looking within itself to examine all of the things that it
had control over and opined that the state did well on the
permitting process. He thought that Alaska was pretty
responsive in the areas that it had the ability to
influence.
Senator Dunleavy pointed out that the discussion on the
bill the last several weeks had been centered on tax policy
and how it would dictate investment. Mr. Pulliam responded
that at the current price of oil, CSSB 21(FIN) represented
a change in government take of about 10 percentage points,
which was a significant shift and stated that he expected
that the bill would attract interest and additional
investment; if this did not occur in Alaska, it would be a
"head scratcher."
7:09:44 PM
Senator Dunleavy inquired if it would be a head scratcher,
a surprise, or a shock if nothing happened in 3 years as a
result of the bill. Mr. Pulliam responded that he would be
a little of all of those and that he might be shocked;
furthermore, if this occurred, he would want to take a look
at why additional investment had not result from the bill
passing. He added that other variables might be standing in
the way of investment and that permitting issues would be
applicable to both the ACES and the CSSB 21(FIN) systems;
these other variables needed to be taken into account. He
concluded that, outside of other variables, there was no
reason to believe that the kind of changes in CSSB 21(FIN)
would not increase investment.
Senator Hoffman remarked that the committee had just heard
from 3 of the major Prudhoe Bay investors and recalled that
the commissioner of DNR had been very excited when the
dialogue for the bill had started; he recalled making the
statement that if the majors were not as excited, it would
be very difficult for the committee to pass a bill that had
close to a $10 billion revenue impact at the high end over
a 6-year period. He pointed out that it had been stated
that the major producers "wanted more" and wondered when
these companies would stop saying they wanted more. Mr.
Pulliam replied that he was unsure if they would stop
saying that they wanted more and acknowledged the
situations that the oil companies were in; they wanted the
best possible rates that they could get and at the same
time, were reluctant to offer a hard number.
Senator Hoffman pointed out that he had been present when
the Economic Limit Factor (ELF) had been discussed, as well
as the other tax structures since; furthermore, the
committee had heard from the majors during the discussion
of ACES that the rates were too high and that they would
not come and invest in Alaska. He continued that the rates
were substantially lower in CSSB 21(FIN) and that the
majors were still stating that they would not conduct
additional investment in Alaska; furthermore, the majors
"had kept their word at the other end" and he found it hard
to believe that they would say anything else other than
what they believed. He pointed out that Mr. Pulliam had his
opinion, but that there were billions of dollars at stake.
He pondered whether the committee should listen to the
majors, "that told us the truth" during the discussions on
ACES, or if it should "ignore them" today and pass the
money across the table because Mr. Pulliam believed that
being "south of the middle of the pack" would prompt the
majors to come forward; he opined that this seemed to be a
very high-stakes gamble and inquired if Mr. Pulliam would
have the same opinion if he were representing the people of
Alaska.
7:15:15 PM
Mr. Pulliam responded that he appreciated the position that
the committee was in and noted that it had to do the best
it could by the citizens of Alaska in developing resources
and maximizing them for the benefit of the citizens. He
pointed out that he had been working with Alaska for
several decades and that although he did not live in the
state, he felt a strong connection with it; the health of
Alaska was extremely important to him and he had approached
the issue as an economist. He pointed out that the tools of
economics dealt with motivations, financial motivations,
and what drove investment and noted that the companies in
Alaska were trying to make money. He asserted that it would
be economically irrational to think that the kinds of
changes in CSSB 21(FIN) would not improve and attract more
investment that in turn would lead to higher production. He
reiterated that he approached the issue an economist and
examined markets and economic motivation. He offered that
he had heard 2 things from major's testimony and opined
that each of the 3 majors had said something a little
different; he felt that it would be good to hear from "some
of the other folks, such as the Armstrong Oil and Gas and
Repsol; these companies had been very active over a number
of years in acquiring leases in Alaska and moving towards
development. He offered that Armstrong Oil and Gas, Brooks
Range Petroleum, and Repsol viewed the bill's changes as
very positive. He concluded that he could not offer the
committee any guarantees, but could only provide economic a
sound analysis; in conclusion, CSSB 21(FIN) would put
Alaska in a good competitive position and ought to generate
a response.
7:20:01 PM
Senator Hoffman noted that if the bill passed, it was a
guarantee that billions of dollars would move across the
table and that the 3 major corporations had been truthful
during discussions over ACES. He was unsure if those majors
were not being truthful during the current proceeding, but
knew for a fact that billions of dollars would cross the
table.
Senator Dunleavy inquired if it would be an anomaly if the
investment that Econ One's models predicted did not occur
and further queried if there were instances where the
modeling had failed. Mr. Pulliam replied in the affirmative
and expounded that there were instances where modeling had
not predicted exactly what would happen; furthermore,
modeling did not typically get the direction wrong, but
sometimes got the magnitude incorrect. He explained that
Econ One put its best efforts in and applied its experience
to the modeling; however, he admitted that there could be a
different outcome than what was predicted. He pointed out
that DOR tried to be very diligent regarding its forecasts,
but that numbers were different from what was forecasted,
which was part of the process of forecasting. He stated
that Econ One would be extremely "shocked" if the direction
of its modeling regarding CSSB 21(FIN) was incorrect. He
expounded that the bill made investment more attractive and
that if investment either stayed flat or went the other
way, it would be like "turning the laws of economics on
their head."
Mr. Pulliam discussed slide 5 titled "Additional Volumes
Need to Offset Projected Fiscal Impact of SFIN CS SB21 (FY
2014 - FY 2019)" and related that it looked at the dollar
amount that was in the fiscal note rather than the full 30-
year period; the amount was $5.7 billion and would
represent about a 200 million bbl need in additional
production, which was a little bit bigger than the
Nikaitchuq field.
Co-Chair Kelly inquired how many bbl/d the 200 million bbl
equated to. Mr. Pulliam replied that it worked out to be
about 90,000 bbl/d for a 6-year window.
Co-Chair Meyer expressed confusion and thought that the
target was 50,000 bbl/d. Mr. Pulliam replied that he was
trying to compress the previous slide into a 5-year window
and examine how much production was needed to recover the
fiscal note's cost in 5-years. He stated that 4 Mustang
developments or little bit more than 1 Nikaitchuq field
would be what the state needed.
7:24:18 PM
Co-Chair Meyer handed the gavel to Vice-Chair Fairclough.
BRUCE TANGEMAN, DEPUTY COMMISSIONER, TAX DIVISION,
DEPARTMENT OF REVENUE, indicated that he would be
addressing some the prior questions that were asked in
committee. He provided a PowerPoint presentation titled
"DOR Additional Information Requested: Prepared for Senate
Finance: March 14, 2013" and shared that first several
slides addressed questions that were raised regarding lease
expenditures and how DOR forecast and listed them in the
Revenue Sources Book.
Mr. Tangeman discussed slide 3 titled "Lease Expenditure
Forecast Methodology."
· Request capital and operating lease expenditure
projections from North Slope unit operators in the
fall and the spring of each year in writing for the
next five years from the current year
· Meet with and request spending projections from
companies that are not currently producing but have
announced drilling and/or development plans
· Review and coordinate with production forecast
regarding anticipated developments outside the five-
year time horizon received from operators
· Update long-term capital and operating expenditure
projections based on new information
Mr. Tangeman spoke to slide 3 and related that the second
bullet point was critical under the net tax system because
there were companies in Alaska that were not producing, did
not have a tax liability, but were spending in the state.
Mr. Tangeman spoke to slide 4 titled "North Slope Projects
Included in Fall 2012 Lease Expenditures Forecast."
· Currently producing legacy fields
· Includes ongoing cost of operating fields &
maintenance capital
· Includes facility upgrades and debottlenecking
· Includes new wells and projects in legacy fields
· Targeting new oil not in reach of production
wells
· Work-overs of existing wells
· Advanced EOR projects
· Four new fields in Fall 2012 production forecast
· Point Thomson
· CD-5 (Alpine West)
· Mustang
· Umiat
· Exploration work at other prospects
· Includes primarily announced exploration work
only
· Includes spending plans announced by companies
like Repsol, Great Bear, and others
· Does not include costs for development of
possible discoveries
Mr. Tangeman spoke to slide 4 and pointed out that it
directly related to page 35 of the Revenue Sources Book
where FY13 and FY14 were depicted.
7:27:55 PM
AT EASE
7:38:40 PM
RECONVENED
Co-Chair Meyer resumed chairing the meeting.
Mr. Tangeman continued to discuss slide 4.
Co-Chair Meyer welcomed Senators McGuire and Micciche to
the committee room.
Mr. Tangeman discussed slide 5 titled "North Slope
Operating Expenditures" and stated that it used the
operating expenditures for FY12, and forecasted for FY13
through FY19; additionally, the numbers themselves were
included on the slide of the packet. He pointed out that
there were 2 lines on the slide; 1 line showed the total
operating expenditures while the other showed only the
operating expenditures that were associated with companies
that had a tax liability.
Mr. Tangeman discussed slide 6 titled "North Slope Capital
Expenditures" and reported that it showed the capital
expenditures in the same format at the previous slide from
FY12, as well FY13 through FY19; additionally, on both
slide 5 and 6, FY12 had been prepared using unaudited
company-reported estimates.
Mr. Pawlowski looked at slide 8 titled "Additional Oil
Production Amounts." He related that there had been a
previous question regarding the production scenarios and
asking to expand the price ranges and the data points at
which they were run; what was included in slide 8 was the
actual numbers that went along with the production built
into the scenarios. He reminded the committee that scenario
A was the addition of one 50 million bbl field and related
that the development took some time; the ramp up began at
2017 and peaked at 10,000 bbl/d in 2019. He shared that
scenario B showed the addition of the 4 new rigs drilling
within the legacy fields; each rig was drilling 4 wells per
year, was producing 1,000 bbl/d, and had a decline rate of
15 percent. He continued to address scenario B and related
that the production decline was why the production was not
32,000 bbl/d even though the initial production in FY14 was
16,000 bbl/d; "that" work continued in that scenario
through till the end, and what was depicted was the
incremental production added above the forecast by that
scenario.
Mr. Pawlowski continued to speak to slide 8. He stated that
scenario C was the addition of 4 rigs working in the legacy
fields and the expansion of the large development
opportunity; what was depicted was "that" layered on top of
the activity of the 4 rigs. He pointed out that the top
chart showed the Fall 2012 Production Forecast numbers; it
showed 538,400 bbl/d in FY12 for scenario C, declining to
421,600 bbl/d in FY19. He relayed that Scenario B, on the
other hand, would go from 554,400 bbl/d to 472,000 bbl/d by
FY19 and explained that DOR had wanted to provide the
production data behind the fiscal analysis in order to
allow members to see that there was built-in time and ramp
up in decline in the additional and increased production
that was used to build the slide's scenarios.
Mr. Pawlowski discussed slide 9 titled "Scenarios: At
forecasted production" and related that "these" would match
page 5 of the fiscal note and the scenarios; at the earlier
hearing, DOR was asked to run the numbers at $110 and $130
per bbl and provide the fiscal impact. He reported that
slide 9 included no increased production.
Mr. Pawlowski spoke to slide 10 titled "Scenarios: Scenario
A" and pointed out that the scenario only added 3,300 bbl/d
in 2017, 6,700 bbl/d in 2018, and 10,000 bbl/d by 2019;
there was relatively little fiscal impact from that
additional production because it was minor in scale.
Mr. Pawlowski discussed slide 11 titled "Scenarios:
Scenario B." He relayed that scenario B represented
opportunities in the legacy fields and that the slide
showed the different impacts of that at $110 per bbl, $120
per bbl, and $130 per barrel. He reported that at a price
of $110 per bbl and with the additional activity in
scenario B, the spread would go from $275 million less in
revenue in FY14 and would maintain roughly that amount
throughout the period of the projection; furthermore, it
was important to note that these scenarios did not include
some of the other items that were in the fiscal note such
as the reduced operating expenditures associated with the
capital credits that the state would not be paying, which
would reduce any of those lines by about $110 million per
year.
Mr. Pawlowski addressed slide 12 "Scenarios: Scenario C."
He shared that scenario C was the additional production
scenario plus the additional pad. He added that it was
important when viewing the scenarios, to keep in mind that
they represented discrete production models that did not
take into account additional work beyond those things and
that they were intended to show committee members how
production flowed through at the different price levels and
the different analyses.
Senator Hoffman directed the committee attention back to
slide 9. He acknowledged that the slide did not include any
new production, but that FY17, FY18, and FY19 were when the
state would slide back to a 33 percent base tax rate. He
thought that when ACES had been discussed, the range "back
then" had looked at $70 per bbl to $100 per bbl of oil and
that there had not been any real contemplation of anything
north of that; however, the price had gone as high as $140
per bbl. He observed that the slide's formula showed a cost
to the treasury in the neighborhood of $2 billion, or "a
little south of that," in FY17, FY18, FY19 at $130 per bbl;
even at $90 per barrel "that's substantially less." He
offered that the price of oil was always an unknown factor,
which had been the problem during the discussions on ACES
and pointed out for the record that the fiscal
ramifications of any formula, as well the amount of revenue
the state would receive, was probably more dependent on the
price of oil than on oil production.
7:48:10 PM
Mr. Tangeman turned to slide 14 titled "Forecasted Oil
Production on the North Slope" and related that the final
question DOR would be addressing related to the production
forecast. He thought that Senator Hoffman had requested the
administration to extend the fiscal note a number of years
farther, but pointed out that note included a forecast for
the current budgeted year, which was FY14 and 5 additional
years; furthermore, this was the standard operating
procedure with fiscal notes. He shared that the reason DOR
did not include the forecast farther out was because oil
production forecasting was speculative and became more so
the further out one tried to forecast. He pointed out for
example that when ACES was being debated, the price
forecast was projected to be around $60 per bbl for the
following 5 years through FY12 and production was
forecasted to be 675,000 bbl in FY12, which was a "miss" of
100,000 bbl. He pointed out that DOR and DNR's Division of
Oil and Gas had taken great strides to tighten up the
production forecasts going forward; his example showed how
far off a production forecast could be with a just a 5-year
outlook. Furthermore, the 5-year outlooks were developed
with the best information that the state had available
through discussions with the producers. He believed that a
5-year extension of the fiscal note itself, particularly
relating to the scenarios on page 5 of the note, would be
incredibly speculative; the scenarios were included as good
examples of possible developments that were realistic in
Alaska's future.
Mr. Tangeman continued to speak to slide 14 and related
that the information came directly from page 43 of Revenue
Sources Book. The slide showed the different types of
production that were included in DOR's 10-year production
forecast; currently producing was the first column and was
the category that DOR had the most confidence in
forecasting. The decline rates were depicted and ranged
from 10 percent to 7 percent. He relayed that the next
column represented the risk adjusted new oil, which was the
under development and under evaluation pools that were much
more speculative; furthermore, in order to account for the
speculative nature of this type of oil, DOR had risk
adjusted it in its current forecast, which would hopefully
steer the forecast away from "100,000 bbl misses."
Mr. Tangeman spoke to slide 15 titled "Crude Oil Production
-Forecast" and related that it came directly from page 105
of the Revenue Sources Book; the slide gave a little more
detail of field levels over a 10-yuear period and was good
information regarding where the bulk of the oil on the
North Slope was coming from.
Mr. Pawlowski discussed slide 16 titled "North Slope Lease
Expenditures Fall 2012 Revenue Forecast" and stated that it
gave the data behind the actual operating and capital
expenditures that had been given earlier in the
presentation. He reiterated the comments of Mr. Tangeman
that given the timing of the request, that running the
forecast for the scenarios an additional several years
would require DOR to work with the committee to design a
consensus around what levels or additional projects would
be put in that type of scenario analysis; in other words,
DOR was not going to put that information on the table
without first coming to an agreement with the committee
regarding the details. He concluded that given that time
was a factor, DOR had attempted to be as responsive to the
committee as it could.
7:52:43 PM
Co-Chair Meyer thought that Mr. Pawlowski and Mr. Tangeman
had both done an excellent job preparing the presentation
in the short period of time that they had been given. He
reiterated that if "this" had been known earlier as a
concern, the committee would have requested the information
several weeks prior.
Senator Hoffman pointed to slide 16 [He most likely meant
to say slide 15.] and noted that it showed Point Thomson
kicking in some bbl of oil in 2016. He inquired if there
was no anticipation in the production forecast during this
time for CD-5 or Mustang to produce any oil through 2022.
Mr. Pawlowski believed that the categories were aggregated
to protect confidential tax payer information regarding
specific projects and project related production; however,
DOR had additional support online that could answer which
one of the buckets that might or might not fall into.
Senator Bishop thanked DOR for its time and work.
Mr. Pawlowski responded to Senator Hoffman's question and
related that CD-5 was in the Alpine section because it was
part of the Colville River Unit.
7:55:15 PM
AT EASE
8:02:56 PM
RECONVENED
Co-Chair Meyer addressed the CS and pointed to Amendment 1.
Co-Chair Kelly MOVED to ADOPT Amendment 1, 28-GS1647\Y.7,
Nauman/Bullock, 3/14/13 (copy on file).
Vice-Chair Fairclough OBJECTED for the purpose of
discussion.
SENATOR LESIL MCGUIRE, related that the amendment
represented a concept that was in CSSB 21(RES) that had
been a part of many conversations in the building for
several years as the legislature was trying to gauge
Alaska's competitive with respect to other jurisdictions
globally; the amendment created a competitiveness review
board in Alaska that would provide an opportunity for
Alaska to continually reflect on its position globally with
respect to its competiveness in oil and gas. She shared
that the idea for the amendment had occurred to her when
she had been president of the Pacific Northwest Economic
Region, which was a collection of western states, as well
as provinces and territories in Canada and U.S. that worked
collectively to develop their natural resources and improve
their economies; furthermore, the province of Alberta,
which shared many similarities with Alaska and was almost
exclusively dependent on its natural resources for its
budget, had undergone a very similar lifecycle to Alaska.
She reported that when Alberta had instituted what they
referred to as a "windfall profit tax," which was ACES in
Alaska's case, it had seen the bottom fall out of its
economy; this was similar to what many believed happened to
Alaska, at least in part, as a result of adopting ACES. She
explained that as a result of the windfall profit tax,
Alberta had seen the investors that had been major
supporters of its economy leave the jurisdiction to
Saskatchewan, British Columbia, and other parts of the
globe. In response to investment leaving, Alberta had
established the Alberta Competiveness Council; she pointed
to a report that was in members packets from May of 2011
from that council. She concluded that the model of the
Alberta Competiveness Council gave her the idea that Alaska
could benefit from something similar.
Senator McGuire continued to address Amendment 1. She
discussed a report from May of 2011 from the Alberta
Competiveness Council and shared that it was important
because Alaska had changed its fiscal regime 3 times in the
last 6 years. She pointed out that in in every case of a
fiscal regime change, the impetus had been politically
motivated and had been a source of stress; furthermore, the
changes were made in a compressed time period, in which law
makers were working under accelerated timelines. She
expounded that law makers did not often have a chance to
examine all of the factors that may go into what made an
economy competitive. She referenced earlier comments made
by Mr. Pulliam in response to questions by Senator Hoffman
and Senator Dunleavy regarding what would happens if Alaska
did not see investment responses in 3 years after the
passage of the bill. She offered that Mr. Pulliam's
response that been that he would be shocked from an
economic point of view, but that if nothing occurred, it
would be up to the state to look at other factors, such as
permitting and regulation; furthermore, this is exactly
what had happened with the Alberta Competiveness Council.
She expounded that with its review status, the Alberta
Competitiveness Council had been able to provide
recommendations to its jurisdictions that went far deeper
than fiscal regime recommendations, which was what the
legislature was tasked with; rather than examining taxes,
the competitiveness review board would be looking at
structural things, such as regulations, permitting, and
infrastructure in order to identify how to stay
competitive. She read an excerpt from the May, 2011 report
from the Alberta Competitiveness Council:
A competitive economy attracts industries and
investment to the province, which create jobs and
opportunities for Albertans. A competitive Alberta
also leads to healthy and strong communities.
Businesses that call Alberta home make important
contributions to their communities and they help
finance public services, like education, health,
infrastructure, and environmental protection. Our
province's competitive position, anchored by our
abundant natural resources has fueled our growth and
prosperity over the last decade; however, our
continued prosperity is not assured. Alberta faces a
growing number of competitors and shifting economic
forces stand to impact our future success. We cannot
rest on our past success and passively except
opportunities to keep coming to our province.
Senator McGuire offered that Alaska could be inserted
instead of Alberta everywhere it appeared in the above
excerpt. She pointed out that Amendment 1's competitive
review board setup would consist of 9 members that included
the commissioners of DNR, DOR, the Department of
Environmental Conservation, as well as the Alaska Oil and
Gas Conservation Commission; the other 5 members would be
from the public and would be appointed by the governor. She
explained the experience preferences of the public members
of the competitiveness review board and related the board's
members would serve without compensation, but would be
eligible for per diem and travel expenses; the board's
duties would be to review historical, current, and
potential levels on investment in Alaska to identify
factors that affect investment in oil and gas, as well to
make recommendations annually to the legislature that would
potentially increase Alaska's competitiveness; she reminded
the committee that any action would be up to the
legislature as lawmakers. She opined that the
competitiveness review board would spark an interesting,
reasonable, and thorough dialogue that would be ongoing and
force the conversation each year, hopefully in a way that
was non-political and less emotionally charged than the tax
debates in recent years.
8:10:39 PM
Co-Chair Meyer apologized and acknowledged that the concept
for Amendment 1 had been CSSB 21(RES). He had originally
thought that the competitiveness review board was a great
idea, but had thought that it might be better served
outside of SB 21; however, he understood the linkage
between the Amendment 1 and SB 21 now and was fine with it.
Vice-Chair Fairclough recalled that one of the
considerations when the committee had fist received the
bill was that the competitiveness review board had to a
$1.8 million fiscal note attached to it; however, Amendment
1 was much less intrusive financially. She hoped the
committee would consider adding the amendment the bill.
Co-Chair Meyer thought that Amendment 1 had now had a
fiscal impact of $34,000 for the first year, which was
better than the previous request.
Senator Olson asked what the results of the Alberta
Competitiveness Council had been. Senator McGuire replied
that the results had been positive and that if you looked
at when Alberta's decline rate had started in 2009 on Econ
One's and PFC Energy's presentations, you could see the
that the curve had been redirected. She related that the
parliament in Alberta acting on the recommendations of the
Alberta Competitive Council had been directly responsible
for redirected the decline curve; besides the tax policy,
Alberta had established measures to regulate and access
Alberta's regulatory performance in the areas of oil and
gas and had increased weight limits to provide the safe
transportation of higher density modules. Alberta had also
identified new economic opportunities to commercialize
innovative technologies in the area of the oil and gas
industry and workforce development. She concluded that the
Alberta Competitiveness Council had been very effective.
8:13:30 PM
Senator Olson noted that initially, the competitiveness
review board had been slated to meet 4 times per year and
inquired how often it would meet under Amendment 1. Senator
McGuire replied that the board would meet once annually and
would issue 1 annual report, which was in fact consistent
with the Alberta Competitiveness Council; this reduction
had affected the fiscal impact. She noted that she had been
delighted to work on that compromise with the co-chairs.
8:14:13 PM
AT EASE
8:15:18 PM
RECONVENED
Co-Chair Meyer asked for additional comments related to
Amendment 1.
Vice-Chair Fairclough WITHDREW her OBJECTION. There being
NO further OBJECTION, Amendment 1 was ADOPTED.
Co-Chair Meyer pointed to the 3 fiscal notes attached to
the bill.
Co-Chair Kelly MOVED to REPORT CSSB 21(FIN) out of
committee as amended with individual recommendations and
the accompanying fiscal notes.
CSSB 21(FIN) was REPORTED out of committee as "amended"
with a "do pass" recommendation and with two new fiscal
impact notes from the Department of Revenue and one new
indeterminate fiscal note from the Department of Natural
Resources.
Co-Chair Meyer discussed the schedule for the following
meeting.