Legislature(2013 - 2014)SENATE FINANCE 532
03/13/2013 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB21 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 21 | TELECONFERENCED | |
| + | TELECONFERENCED |
SENATE FINANCE COMMITTEE
March 13, 2013
9:11 a.m.
9:11:47 AM
CALL TO ORDER
Co-Chair Meyer called the Senate Finance Committee meeting
to order at 9:11 a.m.
MEMBERS PRESENT
Senator Pete Kelly, Co-Chair
Senator Kevin Meyer, Co-Chair
Senator Anna Fairclough, Vice-Chair
Senator Click Bishop
Senator Mike Dunleavy
Senator Lyman Hoffman
Senator Donny Olson
MEMBERS ABSENT
None
ALSO PRESENT
Senator Burt Stedman; Senator Cathy Giessel; Michael
Pawlowski, Advisor, Petroleum Fiscal Systems, Department of
Revenue; Dan Stickel, Assistant Chief Economist, Tax
Division, Department of Revenue; Barry Pulliam, Managing
Director, Econ One Research, Inc.;
SUMMARY
SB 21 OIL AND GAS PRODUCTION TAX
SB 21 was HEARD and HELD in committee for further
consideration.
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."
9:13:45 AM
DAN STICKEL, ASSISTANT CHIEF ECONOMIST, TAX DIVISION,
DEPARTMENT OF REVENUE, presented the draft fiscal analysis
of CS SB 21 (FIN) (copy on file). He turned to Slide 1
titled, "Provisions in CSSB 21 (FIN) and their Estimated
Fiscal Impact as compared to Fall 2012 Forecast
($millions)." He cautioned that the fiscal analysis was a
draft and the fiscal note could contain differences. The
slide displayed the data from the fiscal note for the
previous version of the bill [CSSB 21 (RES)]. The analysis
listed the 12 provisions of the legislation that had a
potential revenue impact and the provisions for refunded
credits that impacted the operating budget.
Mr. Stickle reviewed the provisions. He highlighted the
differences (items highlighted in grey) in the Senate
Finance Committee Substitute (CS) compared to the Senate
Resources Committee version of SB 21. The first provision
eliminated the progressive portion of the tax and remained
unchanged. The second provision adjusted the base rate from
35 percent of the production tax value down to 30 percent
in the finance CS. The finance version decreased revenues
to the state compared to the resources CS that imposed a
higher base rate production tax. The third provision
eliminated the qualified capital expenditures for the North
Slope, and remained unchanged in the finance CS. The
finance CS monetized the net operating loss credit and
increased it to 30 percent to match the base rate. The
department deemed that the net operating loss (NOL) credits
would not be taken against tax liability; but instead used
by companies that did not have a tax liability. The change
to the NOL credit impacted the operating budget.
Mr. Stickle discussed the Gross Revenue Exclusion (GRE) for
certain wells. The Resources CS applied the GRE to specific
units, Participating Area (PA) or portions of PAs. The
finance CS applied a lower exclusion of 20 percent, which
was applied to any well that met certain qualifications on
approval by DNR. The range ($0 to $50 million) displayed
assumed that at the lower end only new developments would
receive the GRE. The higher end of the range assumed that
any production in "under development" and "under
evaluation" components of the department's production
forecast would receive the exclusion. The fiscal impact
would likely fall in the middle of the range.
Mr. Stickle detailed that the extension of the small
producer credit was unchanged. The finance CS retained the
elimination of the mandatory two year credit provision. The
community revenue sharing fund and the $5 per barrel tax
allowance were left unchanged. The new corporate income tax
credit for qualified oil and gas service expenditures
remained intact.
Mr. Stickle noted that a new provision in the finance
version was included to reduce the interest rate on late
payments or assessments for most taxes administered by the
Department of Revenue (DOR). He predicted a small impact in
revenues in the early years and a growing impact over time.
The extension of the exploration extension credit was
unchanged from the prior version of the bill. He reported
that the combined impact of the revenue provisions totaled
$900 million to $1.1 billion increasing to $1.5 to $1.9
billion in FY 19.
Mr. Stickle offered that the impact was mitigated to some
extent by the impact on appropriations. The impacts on the
operating budget were divided into three items. The first
impact resulted from credits taken in one versus two years.
The provision advanced the entire $150 million liability in
refunded North Slope Credits to FY 14. The provision was
net revenue neutral. The limitation to the Qualified
Capital Expenditures (QCE) credit decreased refunded
credits by $150 million per year for the North Slope, which
benefitted the operating budget. The finance CS expanded
the NOL credits from 25 percent to 30 percent and impacted
the operating budget by approximately $25 million per year.
Mr. Stickle communicated that the total fiscal impact for
both the state's operating budget and revenue was
approximately $1 billion to $1.3 billion in FY 2014
increasing to $1.4 billion to $1.8 billion in FY 2019.
9:22:11 AM
Vice-Chair Fairclough questioned the GRE for wells as
listed on line 5, slide 1. She referenced that the range
for 2014 was zero to $50 million for certain wells. She
asked what production level the $50 million was based on.
Mr. Stickle replied that the potential $50 million impact
in FY 14 included the under development and under
evaluation portion of the forecast and the number of
barrels for one half of the fiscal year. The fiscal impact
was based on the 20 percent revenue exclusion for the total
number of barrels.
Vice-Chair Fairclough asked the department to provide
information regarding the number of barrels used to
calculate the analysis. She thought the assumption was
valid but she countered that the barrels were not
calculated in new dollars. Mr. Stickle replied that he
would provide the information.
Vice-Chair Fairclough wanted to understand the $50 million
figure used in view of the revenue impact. She wondered
what price per barrel the revenue impact was based on. Mr.
Stickle stated that the draft analysis was based entirely
on the fall 2012 revenue forecast.
Vice-Chair Fairclough asked whether the analysis included
new barrels. Mr. Stickle explained that analysis on line 5
reflected production that was not currently on line but was
expected. The production forecast was divided into three
components. The production classified as under development
or under evaluation in the production forecast were new
wells expected to produce but not currently producing oil.
Vice-Chair Fairclough asked if the wells would qualify for
GRE under the legislation. Mr. Stickle replied that the
department provided a range from zero to $50 million
because qualification of the wells remained uncertain. He
anticipated that the impact fell somewhere in the middle.
Senator Hoffman remarked that the numbers included in the
draft fiscal analysis were "staggering." He pointed out
that the low end estimate of the losses through FY 2019
totaled $7.5 billion or an average $1.25 billion every
year. He added that the high end of the spectrum amounted
to $9.5 billion or $1.5 billion per year. Without any
changes to Alaska's tax structure, the state needed to
borrow up to $400 million from the state's savings account
[in FY 2014]. He warned that the lost revenue would have
detrimental effects to the state's operating budget and
savings accounts. He suggested serious consideration of the
budgetary process. He estimated that $1.6 billion dollars
withdrawn from savings would be necessary to balance the
budget within the first year of the enacted legislation. He
cautioned that the committee must carefully review the
numbers and the impact that the bill had on the needs of
Alaskans.
Co-Chair Meyer agreed with Senator Hoffman's concern about
the potential loss to the state's treasury. He reminded the
committee that the current fiscal year's deficit was due to
decreased oil production. The fiscal note could not predict
the amount of increased production the state could expect
as a competitive participant in the global markets. He
noted his "frustration" with the fiscal note and stated
that if production was not expected to increase, the
committee was wasting its time with the legislation.
MICHAEL PAWLOWSKI, ADVISOR, PETROLEUM FISCAL SYSTEMS,
DEPARTMENT OF REVENUE pointed out that DOR included
"scenario analysis" comparisons of increased new production
predicted in the forecast.
Senator Olson wondered how many barrels of new production
were necessary to make up the lost revenue anticipated in
the next five years. Mr. Pawlowski reported that the
information was still under analysis.
Co-Chair Meyer asked about the fiscal note comparison with
the Senate Resources CS. Mr. Stickle replied that he had
not compared the two fiscal analyses. The finance version
of the bill had a larger fiscal impact under the forecast.
The Senate Resources version impact ranged from $800
million to $900 million in FY 14 to $800 million to $1
billion in FY 19.
9:30:02 AM
Mr. Stickle addressed Slide 2: "Production Tax Revenue,
less refunded and carried-forward credits." He explained
that the slide depicted a graph of production tax revenue
under the Alaska Clear and Equitable Share (ACES), SB 21,
CSSB 21(RES) and CSSB 21 (FIN). The graph displayed the net
production tax revenue minus North Slope refundable
credits. The graph addressed major provisions of the bill
and lacked data for corporate income tax service industry
credit, the expansion of the exploration credit, the
reduction in interest rates for late payments, and
assessments of taxes. He related that all versions of SB 21
provided a better net impact to the state than ACES at the
lower price ranges for oil. The net impact was lower than
ACES at higher oil prices. The net impact of CSSB 21 (FIN)
at the current price of oil was higher than the other
versions of the bill when compared to ACES.
Mr. Stickle continued with Slide 3: "General Fund
Unrestricted Revenue, less refunded and carried-forward
credits." He highlighted that the blue line depicted on the
chart represented total unrestricted revenue to the state
under the ACES regime compared to each version of SB 21
assuming no changes in production and using fall forecast
numbers.
Senator Bishop asked whether the projections were based on
the 2012 fall revenue forecast. Mr. Stickle concurred and
clarified that the revenue analysis was projected for FY 14
price scenarios.
Mr. Pawlowski interjected that FY 15 was chosen because it
was the first full fiscal year the tax changes would be in
effect.
Mr. Stickle noted that the following slides illustrated
three different production scenarios. He reviewed Slide 4:
"Production Scenarios."
Scenario A:
· New 50 million barrel field developed by small
producer without tax liability
· Peak production = 10,000 bbls/day
· Development costs = $500,000,000
· Qualifies for GRE and NOL
Mr. Stickle turned to Slide 5:
"Scenario B: Production Scenarios."
Scenario B:
· Operators of existing unit add 4 drill rigs to
current plans
· Each rig adds 4,000 bbls/day in new production
each year
o Which each then decline at 15 percent per
year
· Does not qualify for GRE
Mr. Stickle cited Slide 6:
"Production Scenarios."
Scenario C:
· Operator of existing legacy unit builds new drill
pad
· Development cost = $5 billion
· Adds 15,000 bbls/day in 2014 increasing to peak
rate of 90,000 bbls in 2018
· Does not qualify for GRE
Mr. Stickle addressed Slide 7: "Projected Revenues under
production scenarios - at $90 per barrel ANS." He explained
that the graph compared CSSB 21 (FIN) under the different
scenarios to ACES under the production forecast in FY 14 -
FY 19. After a few years of additional production at $90
per barrel, SB 21 yields more revenue with scenarios b and
c than with ACES minus the additional production. The graph
intended to provide an estimate of the revenue change
derived from a certain amount of production.
Mr. Stickle discussed Slide 8: "Projected revenues under
production scenarios - at $100 / barrel ANS." He detailed
that scenario b in FY 18 and FY 19 provided a comparable
amount of revenue to ACES. Scenario c provided more revenue
under CSSB 21 (FIN) than under ACES.
Mr. Stickle discussed Slide 9: "Projected Revenues under
production scenarios - at $120/barrel ANS." Scenario C
showed closer projected revenues compared to ACES at the
$120 price of oil. He disclosed that progressivity under
ACES kicked in with a higher surcharge at $120 per barrel.
Mr. Stickle examined Slide 10: "Projected revenues under
production scenarios at forecast ANS price." The final
slide illustrated the comparison using the forecast price.
In the early years, less revenue was projected with SB 21
using all three scenarios than under ACES projected. The FY
2017 - FY 2019 time frame exhibited a level of revenue that
was similar to ACES. He reiterated that the analysis was
not a forecast but illustrated how much additional
production was necessary under SB 21 to equal the revenue
under ACES.
Co-Chair Meyer expressed that the previous slides addressed
his concerns regarding information about the amount of
additional production necessary to offset the fiscal
impacts of changing the tax regime. He wondered which
scenario DOR felt was most likely to occur.
Mr. Pawlowski stated that any scenario was "imperfect." The
conclusion drawn from scenario a was that new field
development was not sufficient to offset the revenue
impact. Scenario b demonstrated that more production in the
legacy fields significantly improved the revenue outlook.
He detailed that the analysis in scenario b included a 15
percent decline each year. The more realistic scenario was
scenario b; the addition of rigs in a legacy field. The
development of "large pads" (scenario c) was a more
"difficult" and long term investment. But was a more
desirable investment for the state.
9:39:53 AM
Mr. Stickle added that DOR felt the scenarios were
"plausible" but could not attach a percentage probability.
Co-Chair Meyer asked whether the analysis included the cost
for credits under ACES. Mr. Stickle thought that they were
factored in.
Mr. Pawlowski answered in the affirmative. He added that
"the analysis portrayed what incremental production would
have to happen under the CS to get towards ACES as
forecast."
Senator Hoffman reiterated analysis that showed that the
state was foregoing $1.4 billion at the low end and $1.8
billion at the high end. He cited scenario C. He commented
that the analysis did not look promising. He wondered
whether a business would make a similar adjustment to
revenues. Mr. Pawlowski replied that the scenarios included
only basic areas of new investment. The committee could
model additional incremental production if further
evaluation was desired after balancing future industry
testimony. Senator Hoffman voiced that any additional
investment was purely hypothetical, if any additional
drilling occurred at all. But the revenue the state was
foregoing under ACES was not.
Co-Chair Meyer relayed that according to industry
testimony; a more competitive environment in the state
meant more industry activity.
Co-Chair Kelly pondered whether the legislators were "here
to protect the interest of the government or are we here to
protect the people of Alaska." He opined that the state
"spent too much." He believed that too much discussion
occurred among legislators about "keeping money for
government." He believed the problem was too much
government. The state took too much money from investors
under ACES and now must examine how to "give some money
back so business will stay here and continue to invest." He
felt that the state must give back measured against what
the people wanted not what the government wanted. He wanted
the legislature to examine how the state spent money. He
stated that "a $5.7 billion operating budget was
ridiculous." The state savings would be expended because
the state spends too much not because of oil tax
reductions. He wanted to protect the ability of Alaskans to
spend their money by ensuring jobs were available.
Senator Olson wondered how revenue sharing would work under
the new legislation. He indicated that revenue sharing
would be appropriated from to the general fund instead of
linked to progressivity.
9:48:37 AM
Mr. Pawlowski offered that the finance CS mandated that
state revenues were deposited into the general fund. The
original version "softly dedicated" corporate income tax
revenue to the revenue sharing fund. He deemed that the
finance CS authors decided that corporate income tax
revenues were general fund revenues. He explained that the
revenue sharing statue guided the decision. The legislature
may appropriate either $60 million per year or up to the
amount necessary to bring the balance of the fund up to
$180 million. The CS took the appropriation from the
broader pool of the general fund instead of the specific
corporate income tax.
Senator Olson wondered whether the legislature could
radically change the revenue sharing contribution. Mr.
Pawlowski answered that the original language required that
the legislature appropriated the revenue from progressivity
into the revenue sharing fund. The amount of the
appropriation was maintained in statute. The statutes
focused on how much the fund needed which provided stronger
guidance for full funding given that the legislature chose
to appropriate to the revenue sharing fund.
Senator Olson asked what the bill's potential impact on the
revenue sharing fund was. Mr. Pawlowski replied that no
difference existed. The amount deposited into the fund was
subject to legislative appropriation.
Co-Chair Meyer added that the revenue sharing language was
the same as what was currently in ACES. The fund was
subjected to legislative appropriation.
9:51:24 AM
AT EASE
9:56:09 AM
RECONVENED
BARRY PULLIAM, MANAGING DIRECTOR, ECON ONE RESEARCH, INC.
presented the Power Point presentation "Comments on Senate
Finance CS SB21."
Mr. Pulliam began with Slide 2: "Summary of Investment
Measures New Participant Investment in 50 MMBO field
$20/Bbl Developmental Capex, 12.5 % Royalty Rate." He
explained that the spreadsheet contained a comparison of
"investment metrics" between ACES and various versions of
SB 21 and other oil producers in the world. He noted that
the net present value (NPV) (measured at price per barrel)
for the investor improved with each version of SB 21.
Mr. Pulliam pointed out that the new provision in the CS
allowed losses to be monetized in contrast to losses being
carried forward. The carry forward allowed a new
participant's economics to look similar to an established
producer.
Mr. Pulliam continued with Slide 2. He directed attention
to Government Take figures and noted that Alaska was more
competitive compared to other parts of the world. He
believed that the investment climate looked very good to an
investor.
Mr. Pulliam turned to Slide 3, "Summary of Investment
Measures Incumbent Investment in 50 MMBO Field $20/Bbl
Development Capex, 12.5% Royalty Rate" He reported that the
spreadsheet contained the same analysis as slide 2 for the
incumbent. The figures in column four that reflected the
finance CS were identical to the chart for the new
participant. Unlike ACES, a new participant had the same or
better tax rate as the incumbent. He exemplified that at
$100 per barrel, CSSB 21 (FIN) offered a higher NPV to the
new participant ($5.97) than the incumbent ($5.87). The
small difference was driven by the small producer credit
extended until 2022. The credit was a write off to buy down
the incumbent's current tax obligation. Monetization of the
early investment by the new participant placed the new
participant in the same financial footing as the incumbent.
He suggested the committee re-examine the need for the
small producer credit while simultaneously allowing
monetization of the losses.
Co-Chair Meyer asked whether the need for the credit was
necessary while offering a net operating loss (NOL). Mr.
Pulliam responded that both the NOL and monetizing losses
placed the new participant on a level playing field with
the incumbent. He thought that made the small producer
credit unnecessary.
Co-Chair Meyer asked how that would impact the fiscal note.
Mr. Pulliam replied that would amount to $25 million to $50
million per year with the same number of producers. More
producers would continue to qualify for the small producer
credit and the impact would increase.
Mr. Pulliam concluded that the finance CS "leveled the
playing field" between the new and incumbent investors and
created a more favorable investment climate.
Senator Bishop asked for an explanation of a cash margin.
Mr. Pulliam explained that a cash margin was the producer's
cash flow after tax payments divided by the number of
barrels that were produced. According to the spreadsheet, a
producer had a cash margin of $44.16 under CSSB 21 (FIN) in
contrast to $29.48 for ACES. Senator Bishop noted that the
cash flow under the finance CS was better than in North
Dakota.
Senator Dunleavy asked whether any of the new or incumbent
participants related what they thought of the proposed tax
legislation. Mr.Pulliam heard favorable responses,
particularly from new participants.
10:07:28 AM
Mr. Pulliam discussed Slide 4:
"Duration of the GRE."
· GRE has the effect of reducing` tax rate
· Removing GRE during life of a well is a tax increase
on that production (to the nominal rate)
· Increase occurs as well productivity is declining and
per unit costs are rising
· can shorten productive life of a well and total
recoveries
· Better Alternative would be a lower GRE over life of
well that provides same economics to the producer.
Mr. Pulliam identified the methods that provided incentives
in the tax systems: (1) GRE, (2) per barrel allowance, (3)
capital credit (ACES). The incentives lowered tax rates and
improved the economics for the producer. He shared his
concern about limiting the GRE over time. He demonstrated
that a lower GRE extended over the life of a well was a
better option through the following three slides.
Mr. Pulliam highlighted Slide 5:
"Well Production Profile Initial 1,500 BPD, 12% Decline
Rate."
¾Approximately 50 percent of oil [was] produced
during the first 5-7 years of well life
¾Well productivity declines while $/Bbl operating
costs rise over time
¾Maintenance and Workovers Extend the Production Life
of a Well
Mr. Pulliam explained that the slide contained a graph that
depicted the annual and cumulative production over a 20
year period of the well. The GRE would raise the tax rate
of the well while it was becoming less productive and
profitable. He suggested the effect was contrary to the
objective of the legislation.
Mr. Pulliam reviewed Slide 6: "Relationship Between Length
of GRE and Percent of NPV of Drilling Cost Initial 1,500
BPD, 12% Decline Rate." The slide graphed the relationship
over time. He exemplified that if the GRE was offered at 20
percent at $100 per barrel over 5 years the NPV for the
producer amounted to 30 percent of the cost of drilling the
well. The GRE was similar to a 30 percent capital credit.
If the limit was extended to 10 years the NPV totaled 40
percent and beyond 10 years the NPV valued 45 percent.
Alternatively, the GRE could be reduced to 15 percent for
the life of the well. The alternative produced the same
results for the producer and "eliminated the potential for
having an earlier shut in for the well." He recommended
that the committee consider a lower percentage GRE over the
full life of a well.
Mr. Pulliam discussed Slide 7: "Example of Tax Calculation
With and Without GRE." He noted that the analysis on the
chart was based on the rates included in the finance CS.
The calculation was based on gross production of 100,000
barrels at 12.5 percent royalty amounting to 87.5 thousand
taxable barrels. The calculation without the GRE minus
expenses amounted to a taxable value of $70 per barrel. The
total production tax value was $6.125 million taxed at the
30 percent tax rate minus the $5 production allowance of
$437.5 thousand for a net taxable total of $1.4 million.
The tax as percentage of the net value of production was
22.9 percent. The tax as a percentage of the gross value of
production was 16 percent. The same variables with a 20
percent GRE ($20 per barrel) were subtracted out of the
taxable value resulting in a taxable value of $50. The
taxes due minus the $437.5 thousand ($5 per barrel) totaled
$875 thousand. The same variables applied at a GRE of 15
percent. The taxable value was $55 per barrel which
resulted in a slightly higher tax due of approximately $1
million dollars. The tax was higher with the lower GRE.
10:18:15 AM
Co-Chair Meyer indicated that the resources CS version set
the GRE at 30 percent. The taxes would be significantly
less at the 30 percent rate. Mr. Pulliam confirmed and
replied that the tax base rate was set higher at 35
percent. The tax rate and GRE offset each other.
Co-Chair Meyer commented that CSSB 21 (FIN) attempted to
accomplish the same rate as the Resources CS but with a
lower tax rate and higher GRE. He surmised that it wasn't
an even exchange. Mr. Pulliam agreed the numbers were not
exact but thought that it was close enough.
In response to a question by Co-Chair Meyer, Mr. Pulliam
reiterated that he advocated lowering the GRE for the
entire life of the well instead of the 20 percent GRE with
a limited duration.
Senator Bishop wondered whether the "theory" behind
extending a lower GRE was to incentivize keeping the well
producing while in decline. Mr. Pulliam concurred.
Mr. Pulliam addressed Slide 8: "Example of NOL Credit
Related to New Investment Of $1 Billion." He understood the
intent of the NOL credit. He described that the chart
exemplified the NOL over a five year period. The chart
depicted a capital spending column and tax loss column at
30 percent. The tax loss, or portion of, would be the
amount monetized. The intent of the CS was to tie the
amount of monetization to the continued investment. The
first year loss was monetized out of a loss in the second
year and the remainder of the loss was carried forward,
which continued through year three. In the fourth and fifth
year the tax loss for the year was monetized at the full
amount and there was no carry forward. In the 5th year
production began and the monetized amount over the 5 year
period was 50 percent and the carry forward totaled 50
percent. The carry forward losses were increased at 15
percent per year. The carry forward was counted against the
tax obligation as it became due. The monetization was tied
to the ongoing investment in an effort to avoid investments
for the sole purpose of investing without production. He
believed that the 30 percent tax rate itself dissuaded
illegitimate investments. He suggested that investors could
pre-qualify the project. Pre-qualification could accomplish
a level playing field between the incumbent and new
investor and ensured that the investment was legitimate.
10:28:14 AM
Senator Bishop asked whether the loss was split between the
producer and the state under the NOL credit. Mr. Pulliam
answered in the affirmative. He added the carry forward
would apply to the producer's tax obligation going forward.
Vice-Chair Fairclough reported that she presented the NOL
concept based on the idea that "people that wanted the
state's money should invest that money into the state."
Consultants suggested using capital credits to accomplish
the objective.
Mr. Pulliam turned to Slide 9: "Annual State Cash Flows New
Participant Investment in 50 MMBO Field $20 Bbl.
Development Capex 12.5 Percent Royalty Rate. He explained
that two graphs on each side of the slide illustrated NOL's
carried forward with and without the GRE and NOL's
monetized with and without the GRE in relation to taxes
specifically production tax (depicted in blue.) He
highlighted that the main difference was that monetization
of the NOL's meant that the state would collect taxes
sooner and if the NOL's were carried forward tax collection
was delayed.
Mr. Pulliam discussed slide 10: "Shares of Per-Barrel
Values Under SFIN CS SB 21 (30 % Base Rate, $5 /Bbl.
Allowance, Losses Monetized) for All Producers (FY 2015 -
FY 2019) He explained that the graph illustrated the profit
share among the state and federal government and the oil
industry. He summarized that as the price of oil raises the
state and industry shares were similar and the federal
government share was smaller.
Mr. Pulliam examined Slide 11: "Interest Rates 1977 - 2012"
He noted that provisions in the finance CS contained
changes to the overdue tax interest rate, which he
concurred with. The current law required the highest of 11
percent or the federal funds rate plus 5 percent. He
believed the 11 percent rate was very high and was
sympathetic with industries disapproval of the rate. He
opined that the rate was punitive and the state should
charge a penalty instead. He explained that the graph
looked back over the time since ANS (Alaska North Slope)
oil was produced and depicted the tax rate declining except
for a period of time in the late 1970's and early 1980's.
He encouraged the committee to eliminate the 11 percent and
tie the interest rates to the federal funds rate plus 3
percent. He felt that was a simpler system and more
equitable for both sides.
Co-Chair Meyer liked the suggestion to change the interest
rate.
SB 21 was HEARD and HELD in committee for further
consideration.
10:37:36 AM
ADJOURNMENT
The meeting was adjourned at 10:38 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 21 3.13.13 CS Fiscal Note SFIN PowerPoint.pptx |
SFIN 3/13/2013 9:00:00 AM |
SB 21 |
| SB 21 Econ One Presentation For Senate Finance (3-13-13) (2).pdf |
SFIN 3/13/2013 9:00:00 AM |
SB 21 |
| SB 21 2013 03 12 Oil Tax and Credits Spreadsheet.pdf |
SFIN 3/13/2013 9:00:00 AM |
SB 21 |
| SB 21 Oil Tax Provisions Comparison 03122013 ACESvSB21introvSB21CSResvSB21CSFi .pdf |
SFIN 3/13/2013 9:00:00 AM |
SB 21 |