Legislature(2005 - 2006)SENATE FINANCE 532
04/01/2006 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB305 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 305 | TELECONFERENCED | |
| + | TELECONFERENCED |
MINUTES
SENATE FINANCE COMMITTEE
April 1, 2006
9:07 a.m.
CALL TO ORDER
Co-Chair Lyda Green convened the meeting at approximately
9:07:12 AM.
PRESENT
Senator Lyda Green, Co-Chair
Senator Gary Wilken, Co-Chair
Senator Con Bunde, Vice-Chair
Senator Fred Dyson
Senator Bert Stedman
Senator Lyman Hoffman
Also Attending: CHERIE NIENHUIS, Petroleum Economist, Department
of Revenue; DAN DICKINSON, CPA, former Director of the Tax
Division, secured as a consultant by the Office of the Governor
Attending via Teleconference: From Offnet Locations: ROGER
MARKS, Petroleum Economist, Department of Revenue; ROBERT MINTZ,
Assistant Attorney General, Oil, Gas & Mining Section,
Department of Law
SUMMARY INFORMATION
SB 305-OIL AND GAS PRODUCTION TAX
The Committee heard from the Department of Revenue, the
Department of Law, and a consultant to the Office of the
Governor. The bill was held in Committee.
CS FOR SENATE BILL NO. 305(RES)
"An Act providing for a production tax on oil and gas;
repealing the oil and gas production (severance) tax;
relating to the calculation of the gross value at the point
of production of oil or gas and to the determination of the
value of oil and gas for purposes of the production tax on
oil and gas; providing for tax credits against the tax for
certain expenditures and losses; relating to the
relationship of the production tax on oil and gas to other
taxes, to the dates those tax payments and surcharges are
due, to interest on overpayments of the tax, and to the
treatment of the tax in a producer's settlement with the
royalty owners; relating to flared gas, and to oil and gas
used in the operation of a lease or property under the
production tax; relating to the prevailing value of oil or
gas under the production tax; relating to surcharges on
oil; relating to statements or other information required
to be filed with or furnished to the Department of Revenue,
to the penalty for failure to file certain reports for the
tax, to the powers of the Department of Revenue, and to the
disclosure of certain information required to be furnished
to the Department of Revenue as applicable to the
administration of the tax; relating to criminal penalties
for violating conditions governing access to and use of
confidential information relating to the tax, and to the
deposit of tax money collected by the Department of
Revenue; amending the definitions of 'gas,' 'oil,' and
certain other terms for purposes of the production tax, and
as the definition of the term 'gas' applies in the Alaska
Stranded Gas Development Act, and adding further
definitions; making conforming amendments; and providing
for an effective date."
This was the second hearing for this bill in the Senate Finance
Committee.
Co-Chair Green informed the Committee that the Tax Division,
Department of Revenue would continue their previous day's
presentation about the proposed Petroleum Production Tax (PPT).
CHERIE NIENHUIS, Petroleum Economist, Department of Revenue,
stated that the "PPT Revenue Studies" presentation, dated March
31, 2006, [copy on file], would resume at page eight. Pages one
through seven had been addressed during the previous Committee
hearing. Her remarks would focus on cumulative and annual
revenues and co-worker, Roger Marks, would address the effective
tax rate and the State's revenues generated from Cook Inlet.
Page 8
Volume Scenarios
· No enhanced volumes / No gasline
- Totals 5.7 billion barrels through 2030
* Including 0.6 billion barrels of heavy oil
- No additional heavy oil at prices under
$30
· Gasline and enhanced volumes
- Totals 10.5 billion barrels through 2050
* Includes additional 3.1 billion barrels
conventional
- 700 million barrels net stemming from
gasline
- Including additional 1.7 billion barrels heavy oil
* No additional heavy oil at prices under $30
Ms. Nienhuis specified that numerous assumptions accompany
economic modelings. To that point, she noted that the Department
incorporated volume and cost assumptions into its PPT modeling.
It also modeled high and low volume scenarios with consideration
of the construction of a natural gas pipeline. The Department is
projecting a low production volume forecast for the State, as
reflected in its Spring 2006 Revenue Sources Book [copy not
provided], based on oil currently under production, oil under
development, and oil under evaluation with no new discoveries
being assumed.
Ms. Nienhuis stated that this low volume scenario anticipated
that approximately 5.7 billion barrels of oil would be produced
through the year 2030. It would be expected that, absent a gas
pipeline or additional oil volumes, the Trans-Alaska Pipeline
System (TAPS) would cease to operate at that time.
Ms. Nienhuis communicated that the high volume scenario is also
referred to as the enhanced volume scenario. This scenario is
typically "coupled" with the development of a gas pipeline, as
the anticipation is that a gas pipeline would be accompanied by
additional exploration and subsequently the discovery of
additional oil volumes. Thus an enhanced volume scenario would
include the cumulative effect of the additional volumes. In
addition, a gas pipeline would affect oil production in three
ways: while there would be a slight decrease in Prudhoe Bay
production, the life of the field would be extended to 2050; it
would include additional volumes of oil from the Point Thompson
Unit; and additional oil would accompany, as of yet,
undiscovered gas reserves. In summary, the high-volume scenario,
at 10.5 billion barrels, would approximately double the State's
low-volume scenario and oil production could extend out until
the year 2050. This volume would include approximately 1.7
billion barrels of heavy oil.
Ms. Nienhuis noted that when oil prices fall below $30 a barrel,
a mechanism is included in the economic modeling scenarios to
limit the production of heavy oil as it is expensive to produce.
9:11:51 AM
Page 9
Volume Scenarios
[The blue line depicted on the graph reflects the low
volume scenario from the year 2005 to 2030. The red line
depicts the high volume scenario from 2005 through 2050.]
Ms. Nienhuis stated that the "waves" in the high volume scenario
line would indicate "the addition of enhanced volumes coming
online every five years or so".
Page 10
Costs and Prices
· Costs
- $100 mm/yr exploration through 2040
- $1/bbl on-going capital on all barrels
- $3.50/bbl developmental capital on 2/3 of existing
conventional oil
- $8/bbl developmental capital on 2/3 of existing
heavy oil
- $3.50/bbl developmental capital on new conventional
oil
- $8/bbl developmental capital on new heavy oil
- $3/bbl operating costs on conventional oil
- $5/bbl operating costs on heavy oil
· Costs, prices, and revenues are all real $2005 dollars
· Heavy oil discounted 8% for quality
· 2.5% of production subject to small company allowance
(5,000 b/d)
· 70% of transition expenditures realized (2 for 1) as
20% credit
- Costs $100 mm/year over 7 years
Ms. Nienhuis noted that the Department incorporated several cost
assumptions in its modeling scenarios. The assumptions were
based on public and non-public sources including partnership
returns and other tax information.
Ms. Nienhuis pointed out that several types of expenses were
considered in determining the cost per barrel (bbl) of Alaska
North Slope (ANS) crude oil. These expenses included exploration
expenses, operating costs associated with both conventional and
heavy oil, and three types of capital costs: on-going capital
costs; developmental capital costs for existing and new
conventional oil; and developmental capital costs associated
with existing and new heavy oil.
9:13:40 AM
Ms. Nienhuis noted that the costs and prices depicted on page 10
were 2005 dollars and were not adjusted for inflation. Heavy oil
had been discounted eight percent for equality.
Ms. Nienhuis disclosed that the modeling has been adjusted to
reflect changes included in the Senate Resources committee
substitute, Version 24-GS2052\C, before the Committee,
specifically its inclusion of the 5,000 barrel per day (b/d)
allowance for small companies.
9:14:03 AM
Ms. Nienhuis stated that after analyzing the production of
companies producing 5,000 b/d or less, it was determined that
this allowance would apply to 2.5 percent of ANS oil production.
This percent would increase annually, as additional companies
fell into the 5,000 b/d or less category due to overall
declining oil production.
Ms. Nienhuis communicated that the one dollar for two dollar
recoupment transition provision included in Version "C" would
allow 70 percent of transition expenditures to qualify for the
20 percent credit. This would equate to credits of approximately
$100,000,000 per year for a seven year period.
Ms. Nienhuis expressed that in addition to price and production
levels of ANS crude oil risks, the PPT would expose the State to
cost risks. Each one dollar differential in the costs depicted
on page 10 would affect State revenues by approximately $70
million each year.
Ms. Nienhuis repeated a statistic previously shared by Mr.
Marks: a $200 million discrepancy would occur were three of the
Department's cost projections incorrect.
9:15:42 AM
Co-Chair Wilken understood therefore that a one dollar deviance
of any of the costs depicted on page 10 could equate to a $70
million difference.
Ms. Nienhuis affirmed.
9:16:29 AM
Page 11
Feedback Effects Not Modeled
· Production depends on investment
- More investment with incentives
- Credits are incentive
· More investment with higher prices
· Less investment with higher taxes
· Investment driven by competitive international
opportunities … which are always evolving
Ms. Nienhuis discussed elements which were not modeled, but
which could affect production. These elements were excluded from
the modeling because the Department "wanted to keep the results
of our modeling purely a tax effect". These "feedback effects
could be subject to debate and possibly result in modeling
error".
9:16:55 AM
Ms. Nienhuis reminded the Committee that the Department had
included in the modeling a mechanism, "relative to price",
through which to decrease heavy oil volumes. "The reason for
that is that heavy oil is very expensive to produce."
9:17:35 AM
Page 12
Cumulative Revenues
· Without enhanced volumes / without gasline (through
2030)
· With enhanced volumes / with gasline (through 2050)
- Does not include gasline severance taxes
- Includes gasline costs
Ms. Nienhuis stated that the Department recognized cumulative
revenues as being "the most important point in the presentation
on revenue". Cumulative revenues would be generated through the
low-volume scenario through the year 2030. Revenues would be
generated through the year 2050 under a high volume scenario
with a gas pipeline. One important distinction between the high
volume scenario with a gas pipeline and the low volume scenario
without one is that the high volume scenario includes "the
upstream costs" of the gasline; specifically the gas processing
plant and various other costs associated with developing gas.
The cost of the pipeline itself would not be included.
Ms. Nienhuis stressed that, while the high volume scenario would
include additional gasline expenses, it would not reflect gas
pipeline revenues; those revenues would be a component of the
gas pipeline contract rather than the PPT. Thus, the PPT high
volume modeling would include the increased costs, but not the
revenue associated with the gas pipeline. It would be reasonable
to anticipate an increase in revenue, separate from this
modeling.
9:19:29 AM
Ms. Nienhuis encouraged Committee members to focus on cumulative
long-term expenses and revenues since it is difficult to
forecast when capital expenditures might occur; therefore, such
things were "smoothed over the life of the project to show a
long-term effect". Spreading anticipated expenses over a long-
term period of time would better represent expected trends in
spending and revenue.
9:20:13 AM
Page 13
Low Volume Scenario Cumulative Severance Tax Chart
[The three graph lines on the "Figure 4" chart reflect Low
Volume Scenario's cumulative severance tax revenues in
billions of dollars for the years 2006 through 2030 under
the PPT formula proposed by the Governor; the formula
proposed by the Senate Resources Committee; and the status
quo Economic Limit Factor (ELF) severance tax revenue,
based on ANS West Coast barrel prices.]
Ms. Nienhuis noted that the severance tax revenues garnered
under the Senate Resources committee substitute would exceed the
revenue generated under ELF at the ANS West Coast barrel price
of $21.60. That "crossover point" under the Governor's PPT
proposal would be $27.70. The slight upward bend in the graph
line of the Senate Resources committee substitute at the $40 ANS
West Coast price was caused by that proposal's Progressivity
mechanism, which would be activated at that price.
Page 14
High Volume Scenario Cumulative Severance Tax Chart
[The three graph lines on the "Figure 5" chart reflect the
High Volume Scenario cumulative severance tax revenues in
billions of dollars for the years 2006 through year 2050,
under the PPT formula proposed by the Governor, the formula
proposed by the Senate Resources Committee, and ELF, based
on ANS West Coast barrel prices.]
Ms. Nienhuis reminded the Committee that the High Volume
Scenario would be accompanied by higher expenses due to the
increased cost of producing heavy oil. The crossover point
relative to ELF would be $25.60 under the Senate Resources
committee substitute and $34.20 under the Governor's PPT
proposal.
Ms. Nienhuis pointed out that, in addition to expanding the
production timeframe and increased oil projections, the revenue
scale on the High Volume Scenario chart would be significantly
higher than that of the Low Volume Scenario.
9:21:39 AM
Co-Chair Wilken, referring to the vertical "Y" axis which
depicted cumulative severance tax revenues, observed that under
the High Volume Scenario, the Senate Resources committee
substitute proposal would, at a $45 West Coast ANS Price,
generate a cumulate severance tax of $50 billion dollars.
Ms. Nienhuis affirmed.
Co-Chair Wilken asked, for comparison purposes, whether a graph
reflecting the PPT proposal being furthered by the House of
Representatives could be developed.
Ms. Nienhuis responded that such a chart could be developed.
Senator Hoffman asked for confirmation that the $50 billion
severance tax revenue referred to by Co-Chair Wilken would be
the cumulative amount for the 44 year timeframe between 2006 and
2050.
Ms. Nienhuis affirmed. She also noted that the effective date of
the Senate Resources committee substitute differed from that
proposed by the Governor. The Governor's bill would not become
effective until 2007.
Senator Stedman pointed out that the effective date of the bill
could be further explored.
Senator Stedman asked that further discussion occur regarding
"the discounting" associated with real verses nominal dollars;
since it is difficult to make a one year forecast, it would be
"near impossible" to forecast out 30 or 40 years.
Senator Stedman also requested that, in the future, the "Y" axis
scale be keep constant on presentation charts. Such uniformity
would make comparing High and Low Volume graphs easier.
Senator Stedman re-emphasized his desire to further discuss the
Department's decisions regarding "the time value of money". To
that point, he asked whether the Department's PPT modeling was
"substantially different" than the PPT modeling developed by
Econ One Research, Inc, [Econ One] the economic and research
consultant firm hired by the Legislature.
9:23:59 AM
Ms. Nienhuis specified that the Department's earliest PPT
presentations included a two-percent inflation factor. The
decision was made to eliminate inflation as it magnified the
scenarios "beyond what we should be expecting", in other words,
revenues would exceed Department projections.
ROGER MARKS, Petroleum Economist, Department of Revenue,
testified via teleconference from an offnet location and noted
that the Department did not utilize "discounted numbers" in its
presentations, although "it would not be difficult to do …
discounting would reduce all the numbers."
Senator Stedman impressed the point that it would be easier to
compare data were the same methodology utilized. As it was, the
reports presented by the various consultants working for the
Administration, the Legislature, and other entities used an
array of methodologies. Footnotes specifying the methodology
utilized in the report would be appreciated.
Mr. Marks clarified that the dollars depicted in the
Department's March 31st presentation were actual 2005 numbers.
The Department's initial PPT data utilized nominal number;
however, the Department determined that the inflation factor
significantly affected the outcome. "A more accurate picture"
would be presented by the use of real dollars.
Mr. Marks communicated that the Department had consulted
numerous times with Econ One. The determination was that their
individual "modeling results are quite similar". Both analyses
of the PPT proposals' "crossover points, for instance, were
within pennies".
Senator Dyson understood that the ANS West Coast prices
reflected on the "X" axis horizontal bar were real dollars. He
asked that real and nominal dollars be defined.
Ms. Nienhuis clarified that real dollars would be defined as
today's dollars; nominal dollars would reflect inflation over
time.
Senator Dyson acknowledged.
9:27:53 AM
DAN DICKINSON, CPA, former Director of the Tax Division, secured
as a consultant by the Office of the Governor, stated that the
best scenario in which to define real dollars would be in terms
of purchasing power. $55 spent today would purchase a larger
quantity of an item than it would purchase in, for instance, ten
years as, due to inflation, more money would be required to
purchase the same quantity of goods. Nominal dollars would
include "an inflation component" to maintain the purchasing
power.
Mr. Dickinson communicated that the Department utilized real
dollars in its presentations due to the concern that building a
two percent annual inflation factor into a 50 year projection
would mislead people into thinking a plan would have more
purchasing power than it really would, "because most of it isn't
an increase in purchasing power, it's just inflation at work". A
two percent inflation factor compounded over a 50 year time
frame would add a "huge amount".
Co-Chair Green stated that a glossary of terms was being
developed. Real and nominal dollars would be included on the
list. Committee members should advise her of other terms they
would like added.
Senator Dyson asked whether real dollars could be defined as
"dollars of the day".
Mr. Dickinson recognized dollars of the day as nominal dollars.
Senator Dyson acknowledged.
Ms. Nienhuis specified that the Department's presentation
expressed monetary amounts in terms of today's dollars as
opposed to, for instance, 2010 dollars.
Senator Stedman asked for information about "discount factors".
Mr. Dickinson exampled that discount factoring would be used
when determining how much "a stream of payments" would represent
were that money available today. In other words, if a payment
schedule included an inflation factor, the money would be
"discounted back down to today's dollars … a great deal of
mischief can occur if you were to inflate it one rate and
discount it a different rate".
In response to an earlier request by Co-Chair Wilken, Mr.
Dickinson noted that a copy of a presentation the Department
developed based on the House of Representatives PPT committee
substitute was available [copy not provided].
Co-Chair Wilken requested the "X" and "Y" axis grid lines on
future charts be kept to a minimum, as cleaner charts would be
easier to interpret.
Mr. Dickinson acknowledged the request.
Senator Hoffman requested charts be developed to reflect how the
Progressivity factors being considered might affect the
Governor's PPT proposal.
Ms. Nienhuis qualified that the Governor's PPT proposal did not
include a progressivity factor.
Senator Hoffman agreed, but explained that a chart portraying
how the progressivity factors being proposed by the Senate would
affect the provisions of the Governor's PPT bill, would be
helpful.
Mr. Dickinson conferred with Senator Hoffman to clarify the
information being sought.
Page 15
Annual Revenues
· Without enhanced volumes / without gasline (through
2030)
- $20
- $40
- $60
· With gasline / with enhanced volumes (through 2050)
(does not include gasline severance taxes; includes
gasline costs)
- $20
- $40
- $60
Ms. Nienhuis stated that page 15 explained that the High and Low
Volume Scenarios charts depicted on pages 16 through 21 were
based on ANS West Coast oil prices of $20, $40, and $60 per
barrel.
Page 16
Figure 6
Annual Severance Tax Revenues @$20 Price
Low Volume Scenario ($ millions)
[The graph lines depicted on this chart indicate that at a
$20 ANS West Coast Price barrel price, declining revenues
would be experienced under each of the three scenarios:
ELF, the Governor's PPT proposal, and the Senate Resources
committee substitute.]
Average annual revenues $40 million less than status quo
(both proposals).
Note: Status quo averages $116 million annually.
Ms. Nienhuis noted the severance tax revenue generated under ELF
reflected current production rates. Revenue would decline with
production. The Senate Resources committee substitute chart
lines reflects a downward slope with a few upward bumps: the
bump depicted around 2009 would reflect increased revenues
resulting from an expected decrease in the TAPS tariff due to
anticipated renegotiations; the upward bump depicted at
approximately 2014 would reflect the termination of the
allowances and transitions provisions proposed in the bill. The
downward slope of all three scenarios "is fairly graphic at $20
prices because the costs and the taxes have a significant
effect" at that price.
9:34:25 AM
Senator Stedman recalled major oil producers testifying "they
would go broke at $20 a barrel". Thus, he asked the Department's
opinion on oil producers' vitality in the year 2020 were oil
prices in the $20 range. He understood British Petroleum's (BP)
breakeven point to be slightly above $20 a barrel.
Mr. Dickinson understood oil producers' remarks to imply that
rather than going broke, their revenue would not allow them to
support significant reinvestment efforts.
Senator Stedman inquired to the financial condition of the State
at that price.
Mr. Dickinson responded that, at $20 a barrel, the State's
financial condition would to be "a terrible one".
Senator Stedman pointed out that at $20 a barrel the State would
face numerous concerns, many of which would outrank concern
about the severance tax.
Co-Chair Green remarked that it would be one of numerous issues
the State would be required to address.
9:36:06 AM
Senator Stedman stated that it has been difficult to accept some
producers' claims that the $20 range is their break-even point.
He could not support the inclusion of such things as annual
"capital cost infusions" in their break even calculations. He
characterized producers' definition of breaking even as being
"fairly liberal".
Mr. Dickinson suggested that, rather than distributing copies of
a presentation regarding the House of Representative's PPT
committee substitute, the Department would revise today's
presentation and include the House PPT provisions in the
comparisons. The revised presentation would then be distributed
electronically.
Co-Chair Green acknowledged. She asked Co-Chair Wilken his
preference in this matter.
Co-Chair Wilken preferred that the House committee substitute
proposal be included as another graph line on the Figure 4 and
Figure 5 charts, depicted on page 13 and 14.
Co-Chair Green reminded the Department to also include a
consistent "Y" axis scale on those charts.
9:38:01 AM
Senator Stedman also requested the Department provide a set of
graphs depicting "the total government take" in addition to the
severance tax revenue. This would enable the Committee to view
the severance tax component within the entire scenario.
Mr. Dickinson clarified that the scope of the presentation had
been made in consideration of time. Initial presentations
included such information but exceeded two hours to discuss.
Co-Chair Green acknowledged, but assured the Department the
Committee would devote time to review the information.
Page 17
Figure 7
Annual Severance Tax Revenues @$40 Price Low Volume
Scenario ($millions)
[This chart reflected the Low Volume scenarios of ELF, the
Governor's PPT proposal, and the Senate Resources committee
substitute at a $40 barrel price from the years 2005
through 2030.]
Senate CS has average annual revenues $600 million more
than status quo and $300 more than Governor's bill.
9:39:12 AM
Ms. Nienhuis read the information, and noted that "the bumps in
the graph become less pronounced" at this price range.
Page 18
Figure 8
Annual Severance Tax Revenues @$60 Price Low Volume
Scenario ($millions)
[This chart reflects the Low Volume scenarios of ELF, the
Governor's PPT proposal, and the Senate Resources committee
substitute at a $60 barrel price from 2005 through 2030.]
Senate CS has average annual revenues $1.6 billion more
than status quo and $800 million more than Governor's bill.
Annual progressive surcharge $200-$400.
Note: This is equivalent to State gasline revenues at
$6.00/mmbtu Chicago price without the gasline.
Ms. Nienhuis reviewed the information on page 18.
In response to a question from Senator Dyson, Mr. Nienhuis
revisited the information in Figure 7 page 17, and stated that,
at $40 per barrel in the Low Volume Scenario, the Senate
committee substitute would generate annual revenues of
approximately $600 million more than ELF and $300 million more
revenue than the Governor's bill.
9:40:02 AM
Ms. Nienhuis noted that the "Y" axis scale, which measured the
Annual Severance Tax, on Figure 8 ranged from zero to
$3,500,000,000 whereas it ranged from zero to $1,600,000,000 on
Figure 7.
Ms. Nienhuis stressed that, as depicted in Figure 8, the Senate
committee substitute would generate annual revenues of $1.6
billion more than ELF and $800 million more than the Governor's
bill.
9:40:50 AM
Ms. Nienhuis noted the Progressivity surcharge included in the
Senate committee substitute would generate revenue ranging from
$200,000,000 to $400,000,000. The $1.6 billion resulting from
the Senate committee substitute would equate to State gasline
revenues at the Chicago price of $6.00 per million British
Thermal Unit (BTUs) absent the gas pipeline. This information
was depicted on the bottom of page 18.
Mr. Marks observed that $1.6 billion in revenue would be
generated under the Senate committee substitute at current ANS
West Coast barrel prices. This would equate to gasline revenues
at $6.00 per million BTUs, absent the gasline.
Senator Hoffman asked the current Chicago price for gas.
Mr. Marks replied that the current Chicago price for gas was
approximately $7.00 Mcf.
Senator Stedman suggested the Committee consider this
information as being "an integral piece of this whole gasline
puzzle". The revenues being discussed in the PPT "are
substantial in comparison to the gasline". The PPT would not
produce "a minor revenue stream relative to" what would be
generated by the gasline. Some people believe the revenues
generated for the State after the completion of the gas pipeline
"would be the key to the future". While he would not disagree
with that position, people should not discount the fact that the
revenue being addressed in this legislation "is a huge piece of
the revenue stream". This issue should not be "minimized,
because there is the possibility" that a gasline might not come
to fruition.
Page 19
Figure 9
Annual Severance Tax Revenues @$20 Price High Volume
Scenario ($millions)
[This chart reflects the High Volume scenarios of ELF, the
Governor's PPT proposal, and the Senate Resources committee
substitute at a $20 barrel price from 2005 through 2050.]
Average annual revenues $80 million less than status quo
(both proposals). Note: Status quo averages $112 million
annually.
Ms. Nienhuis stated this chart reflects the High Volume Scenario
with a gas pipeline. The "fairly large dip" in the Senate
committee substitute graph line from approximately 2010 to 2013
would reflect the money that would be required to develop Point
Thompson. The severance tax revenue during those years could
decline to zero.
9:44:20 AM
Senator Stedman pointed out that, when viewing Low Price
Scenarios, people should be mindful that the industry would also
be subject to royalty payments, property taxes, and perhaps
corporate income taxes. In addition to the challenge the State
might face during low price per barrel years, the industry might
request additional consideration on their other taxation levels.
Such "dynamic issues" should be part of the discussion.
Mr. Dickinson communicated that "one year at the higher price …
would generate enough" revenue to offset approximately four
years at the lower price. As reflected in Figure 9, ELF
revenue's would peak at $300,000,000 in the year 2005 and then
taper downward. While the State might garner zero severance tax
under the Senate committee substitute during the development
years of Point Thompson, ELF would only be generating
$200,000,000.
Mr. Dickinson asked the Committee to advance to the Figure 11
chart on page 21, which depicted the Annual Severance Tax
Revenues under the High Volume Scenario at the a ANS West Coast
Price of $60. At that price, the Senate committee substitute
would generate approximately a billion dollars more than ELF
during the years of the Point Thompson development. That would
equate to a six or seven to one ratio: "seven years of low price
would be recovered in one year of high price." The focus should
be on the fact that it is not an even offset. "One year of high
prices puts us above one year of low prices."
Mr. Dickinson agreed that, as the Committee had pointed out,
this revenue difference might not be obvious due to the
differing "Y" axis scales from one figure to the next.
9:46:48 AM
Page 20
Figure 10
Annual Severance Tax Revenues @$40 Price
High Volume Scenario ($millions)
[This chart reflects the High Volume scenarios of ELF, the
Governor's PPT proposal, and the Senate Resources committee
substitute at a $40 barrel price from 2005 through 2050.]
Senate CS has average annual revenues $500 million more
than status quo and $300 [million] more than Governor's
bill
Ms. Nienhuis affirmed that the "Y" axis scale differences would
be addressed. To that point, she advised that the "Y" axis scale
on Figure 10 was higher than that of Figure 9.
Ms. Nienhuis noted that the monetary impact of developing a
gasline were reflected during the years 2010 and 2013 in Figure
10. Oil revenues from the Point Thompson unit would begin around
the year 2015. In approximately 2030, "the costs for the yet to
be defined gas fields" would be reflected. Thus, the up and down
lines on this chart reflect alternating costs and revenues.
Page 21
Figure 11
Annual Severance Tax Revenues @$60 Price
High Volume Scenario ($millions)
[This chart reflects the High Volume scenarios of ELF, the
Governor's PPT proposal, and the Senate Resources committee
substitute at a $60 barrel price from 2005 through 2050.]
Senate CS has average annual revenues $1.5 billion more
than status quo and $800 million more than Governor's bill.
Annual progressive surcharge $200-$400 mm.
Ms. Nienhuis stressed that the Senate committee substitute would
generate approximately $1.5 billion more in annual revenues that
the status quo. The Progressivity factor would generate an
additional $200,000,000 to $400,000,000 at this price.
9:48:36 AM
Page 22
Effective Tax Rate
Severance Tax / (Wellhead less Royalty)
- Without enhanced volumes / without gasline
- With enhanced volumes /with gasline
Ms. Nienhuis reported that several members of the Senate
Resources Committee requested the Department to provide a
comparison between the status quo taxes on gross revenues minus
royalties or the Value at the Point of Production (VPP), and the
net tax being proposed in the PPT. In order to provide such a
comparison, the Department developed what is being referred to
as the Effective Tax Rate (ETR). As depicted on page 22, the ETR
"is the severance tax as a function of the wellhead less
royalty". In other words, it is the value of the oil at the
wellhead after the royalty fee is removed, as "that is the point
where we start taxing". Caution should be taken in regards to
this term, as it could be used in different contexts.
Ms. Nienhuis reviewed the two scenarios pertaining to the ETR:
the first scenario would be without either enhanced volumes or a
gasline; the second would be enhanced volumes with a gasline.
9:49:58 AM
Page 23
Figure 12
Effective Severance Tax Rate
Sev Tax / Wellhead (less royalty)
Low Volume Scenario
[This chart depicts the effects of Effective Severance Tax
Rates ranging from 0.0 percent to 25 percent and ANS West
Coast oil prices ranging from $15 to $65 in a Low Volume
Scenario. The lines on the graph reflect the impact of
these elements on the status quo, the provisions of the
Governor's bill, and the Senate Resources committee
substitute.]
Ms. Nienhuis communicated that under this scenario, the status
quo would remain constant at approximately the five percent
taxation level because the status quo system was not sensitive
to price. The tax levels of both the Governor's bill and the
Senate Resources committee substitute would be affected by
price. The Senate Resources committee substitute would exceed
the status quo tax rate at a price of $21.60. The Governor's
bill would exceed the status quo rate at a price of
approximately $27.70.
9:50:37 AM
Mr. Dickinson explained that even though the provisions of the
Governor's bill specify a tax rate of 20 percent on net revenue,
the Figure 12 graph is based on gross, as that is the basis for
the tax rate in ELF. Utilizing the same measure for the three
scenarios would provide "an apples to apples comparison".
9:51:13 AM
Senator Stedman remarked that, perhaps with the exception of
"the people paying the bill", most people would agree the ELF
tax system "is broken". To that point, utilizing ELF as the
benchmark for the comparisons would not be the proper comparison
base, "because it's dysfunctional at this time". It has "limited
value" other than providing a reference point.
Senator Stedman, stressing that his remarks should not be
misconstrued as being critical of the charts, suggested it would
be helpful where the Department to align its ANS West Coast
price designations on the chart with those of other entities
such as Econ One, as this might allow discrepancies or data
errors between the information to be more visible. Differences
within a reasonable range could be tolerated.
In response to a question from Co-Chair Green, Senator Stedman
clarified his request. For instance the price points on Figure
12 were in increments of $15, $25, $35 and so forth. The price
points on Econ One's charts, while also in ten dollar
increments, are $10, $20, and $30 and so forth. Thus, his
request would be that an effort be made to align these and other
"data labels" with other presentations when the charts were
revised. This would allow for easier comparisons.
Co-Chair Green acknowledged.
Senator Stedman stated that having comparable data labels would
be particularly helpful in identifying an error in estimates or
"expectations that go out for decades". The goal would be to
have "a reasonable tight range between the different
presenters".
9:54:00 AM
Senator Hoffman pointed out however, that Figure 12 would
reflect that, at a $45 barrel price, the Governor's PPT proposal
would increase the tax by approximately 100 percent.
Senator Stedman asserted that a 100 percent increase over the
status quo might not "be enough".
Ms. Nienhuis assured Senator Stedman that additional data points
could be incorporated into the presentations.
9:54:44 AM
Page 24
Figure 13
Effective Severance Tax Rate
Sev Tax / Wellhead (less royalty)
High Volume Scenario
[This chart depicted the effects of Effective Severance Tax
Rates ranging from 0.0 percent to 25 percent and ANS West
Coast oil prices ranging from $15 to $65 in a High Volume
Scenario. The lines on the graph reflect the impact of
these elements on ELF, the Governor's bill, and the Senate
Resources committee substitute.]
Ms. Nienhuis stated that an ANS West Coast Price of $40 would
generate slightly less revenue under this High Volume Scenario,
when compared to the Low Volume Scenario depicted in Figure 12.
This is due to the inclusion of the costs of both the gas
pipeline and the production of heavy oil.
Ms. Nienhuis stated that incorporating additional data points on
the Department's charts would allow for easier and more "direct
comparisons".
Senator Stedman asked the Department the numbers it was
utilizing for the cost of developing the gas pipeline. The cost
could be in the $25 to $30 billion range.
Mr. Dickinson clarified that rather than the expense associated
with developing the gas pipeline being actual costs, the costs
that would be deductible under the PPT would be limited to the
upstream costs associated with developing the project. He
declared that "when investments are made in Prudhoe Bay, it's
very hard to distinguish between oil and gas". Therefore, "the
actual costs of the gasline are not what is being deducted".
What would be deducted would be "the ancillary costs upstream".
The anticipated cost of developing Point Thompson would be three
billion dollars, and "the incremental costs of developing
Prudhoe Bay" could be approximately several hundred million
dollars.
Senator Stedman stated that the Senate Resources committee
substitute included a 20-percent credit factor. He opted to
further his questions about this and other issues with the
Department at another time.
Ms. Nienhuis concluded her portion of the presentation.
Page 25
State Take
State Revenues / Economic Rent
ROGER MARKS, Petroleum Economist, Department of Revenue,
testified from an offnet location and communicated that his
presentation would explore the revenues the State could receive
under the High and Low Volume Scenarios.
Page 26
Figure 14
State Take
State Rev / Econ Rent
Low Volume Scenario
[This graph on this chart depicted State revenues generated
in the Low Volume Scenario at differing ANS West Coast
Prices under ELF, the Governor's PPT proposal, and the
Senate Resources committee substitute.]
Mr. Marks defined "State take" as the total amount of revenue
the State would receive from royalties, severance tax, property
tax, and corporate income tax "divided by economic rents which
is pre-tax profits". State take is "generally" thought of as
being "a percent of the economic rents".
9:57:27 AM
Mr. Marks stated that Figure 14 would indicate that at low
prices under the Low Price Scenario the State would experience
"a regressive system". A regressive system is defined as one in
which the State take, as low prices, is high. This was due to
three things: the first being that the State's oil industry
property tax was based on assessed value and was not affected by
the price of oil. "Our State corporate income tax is based on
world wide apportionment and profits of the oil companies
worldwide." A company's income tax would be dependant on
worldwide oil prices as well as the industry's refinery margins.
"An integrated producer is quite hedged in that they make a lot
of money on the refining arm of their business when oil prices
are low". Thus, the modeling conducted by the Department
reflected "a significant correlation between our corporate
income taxes and refinery margins." Corporate income taxes are
elevated at low prices because of that.
Mr. Marks communicated that the State's royalties "are based on
the gross value at the point of production and do not reflect
the upstream costs". This is the reason that all three PPT
proposals, the State would continue to receive "a high share of
the rent at low prices".
Mr. Marks noted that, as depicted on the Figure 14 chart, the
State take under ELF would decrease at an ANS West Coast Price
of $25 or higher. As prices increase, the take under the
Governor's PPT proposal would "be fairly level" and the take
under the Senate Resources committee substitute would "increase
slightly" due to the progressivity surcharge.
Page 27
Figure 15
State Take
State Rev / Econ Rent
High Volume Scenario
[This graph on this chart depicted the State revenue
generated in the High Volume Scenario at differing ANS West
Coast Prices under ELF, the Governor's PPT proposal, and
the Senate Resources committee substitute.]
Mr. Marks stated that the chart lines on Figure 15 were similar
to those of Figure 14. "The results are not materially
different."
9:59:48 AM
Figure 16
Total Government Take
Senate CS 25/20 vs. 20/20
Low Volume Scenario
[This chart depicted the Total Government Take in
percentages as reflected on the vertical "Y" axis at ANS
prices ranging from $15 to $65 per barrel as reflected on
the horizontal "X" axis. The lines on the graph reflected
two Government Take scenarios for under the Senate
Resources committee substitute: one with a 25/20 percent
tax rate and the other with a 20/20 percent tax rate.]
Mr. Marks referred the Committee to a Department handout titled
"Figure 16" that portrayed Total Government Take figures [copy
on file] for the Senate Resources committee substitute factored
at a 25/20 tax/credit rate and a 20/20 tax/credit rate. Other
provisions of the committee substitute had not been changed.
While this graph depicted only the Low Volume Scenario, similar
results would be expected from the High Volume Scenario.
Mr. Marks communicated that the five percent variance between
the two tax rates would equate to approximately a 3.75 percent
difference in Total Government Take. The State's severance tax
on the industry would be eligible as a deduction on an entity's
federal corporate business tax, thus, "on an after tax basis",
the federal government would absorb approximately 35 percent of
the cost of the State's severance tax. In addition, there would
also be a slight adjustment in an entity's state corporation
income tax as the severance tax would also qualify as a
deduction. Thus, 90 percent of the 3.75 percent Total Government
Take difference would be the result of "the federal affect and
about ten percent is on the State affect".
10:01:52 AM
Senator Stedman asked whether the information depicted in Figure
16 reflected the Total Government Take of the State or the total
of both the State and the federal government. He thought it
might reflect solely the State government take as a combined
State/federal should be approximately 60 percent.
Mr. Marks apologized. Apparently incorrect numbers were utilized
in Figure 16.
Senator Hoffman perceived the information on Figure 16 to
reflect solely the State take.
Senator Stedman requested the information in Figures 14, 15, and
16 be revised to individually reflect the State and federal
government take, as information on the Total Government Take was
readily available. The desire would be to have the State and
federal government take components differentiated.
Co-Chair Green understood therefore that the request was to have
the federal and State government takes individually reflected on
each of the three aforementioned charts.
Senator Stedman affirmed. Doing so would allow the Committee to
understand the State, federal, and producers' takes, in
percentages, at different ANS prices.
Mr. Marks again apologized for the incorrect information in
Figure 16. He calculated that the total State and federal
government take would be approximately 60 percent. There would
be approximately a three percent variance between the 25/20 and
20/20 tax rates as applied to the Senate committee substitute.
Senator Stedman reminded the Committee that some citizens in the
State were concerned that the State was not getting its "fair
share" of the oil revenue. He asked those individuals to
recognize that the federal government and the producers must
also be considered in the equation.
10:03:59 AM
Co-Chair Wilken asked Mr. Marks whether the 25/20 and 20/20 tax
rate lines on Figure 16 would remain "essentially flat" even
were the ANS Price to reach $120 or $150 a barrel.
Mr. Marks replied that, under the Senate Resources committee
substitute with its Progressivity factor, the slope of the lines
would increase slightly at higher prices.
Co-Chair Wilken understood that the lines depicted on the chart
would continue to reflect a gradual upward slope at higher
prices.
Mr. Marks affirmed. He additionally noted that the relationships
between the three graph lines would remain "constant".
Page 28
Cook Inlet
Page 29
Cook Inlet
[The table on this page depicted oil production in terms of
barrels per day, gas production measured in Mcf (thousand
cubic feet) per day, and gas production in terms of barrels
of oil equivalency (BOE) for eight different producers
operating in Cook Inlet.]
Mr. Marks stated that pages 28 through 34 of the presentation
focused on the affects of the Senate Resources committee
substitute on Cook Inlet oil and gas production.
10:05:56 AM
Mr. Marks characterized Cook Inlet as "a gas province" since, on
a barrels of oil equivalency (BOE) basis, gas would account for
approximately 80 percent of production and oil 20 percent. The
200 Bcf (billion cubic feet) of natural gas that is annually
produced in Cook Inlet is primarily utilized for heat, power
generation, and to support the Liquefied Natural Gas (LNG) plant
and the Agruim urea producing facility in the area.
Page 30
Cook Inlet Gas
· Cook Inlet is 80% gas on a BOE basis
· Industry is evolving
* Decreased production?
* Higher prices?
* Increased investment?
· PPT impact on oil taxes not significant
· Gas taxes on existing fields may increase at higher
prices
· New fields may see lower taxes/higher npv
10:07:16 AM
Mr. Marks communicated that the impact of the PPT on Cook Inlet
oil taxes would not be significant "because the costs of
producing oil in Cook Inlet are fairly high; those fields are
mostly depleted out". However, some additional taxes could be
realized were oil prices "very high".
Mr. Marks communicated that "the Cook Inlet gas industry is
evolving". Most of the fields are old, "production is
decreasing", and the majority of "capital on these fields have
been recovered". The outlook for further investment in the area
is unpredictable at this time.
Mr. Marks stated that during the 40 year history of gas
production in Cook Inlet, the market has been limited to a few
"sets of buyers and sellers". This established "market dynamics"
with fairly low prices since there were "few options outside the
system". However, a few "revolutionary turn of events" occurred
in the past few years: one being that the Regulatory Commission
of Alaska (RCA) authorized Unocal to sell its gas to ENSTAR
Natural Gas Company at Henry Hub prices, which are Gulf of
Mexico prices. This was significant because it "suggests a
leakage from outside the system in". Nonetheless, other than
that pricing change, "it is still a closed system".
Mr. Marks stated that while current Henry Hub prices are high,
gas contract prices not subject to Henry Hub pricing in Cook
Inlet are selling in the mid-two dollar range. However, Marathon
Oil, another Cook Inlet producer, recently requested RCA to
allow it to also charge Henry Hub prices. Thus, there is
uncertainty about future prices in the area.
Mr. Marks noted that the issue of whether the Cook Inlet LNG
plant would be issued an export permit by the federal Department
of Energy in 2009 furthered compounded the Cook Inlet market
uncertainty. Were this permit authorized, the Agrium nitrogen
plant in Nikiski might be forced to shut down as a by-product of
higher gas prices. In addition, the prospect of North Slope gas
being added to the market could deter further investment in the
Cook Inlet area. In summary, future activity in Cook Inlet is a
complicated issue.
Mr. Marks expected that higher oil prices would result in higher
taxes. However, the PPT could lower taxes because it contained
provisions providing deductions and tax credits for the
development of new fields. It also included provisions geared at
attracting "new and small investors". These factors could serve
to increase development in Cook Inlet.
10:10:15 AM
Page 31
GAS ELF
1 - (3000 / Average Well Productivity)
Example: 10,000 mcf/well/day
ELF = 0.70
6,000 mcf/well/day
ELF = 0.50
Mr. Marks stated that the information on page 31 would assist in
clarifying the context of the statement that taxes in Cook Inlet
could increase. He communicated that, in addition to the oil
ELF, the State also has a gas ELF, which is applicable to gas
produced in Cook Inlet and on the North Slope.
Mr. Marks explained that the gas ELF formula is simpler than the
oil ELF, in that the gas ELF exempts the first 3,000 Mcf per
well per day from taxation. For example, the ELF on a well
producing 10,000 Mcf per day would be 0.70. The ELF on a well
producing 6,000 Mcf per day would be 0.50. The Gas ELF has not
been adjusted since being established in 1977, in other words,
the Gas ELF, which is "a nominal gas severance tax of ten
percent", has been "fiscally stable" for 30 years.
Mr. Marks stated that both the gas ELF and the oil ELF were
based "on the principle that a producer should be able to
recover his operating cost based on the price of gas and the
operating costs so the tax itself doesn't make the field shut
down". In 1977 gas was selling for 65 cents Mcf. The Gas ELF
economics have changed significantly in 30 years and, the
Department believes, that, like the oil ELF, "the Gas ELF is
broken as well", at least as far as Cook Inlet is concerned. It
would be considered "appropriate" were the Gas ELF tax to
increase as a result of the PPT "if prices are high enough".
10:12:34 AM
Senator Bunde recalled Mr. Marks' earlier comment that the
affect of "the PPT tax in Cook Inlet would be insignificant".
Mr. Marks clarified that the PPT affect on oil in Cook Inlet
would be insignificant.
Senator Bunde acknowledged. To that point, he had a conversation
with some representatives of Chevron Corporation who felt
otherwise. He asked Mr. Marks why Chevron believed the PPT
"would make the older Cook Inlet wells uneconomical".
10:13:06 AM
Mr. Marks reiterated that oil production in Cook Inlet was very
low. Producers were "not getting a lot of bang for their buck
right now on their wells". Since a minimal amount of new
investment was occurring, the tax credits and deductions
provided under PPT would be insignificant. Operating costs, in
the range of $15 per barrel, are high. That cost could be
deducted.
Mr. Marks referred the Committee back to the chart on page 29
which depicted per day oil and gas quantities by producer in
Cook Inlet. Other than the Forest Oil field which produced 6,891
barrels and the Chevron/Unocal daily oil production of 7,885
barrels, other producers' oil production in Cook Inlet was less
than the 5,000 barrel a day allowance and therefore would be
exempt from the tax. The issue with Chevron/Unocal is that the
5,000 barrel per day allowance "would not be very effective" for
them as the PPT would be "a company wide tax" and their Cook
Inlet and North Slope production would be combined in the PPT
calculation. Were Cook Inlet production isolated, the 5,000
allowance would be beneficial; however, having to combine it
with other fields' production would negate its effectiveness.
Mr. Marks stated that at current prices, Chevron/Unocal would be
paying higher taxes under the PPT. Because the Department has
not investigated the affect of the PPT on individual companies,
the "crossover point" at which Chevron/Unocal would be affected
has not been calculated. Nonetheless, his determination was that
"if anyone's taxes would go up for oil in Cook Inlet, it would
be them", as the 5,000 barrel a day oil allowance would be
negated by their North Slope production. Thus, he would not
disagree with Chevron/Unocal's position.
10:15:40 AM
Senator Dyson noted that active oil producers judged previous
efforts to incentivize oil exploration and production in Cook
Inlet as being the wrong methodology as it only allowed
deductions for successful exploration. The incentives were not
enough to encourage exploration of "wild cat" areas. A better
incentive would have been to allow deductions for exploration
regardless of its success. To that point, he asked Mr. Marks
whether the producers were right.
Mr. Marks agreed with the producers, as the majority of
exploration efforts are failures. Any tax benefit or provision
based on successful production "is worth nothing if you don't
have any production". He stressed that "those same people should
love the PPT" as it contained provisions to encourage small and
new producers. Under ELF, the State shared none of the costs
incurred by "a pure wildcatter" who spent ten million dollars on
an exploration well that came up dry. Under the provisions of
the PPT, that wildcatter's ten million dollar loss would be
multiplied by a tax rate of 25 percent and converted to a $2.5
million credit which could be sold immediately. In addition, he
would be entitled to a 20 percent credit on that ten million
dollars. Thus, under the terms of the Senate Resources committee
substitute, the wildcatter would be entitled to $4,500,000 of
credit that would be available immediately. This would be
"incredibly valuable" on a Net Present Value (NPV) basis.
Therefore, instead of the State sharing none of the risks, "the
State is sharing 45 percent of his dry hole risk … the PPT is a
fabulous mechanism for sharing dry hole risk." It would
encourage new exploration.
10:18:49 AM
Senator Dyson appreciated the information. He asked whether the
PPT would preempt previous incentive programs.
Mr. Marks responded that the PPT bill would allow an entity to
choose whether to utilize an existing exploration incentive
program or the PPT credit provisions.
Mr. Marks explained that some existing credit allowances were
based on the distance an exploration field was from an existing
well. For instance, "a completely new prospect would receive a
40 percent credit." In that case, an explorer would choose that
method rather than the credits available under the PPT. The
various incentive programs could not be combined.
Senator Dyson characterized this as "valuable" information.
Continuing, he asked for confirmation that the producer rather
than the State would be able to choose which incentive program
to use.
Mr. Marks affirmed.
10:20:40 AM
Mr. Dickinson informed the Committee that the existing 40
percent exploration credit incentive was authorized under SB
185. However, due to the program's distance requirements and
other criteria, less than two million dollars of the total $33
million in exploration credits that have been issued under that
program pertained to exploration work conducted in Cook Inlet.
Thus, while SB 185 "was a step" it contained numerous
restrictions, and, as a result, State audits conducted on the
exploration activities disallowed many of the exploration
expenses. Many of the expenses disallowed under SB 185 rules
would qualify for the 20 percent credit under the PPT.
Senator Dyson understood that under the provisions of the
Governor's bill, all development and exploration costs,
including those in existing fields such as Prudhoe Bay, could
qualify for exploration credits. He asked whether the Senate
Resources Committee substitute would disallow any of those
credits.
Mr. Marks responded that the credits and deduction provisions in
the Senate Resources committee substitute were "identical" to
those of the Governor's bill.
Mr. Dickinson concurred; the exception being "minor exceptions"
in regards to abandonment expenses.
10:23:03 AM
Senator Hoffman asked for specifics regarding exploration in
Bristol Bay fields.
Mr. Dickinson communicated that the PPT credits and deductions
were uniform; there were no geographical restrictions or
limitations in either the Governor's bill or the Senate
Resources committee substitute, with the exception being that
the Senate Resources committee substitute included restrictions
specific to private royalty holdings.
Page 32
COOK INLET GAS FIELDS
Field MCF/day Avg Elf
Beluga River 155,740 0.751
Beaver Creek 17,554 0.088
Cannery Loop 40,636 0.601
Granite Point 208 0.000
Happy Valley 5,083 0.170
Ivan River 4,348 0.000
Kaloa Field 3,269 0.424
Kenai Unit 60,907 0.001
Lewis River 1,042 0.000
Lone River 4,240 0.358
Middle Ground Shoal 61 0.000
Moquawkie 5,188 0.354
North Cook Inlet 108,421 0.648
Nicolai Creek 1.593 0.000
Ninichik 30,783 0.373
North Trading Bay Unit 587 0.000
Pretty Creek 1,967 0.000
Redoubt Shoals 2 0.559
Sterling Gas Field 2,094 0.278
Trading Bay Unit 146,343 0.474
Swanson River 10,539 0.000
Wolf Lake 163 0.000
600,768 0.500
Mr. Marks stated this was a listing of all the gas fields
operating in Cook Inlet and their associated gas ELF rates. The
"weighted average" ELF rate in Cook Inlet was 0.500 percent.
This would indicate an average relative productivity of
approximately 6,000 Mcf per day. 3,000 of that 6,000 Mcf would
be tax exempt.
10:24:07 AM
Page 33
Gas ELF
· A 0.50 ELF implies 6,000 mcf/well/day
· Therefore, 3,000 mcf/well/day is tax-free
· The revenue from tax-free gas is supposed to recover
operating costs
· Operating costs for Cook Inlet is estimated to be 50
cents
· Therefore operating costs are $3,000/well/day
· Henry Hub prices are over $7/mcf
· The revenue from the 3,000 tax-free mcf/well/day is
worth $21,000
· This is 7X more than it should be recovering
Mr. Marks reminded the Committee that the gas ELF was based on
the economic scenario of 1977. "The bottom line is if you are
getting a Henry Hub price for your gas in Cook Inlet through the
ELF, you're probably recovering seven times more than you
should, given what the ELF is supposed to be doing." That being
to consider how much gas a company would "need at the market
price to cover your operating costs".
Mr. Marks communicated that, regardless of "the function or
dysfunction" of the gas ELF in Cook Inlet, the gas ELF function
on the North Slope would be "vastly different" where a gasline
available in that region; specifically in regards to the
upstream costs and the "very very high downstream costs".
Therefore, the focus at this time should be on Cook Inlet.
Page 34
Cook Inlet Gas Tax
· We estimate crossover point at about $3/mcf on
existing fields
· At $4/mcf increase of $35 million annually on existing
fields
· Out of $1 billion gross revenues annually
· Decrease as production goes down
· New production may see reduced taxes
Mr. Marks reviewed the information. The three dollar Mcf
crossover point would be approximately two dollars higher under
the Governor's bill due to the inclusion of the $73 million
allowance. As previously explained, when production increased
beyond 5,000 barrels BOE a day, the percent of tax free
production would decrease. Since the PPT's affect on the gas tax
in the Cook Inlet region would be "relatively small and highly
uncertain", it was not included in the bill's fiscal note.
Senator Dyson appreciated the "valuable" information provided in
the presentation.
This concluded the Department of Revenue's "PPT Revenue Studies"
presentation.
AT EASE 10:27:21 AM / 10:37:02 AM
Navigating CSSB 305(RES)
(With the Differences from SB 305 Highlighted)
April 1, 2006
Co-Chair Green advised the Committee that this presentation
[copy on file] was developed for two purposes: to explain the
mechanics of the proposed PPT and to identify the differences
between the Governor's PPT bill, SB 305, and the Senate
Resources committee substitute, CSSB 305 (RES) which was before
the Committee.
Mr. Dickinson pointed out that a color coding mechanism was
utilized in the presentation: red text indicated language in SB
305 and green text indicated language in CSSB 305(RES). {NOTE:
In these minutes, SB 305 would refer to the Governor's bill and
the Senate Resources committee substitute would be indicated ass
CSSB 305.]
10:39:26 AM
ROBERT MINTZ, Assistant Attorney General, Oil, Gas & Mining
Section, Department of Law testified via teleconference from an
offnet location. The presentation would focus on the "core
elements" of the PPT and key provisions differing between SB 305
and CSSB 305(RES). The presentation also included a flow chart
depicting how the tax would be calculated.
Page 2
SB 305, Section 35
CSSB 305, Section 32
New production tax provisions apply to oil and gas produced
on or after:
July 1, 2006 (SB 305)
April 1, 2006 (CSSB 305)
Mr. Mintz stated that one of the differences between the two
versions of the bill is the effective dates: SB 305 would be
effective as of July 1, 2006; CSSB 305 would be effective April
1, 2006.
Senator Hoffman asked how the differing effective dates would
affect the amount of money collected under the PPT, were oil
prices $60 per barrel.
Mr. Dickinson stated that this information would be forthcoming.
Page 3
SB 305, Section 5
AS 43.55.011(a)
There is levied upon the producer … a tax for all oil and
gas produced each month … The tax is equal to 20 percent of
the net value …. under AS 43.55.160.
Mr. Mintz identified this language as being "the most
fundamental core provision" of the PPT. Like the current
production tax, the PPT would be levied on a monthly basis. The
change, however, would be that, rather than continuing the
current practice of taxing oil and gas at differing rates, the
Governor's PPT bill would uniformly apply a 20 percent rate tax
to both oil and gas under "a new concept called Net Value of oil
and gas" as defined in "a new section of the production tax
statute, AS 43.55.160".
Page 4
CSSB 305, Section 5
AS 43.55.011(e)
There is levied upon the producer … a tax for all oil and
gas produced each month … [except for] a lessor's royalty
interest ….
The tax is equal to 25 percent of the production tax value
… under AS 43.55.160.
Mr. Mintz stated that the oil and gas tax being proposed in CSSB
305 would be 25 percent. CSSB 305 would also utilize the term
"Production Tax Value" rather than the term "Net Value".
Page 5
CSSB 305, Section 5 (cont.)
AS 43.55.011(f)
There is levied upon the producer … a tax for all oil and
gas produced each month … the ownership or right to which
constitutes a lessor's royalty interest …. The tax is equal
to five percent of the gross value at the point of
production …[for existing leases]
- BUT …
Page 6
CSSB 305, Section 6 (cont.)
AS 43.55.011(f) (cont.)
The tax is equal to 1.5 percent of the gross value at the
point of production … [for existing COOK INLET BASIN
leases]
- AND …
Mr. Mintz stated that another difference between SB 305 and CSSB
305 would be how the PPT would be uniformly applied throughout
the State, without "a defined tax on a particular lease". To
this point, SB 305 adopted an allocation formula. CSSB 305
instead opted to include a provision about the "tax treatment of
the royalty interest of lessors under private oil and gas
leases" This provision would apply to a "very tiny portion of
the oil and gas produced in the State" specifically "oil and gas
leases leased by regional Native Corporations" such as Arctic
Slope Regional Corporation (ASRC) and Cook Inlet Region, Inc.
(CIRI). In the case of existing leases, the "share of oil and
gas that goes to the owner as royalty is taxed at a rate of five
percent of the gross value at the point of production".
Mr. Mintz pointed out however that instead of being taxed five
percent of the gross value at the point of production, existing
Cook Inlet leases would be taxed at 1.5 percent.
Mr. Mintz qualified however that "even though this is a tax on
the royalty share" tax obligations of the producer would
continue as specified in existing State production tax statutes.
Page 7
CSSB 305, Section 6 (cont.)
AS 43.55.011(f) (cont.)
The commissioner shall recommend to the legislature the
rate of tax [for FUTURE leases]
Mr. Mintz noted that, rather than identifying a tax rate in the
bill for future private oil leases, this CSSB 305 provision
would specify that the Commissioner of the Department of Revenue
would provide a recommendation to the Legislature.
10:44:37 AM
Page 8
CSSB 305, Section 6 (cont.)
AS 43.55.011(g) - (h)
[When West Coast ANS is above $40/Bbl] there is levied upon
the producer of oil a tax … equal to
(West Coast ANS - 40) * .2% *
(ANS Prevailing Value) * 75% *
(amount of oil production)
Mr. Mintz stated that this CSSB 305 provision is what is being
referred to as the Progressivity tax. This tax, which would be
specific to oil, would be an extra tax reactivated when ANS West
Coast Oil prices reached $40 per barrel.
10:45:12 AM
Senator Stedman, referring back to the royalty rate that would
be established by the Legislature as specified on page 7,
requested that, at some point in the future, the Committee
readdress that issue.
Senator Bunde also asked whether the royalty rate determined by
the Legislature would be specific to private leases. The wording
of the provision however, raises "the question of certainty" in
that respect.
10:45:56 AM
Mr. Dickinson communicated that the actual language in the
committee substitute was "The rate of tax levied on oil and gas
produced from a lease in the State that is in effect on the
effective date of this subsection" or in other words, "leases in
effect at time of bill signing". This language is located in
Sec. 5(f)(1) page 3, line 26. The intent of the provision was to
differentiate between current leases and future leases.
Questions about the intent of this language could include such
things as rather re-negotiated leases would be exempt from the
tax. He agreed that this provision should be further addressed,
as it would be important in terms of administering the plan.
10:47:21 AM
page 9
So …
The original bill has a single production tax: 20% of net
value.
The CS has three production tax components:
(1) 25% of net value (now called "production tax value")
except for lessor royalty share
(2) 5% or 1.5% of gross value for lessor royalty share
(3) A progressive-rate tax on prevailing value of oil
only, including lessor royalty share
Mr. Mintz stated that this information summarized the major
differences between SB 305 and CSSB 305(RES).
Page 10
SB 305, Section 21
AS 43.55.160(a)
net value … is the total of the gross value at the point of
production of … oil and gas … from all leases or properties
in the state, less … lease expenditures … as adjusted … and
… 1/72 of … transitional investment expenditures.
Mr. Mintz read the definition of net value. The net value
concept has been included in the State's production tax statutes
for many years; "and this is not something that the bill
changes". Net value would continue to be based on gross value at
the point of production of oil and gas, minus certain
deductions, referred to as "lease expenditures". Further
information about lease expenditures adjustments would be
forthcoming.
Mr. Mintz noted that the Governor's bill also contained a
deduction relating to "transitional investment expenditures",
commonly referred to as "the clawback or the look-back
provision".
Page 11
CSSB 305, Section 22
AS 43.55.160(a)
production tax value … is the total of the gross value at
the point of production of … oil and gas … from all leases
or properties in the state,
less lease expenditures … as adjusted
Mr. Mintz reminded the Committee that CSSB 305 would substitute
the term "production tax value" for the existing "net value"
term. The gross value at the point of production would continue
to be the first step in the calculation. Lease expenditures, as
adjusted, would then be deducted.
Mr. Mintz noted that CSSB 305 would not allow a deduction for
transitional investment expenditures as specified in SB 305.
Page 12
SB 305, Section 31
CSSB 305, Section 28
AS 43.55.900(7)
"gross value at the point of production" means
for oil, the value … at the … meter … in … pipeline quality
for gas … the value … where … metered
[after any separation or gas processing]
Mr. Mintz stated that the terms identified on this page were
those terms in the PPT bill whose definitions "are somewhat
changed from the current definitions in the production tax
statute".
Mr. Mintz shared the Department's view that, rather than being
substantive, the definitional changes regarding the point of
production for oil would "simplify" and "update" language. The
metering point of production for oil would continue to be the
point at which the oil was "pipeline quality".
Mr. Mintz pointed out, however, that the definition for the
point of production for gas was "substantively changed";
specifically in regards to the activity called gas processing.
This process typically "involved refrigerating a gas stream to
remove valuable hydrocarbon liquids" known as natural gas
liquids (NGLs). Under existing State statute, gas processing
occurred downstream from the point of production. Under the PPT,
the point of production would be downstream from gas processing.
This definitional change would allow gas processing costs to be
deductible. The Department of Revenue could provide further
information about this policy change if desired.
Page 13
SB 305, Section 19
CSSB 305, Section 20
AS 43.55.150(a)
… gross value at the point of production is calculated
using the reasonable costs of transportation …
10:51:33 AM
Mr. Mintz stated that this information mirrored that in existing
law and was included as a refresher of "the basic principal
called the net-back method of calculating value". This concept
was developed in consideration of the fact that ANS oil, while
produced on the North Slope, was typically sold on the West
Coast. Thus, the calculation for net value was based on the
destination value less the cost of transporting the oil. This
calculation is referred to the gross value at the point of
production.
Page 14
SB 305, Section 20
AS 43.55.150(d)
… the department may allow … gross value [to be calculated
based upon] … a royalty settlement agreement … [or]
a formula … that uses … [DNR or U.S. Dep't of Interior]
royalty … valuation [or]
another formula … that reasonably estimates a value …
Mr. Mintz pointed out however, that there was one change in "how
the gross value concept is addressed" in the PPT. The PPT would
allow the Department of Revenue to simplify formulas where they
deemed appropriate. Under SB 305, this permissive authority
allowed the Department to develop a formula that would allow "a
producer to use the royalty value under a royalty settlement
agreement" with the Department of Natural Resources, "or, in the
case of federal leases, United States Department of the Interior
royalty values," or the Department could develop alternate
simplified formulas that, for example would consider
transportation costs, price indices, and other factors. The
purpose of this change would be to increase efficiency in the
process of achieving a "reasonable estimate of gross value".
10:53:31 AM
page 15
CSSB 305, Section 21
AS 43.55.150(d)
if the commissioner completes a detailed fiscal analysis
and determines … the long-term fiscal interests of the
state [would be served] … the department may allow … gross
value [to be calculated based upon DNR or U.S. Dep't of
Interior] royalty … valuation [or] another formula … that
reasonably estimates a value ...
Mr. Mintz stated that this information reflected a change CSSB
305 made to the provision depicted on page 14. CSSB 305 would
mandate that in order to use a simplified formula with a
producer, the Department must conduct "a detailed fiscal
analysis and make a determination" that a particular formula
would, in the long term, be in "the fiscal interest of the
State". In addition, CSSB 305 removed the option that allowed
the Department to develop a formula "utilizing a royalty
settlement agreement".
Page 16
SB 305, Section 21
AS 43.55.160(c)
… lease expenditures ... are the total costs upstream of
the point of production … on or after July 1, 2006 … that
are the direct, ordinary, and necessary costs of exploring
for, developing, or producing oil or gas … in the state.
Mr. Mintz stated that the first step in calculating "net value
or production tax value" would be to determine gross value.
Certain lease expenditures could then be deducted from that
figure. Eligible lease expenditures would include "the total
costs upstream of the point of production that are direct
ordinary and necessary costs of exploring for, developing, or
producing oil or gas". This "very general statement" would be
further addressed in later provisions of the bill. The focus at
the moment should be on how the committee substitute changed the
lease expenditures definition.
Page 17
CSSB 305, Section 22
AS 43.55.160(c)
… lease expenditures ... are the total costs upstream of
the point of production ... on or after April 1, 2006 ...
that are the direct, ordinary, and necessary costs of
exploring for, developing, or producing oil or gas … in the
state.
Mr. Mintz identified the "only change in the fundamental
definition of lease expenditures" between the two versions of
the bills was that CSSB 305 had an effective date of April 1 and
SB 305 had an effective date of July 1. CSSB 305's effective
date would allow costs to be accounted for earlier.
Page 18
Section 21/22
AS 43.55.160(c) (continued)
In determining … [direct, ordinary, and necessary] costs …
the department shall give substantial weight ... to typical
industry practices and standards ... as to [billable] costs
... under unit operating agreements ... and [DNR net
profits share lease regulations].
Mr. Mintz stated that this language would provide the Department
"very meaningful statutory guidance" in determining what would
qualify as lease expenditures. The PPT would allow the
Department to draw on two sources for guidance: one would be
typical industry practices and standards regarding the costs
that could be billed by an operator.
10:55:41 AM
Mr. Mintz identified the second existing source of guidance as
being "the Department of Natural Resources' standards for what
costs are deductible under their net profit share/lease
regulations".
Page 19
CSSB 305, Section 22
AS 43.55.160(n)(2)
CS adds a definition of "ordinary and necessary" to make
clear that Internal Revenue Code meaning is adopted.
Mr. Mintz noted, however, that CSSB 305 would alter one element
of the definition of "direct, ordinary and necessary". While SB
305 would likely "incorporate Internal Revenue Service (IRS)
precedent" of those terms, CSSB 305 would "explicitly
incorporate" it. Thus the definition of "ordinary and necessary"
would adopt the meaning "those terms have for federal income tax
purposes".
Page 20
Section 21/22
AS 43.55.160(d) provides specific examples of, and
exclusions from, "direct costs"
CSSB 305 has several improvements recommended by the
Administration: e.g.,
· (d)(1)(A) and (d)(2)(A), clarifying treatment of
capitalized expenditures
· (d)(2)(L), ensuring that conservation surcharges are not
deductible
Mr. Mintz stated that this Statute would specifically identify
which costs would or would not be deductible as direct costs. At
the request of the Governor Murkowski Administration, CSSB 305
expanded the direct cost provisions to provide further clarity.
Page 21
CSSB 305, Section 22 (cont.)
CSSB 305 has several additional exclusions:
· (d)(2)(M) Costs of dismantlement, removal,
restoration, etc., re: previous oil or gas production
· (d)(2)(N) Costs above fair market value, in non-arm's
length transactions
· (d)(2)O) Costs to acquire a company
Mr. Mintz reviewed the exclusions added to CSSB 305.
10:58:27 AM
Senator Stedman asked that further discussion occur in regards
to which business overhead expenses would be included or
excluded under the criteria such as "buildings and offices in or
out of the State…"
10:59:07 AM
Mr. Mintz expressed that business overhead expenses are
"explicitly" addressed in CSSB 305. "Overhead would generally be
considered an indirect cost and the general rule in the bill is
that only direct costs are deductible." This is the reason the
committee substitute would "allow reasonable allowance … for
overhead expenses," directly related to exploring, developing,
or producing oil and gas deposits in the State, as determined
through regulation by the Department.
Mr. Mintz stated that the issue of whether a building in
Anchorage would qualify as an overhead expense had been
discussed. The general response was "just because a producer
incurred costs in running his business, does not necessarily
mean those costs are deductible". Viable overhead deductions
would be those costs "incurred directly for oil and gas
exploration, development or production".
Mr. Dickinson agreed. While a building would not be recognized
as an overhead expense, industry practice would recognize as an
overhead component an additional employee's salary. An example
of this would be an instance in which British Petroleum (BP), in
its capacity as an operator, billed another working interest
owner for the salary of a BP engineer working on a Prudhoe Bay
project. This is anticipated to reflect "the general approach"
allowed under this legislation. This bill would allow the
Commissioner to "develop an allowance for overhead" as opposed
to allowing "certain categories of costs" be the rule.
Co-Chair Green asked whether a "standard calculation procedure"
for operators' overhead expenses currently existed.
Mr. Dickinson responded in the negative. A variety of overhead
standards, rather than a singe one, currently exists in the
State. A business person would recognize this as being "the
classic negotiation about how overhead gets passed through one's
projects".
Co-Chair Green stated that this issue would be further
addressed.
Senator Stedman acknowledged.
Page 22
SB 305, Section 21
AS 43.55.160(e)
[Lease expenditures must be adjusted by subtracting
payments the producer receives for (1) another's use of a
production facility; (2) reimbursement, e.g. field costs
paid by state, that offset lease expenditures; and (3) sale
of assets acquired through lease expenditures or of non-
taxable oil or gas used in lease operations.]
Mr. Mintz stated that this section provided further information
regarding lease expenditures, as adjusted, as previously
referenced in SB 305, Section 21, AS 43.55.160(a) on page 10 of
the presentation. The "simple" concept would be to allow net
costs to be deducted. For example, were a producer "reimbursed
for some of the costs, those reimbursements should be netted
against the costs that are deductible"; were a producer to
acquire an asset that incurred costs against the deductible and
then sold the asset, "the sale receipts should also be netted
out against the costs".
Page 23
CSSB 305, Section 22
AS 43.55.160(e)
[Lease expenditures must be adjusted by subtracting
payments the producer receives for (1) another's use of -
or for managing -- a production facility; (2)
reimbursement, e.g. field costs paid by state, that offset
lease expenditures; and (3) sale - or removal from the
state - of assets acquired through lease expenditures or of
non-taxable oil or gas used in lease operations.]
Mr. Mintz noted that this information identified changes CSSB
305 made regarding lease expenditures specified in SB 305. SB
305 specified that the payment a producer received for allowing
another entity to use their production facility should be an
adjustment. CSSB 305 added the words "or for managing a
production facility"; thereby mandating that the management fee
should also be a deduction. This also served to "close a
loophole" pertaining to the sale of an asset, as earlier
addressed on page 22. The removal of an asset from the State for
use somewhere else should be treated in the same manner as the
sale of that asset for purposes of adjustments.
Page 24
CSSB 305, Section 22
AS 43.55.160(a), (b)(2), and (e)
At the Administration's recommendation, the CS addresses
potential timing mismatches between lease expenditures and
adjustments, ensuring that the tax effect of an adjustment
will be recognized even if a producer or explorer has no
production, or has low lease expenditures, when an
adjustment payment is received.
Mr. Mintz stated this provision "summarizes the intent of
several groups of text" in AS 43.55.160. "The adjustment to
lease expenditures is intended to implement the rule of allowing
only net costs to be deducted." However, timing mismatches might
make this difficult.
Mr. Mintz recalled the earlier example of an explorer who spent
ten million dollars drilling wells. Since an explorer does not
produce oil or gas, there would be no production tax to which to
apply the credits provided by that expenditure. Nonetheless, the
ten million dollar expenditure would qualify as deductible lease
expenditures and therefore "can be converted" into a 25 percent
credit under the provisions of the PPT.
11:05:10 AM
Mr. Mintz continued that, in this case, the monies garnered from
an asset purchased as part of the ten million dollar expenditure
and then sold "ought to be netted out against the ten million
dollars". The question, therefore, was how to apply that
adjustment when the sale of the asset occurred the following
calendar year and after the explorer had received the 25 percent
credit. This provision would specify that were "an adjustment to
occur in a time period where a producer" or an explorer had no
"taxable oil or gas production or if the lease expenditures are
too low to deduct the adjustment from without getting to a
negative number", then the negative number should be used. This
would generate a tax liability that recognized the adjustment
even though its might occur in a later time period.
11:05:58 AM
Page 25
CSSB 305, Section 22
AS 43.55.160(k) and (l)
For purposes of (1) excluding from lease expenditures costs
that exceed fair market value, and (2) determining the
amount of an adjustment to lease expenditures due to the
sale of an asset, standard = "a producer dealing at arm's
length with an uncontrolled entity"; and IRS rules may be
adopted.
Mr. Mintz stated that CSSB 305 added this language to allow the
Department to follow IRS standards of fair market value to
purchases made "by a producer dealing at arm's length with an
uncontrolled entity".
11:07:19 AM
Page 26
SB 305, Section 21
AS 43.55.160(g)
… transitional investment expenditures are … capital
expenditures [incurred 7/2001 through 6/2006] … less …
[proceeds from] the sale ... of assets … acquired ... as a
result of [those] capital expenditures
[This provision is not in the CS; instead CS provides for a
tax credit for some transitional investment expenditures.]
Mr. Mintz stated that one of the deductions allowed in SB 305
was a transitional investment expenditure. This expenditure
would be recognized as a capital expenditure were the
expenditure to occur five years prior to the effective date of
the bill. The committee substitute deleted this provision and
instead included tax credit provisions.
Page 27
SB 305, Section 21
AS 43.55.160(i)
… a producer that is qualified ... may reduce the net value
by deducting an allowance … [T]he total of the allowances …
during the calendar year does not exceed $73,000,000. An
unused allowance ... may not be carried forward …
[This provision is not in the CS; instead CS provides for
an allowance that depends on the average daily oil and gas
production.]
Mr. Mintz stated that the $73 million per producer annual
allowance provision included in the Governor's bill was omitted
from the committee substitute and replaced with an allowance
based on average daily oil and gas production.
Page 28
CSSB 305, Section 22
AS 43.55.160(g)
… a producer that is qualified ... and produces under
55,000 BOE/day may reduce the net value by deducting an
allowance ... equal to the following fraction of the
production tax value:
(5,000 - 0.2 * [average daily production - 5,000]) ÷
average daily production
Mr. Mintz stated that this language was a summary of CSSB 305's
allowance provision. The 5,000 BOE/day allowance would a
producer's total amount of oil and gas production in the State.
While "oil and gas are treated as equivalent" in the example, he
noted that 6,000 cubic fee of gas would be equivalent to one
barrel of oil. Were a producer to produce less than 5,000
barrels of oil or gas equivalent per day, they would receive a
"100 percent allowance against" their taxable oil and gas
production. As production increased, the percentage of allowance
would decrease rapidly until it reached zero.
Mr. Mintz pointed out that the correct BOE/day production volume
should be 30,000 BOE per day rather than the 55,000 BOE per day
depicted on both this page and in Sec. 22(g), line one, page 20
of CSSB 305.]
Mr. Dickinson affirmed the number should be 30,000 BOE; however,
having the incorrect number in the formula was mathematically
acceptable as "the formula takes you below zero at that point".
11:10:34 AM
Senator Stedman informed the Committee that the Senate Resources
Committee initially utilized a 0.1 percent multiplier in their
tax allowance formula. That multiplier was subsequently
increased 0.2 percent. The 0.2 percent multiplier served to run
the tax allowance to zero at 30,000 BOE/day.
11:11:11 AM
Mr. Mintz concurred with Senator Stedman' observation.
Mr. Mintz noted that both the $73 million allowance specified in
SB 305 and the revised allowance based on oil and gas production
in CSSB 305 were per producer allowances.
Page 29
CSSB 305, Section 22
AS 43.55.160(h) - producer's qualification for an allowance
- ability to qualify expires in 2013
This is an anti-splitting provision to prevent abuse
of the per producer allowance under AS 43.55.160(g).
It is essentially the same anti-splitting provision
that is in sec. 21 of the original bill, for the $73
million per producer allowance.
Mr. Mintz stated that this provision would address concerns
about possible loopholes or abuse of the allowance by producers.
One concern was that a producer might spin off, divide up, "or
generate a multiplicity of different producers" and thereby
"generate a multiplicity of allowances". Thus, this "anti-
splitting provision" was incorporated into both SB 305 and CSSB
305. This provision would require a producer desiring to get an
allowance "to demonstrate to the Department that that kind of
gaming" had not occurred. In addition, in order to qualify for
the allowance a producer must be qualified by the Department
each calendar year.
11:12:36 AM
Senator Bunde asked the reason a five year time period had been
specified as the time in which a producer could qualify for an
allowance. He had been told this time frame was simply "a policy
call".
11:12:59 AM
Mr. Mintz thought that Senator Bunde might be referring to the
five year look-back period for transitional investment
expenditure. That issue was separate from the per producer
allowance specified in AS 43.585.160(g). The transitional
investment provision would be a component of the forthcoming
"credits" discussion.
11:13:24 AM
Senator Bunde clarified that his question pertained to the
timeframe specified in AS 43.55.160(h).
Mr. Dickinson clarified that this provision's qualifying period
would end in the year 2013. Therefore, a PPT with a 2006
effective date would allow a producer a seven year time period
in which to qualify.
Mr. Mintz communicated that while he could address issues
pertaining to the PPT formula, he would defer to others in
regards to policy issues.
Page 30
SB 305, Section 7
CSSB 305, Section 7
AS 43.55.020(a)
… the tax levied under AS 43.55.011, net of any credits
applied under this chapter, is due …
… the tax levied under AS 43.55.011(e) ... net of any
credits applied under this chapter, is
due …..
Mr. Mintz noted that the calculation of net value, which is
referred to as production tax value (PTV) under the PPT had been
discussed earlier. Once the PTV is determined, the tax rate of
25 percent would be applied to it under AS 43.55.011 in CSSB
305. However, before "the actual tax liability" was determined,
"there is the possibility of applying tax credits to the amount"
due. Both SB 305 and CSSB 305 "recognize that the tax that's due
is after credits" are applied.
Page 31
SB 305, Section 12
CSSB 305, Section 13
AS 43.55.024(a)
… a producer ... that incurs a qualified capital
expenditure ... may ... elect ... to take a tax credit in
the amount of 20 percent of that expenditure.
Mr. Mintz stated that this provision would further explain tax
credits relating to capital expenditures. The provisions in SB
305 and CSSB 305 were identical in this regard. Both would allow
a 20 percent credit on qualified capital expenditures.
Page 32
Section 12/13 (cont.)
AS 43.55.024(h)(1) and (j)(2)
[AS 43.55.024(h)(2) in original bill]
"qualified capital expenditure" -
· [is a lease expenditure for G&G exploration,
intangible drilling costs, and other expenditures
capitalized under IRC]
· [does not include purchase of a previously acquired
or used asset]
Mr. Mintz stated that these provisions would clarify what would
suffice as a qualified capital expenditure. This language is
similar in both bills. A qualified capital expenditure must
foremost be a lease expenditure. "A lease expenditure is
everything that is deductible for purposes of calculating
taxable value of oil and gas."
11:16:03 AM
Co-Chair Wilken assumed chair of the meeting.
Mr. Mintz responded to Senator Dyson's earlier question
regarding "credits availability for existing operations".
Senator Dyson had also voiced support for allowing credits "for
all exploration development, and production costs". To that
point, he clarified that while all lease expenditures would be
eligible as a deduction, only "capital type expenditures"
associated with exploration, development, and production
projects would also be eligible for the 20 percent credit.
11:16:42 AM
Mr. Mintz continued that, "for the most part", these qualified
capital expenditures would be those "treated as capitalized
under federal income tax rules. In addition to that, the bills
would allow exploration expenditures for geological and
geophysical (G&G) activities" such as seismic exploration to
qualify for the credit.
11:17:08 AM
Mr. Mintz pointed out that provisions were incorporated into the
PPT bill "to avoid the problem of churning". This term described
the situation in which a producer might buy an asset, receive a
credit, and then sell the asset to a second producer who would
also get a credit. The PPT bill would only allow a credit for an
asset "if it has not previously been placed in service in the
State or previously been acquired as a result of an expenditure
that would qualify for the credit".
11:17:47 AM
Page 33
CSSB 305, Section 13 (cont.)
AS 43.55.024(h)(2)
"qualified capital expenditure" does not include
an expenditure incurred ... for ... an extended period of
disuse, dismantlement, removal ... or abandonment ... or
for the restoration of a lease, field, [etc.]
Mr. Mintz identified restoration activities as another important
element of the bill. The "extended period of disuse" verbiage
would apply to suspended or mothballed operations.
In response to a question from Co-Chair Wilken, Mr. Mintz
explained that the term "G&G exploration" as denoted on page 32
was an abbreviation for "geological and geophysical
exploration", primarily seismic exploration.
11:18:47 AM
Senator Stedman ascertained from Mr. Mintz's remarks that there
might be a question about how the provision on page 33 could be
interpreted. To that point, he asked whether there was a
"language issue" that should be addressed.
Mr. Mintz responded that the wording "extended period of disuse"
could be further clarified. This language is located in Sec.
13(h)(2), on page 9, line 28 of CSSB 305.
Mr. Dickinson qualified that there were two issues with the
verbiage in question. Further clarification of the definition of
"disuse" would be desired, to include a review of whether this
might involve safety or health issues. The second issue would
pertain to "the notion of "extended period". Either the bill
drafters must provide "more clarity" of the term "extended
period of disuse" or the issue must be addressed in regulations
as the language is "open to a lot of interpretation".
11:20:14 AM
Senator Stedman noted that, as the review of this "complicated
bill" continued, other issues might require further
interpretation. To that point, he asked whether the
Administration would be developing a list of elements they
deemed to require further attention.
Mr. Dickinson assured the Committee that an ongoing list of
issues needing further review would be maintained.
11:20:59 AM
Page 34
HB 305 Section 12 (cont.)
AS 43.55.024(b)
A producer may elect to take a tax credit ... of 20 percent
of a carried-forward annual loss [which is the amount of a
previous year's lease expenditures that were not deductible
because they would have reduced the net value of the oil
and gas below zero].
Mr. Mintz identified this provision as "the second major
category of credit. This is basically just a different form of
allowing losses to be carried forward in a calendar year where a
producer's lease expenditures exceed the gross value of the oil
and gas." In this case, a producer would be prohibited from
utilizing the entirety of their deductions in that year if doing
so would result in a negative value and thereby a negative tax.
This provision would allow those deductions to be "converted to
a credit" toward the following year. "A carried forward annual
loss" under the Governor's bill with its 20 percent tax rate
would thereby allow a 20 percent credit of "carried forward
excess lease expenditures".
Page 35
CSHB 305 Section 13 (cont.)
AS 43.55.024(b)
A producer ... may elect to take a tax credit … of 25
percent of a carried-forward annual loss [which is the
amount of a previous year's lease expenditures that were
not deductible because they would have reduced the
production tax value of the oil and gas below zero].
Mr. Mintz stated that CSSB 305 modified SB 305's "carried
forward annual loss" provision to align this allowance with the
committee substitute's 25 percent tax credit provision and its
"production tax value" terminology.
Mr. Mintz noted that, unlike the qualified capital expenditure
credit options explained earlier by Roger Marks in which the
producer could opt between utilizing the qualified capital
credit program in this bill or an existing exploration incentive
credit program, this carried-forward annual loss credit
provision would be automatically available to a producer.
11:23:27 AM
Senator Bunde understood therefore that the carried-forward
annual loss credit differed from the 20 percent investment
credit.
Mr. Mintz affirmed. He stressed that these credits would be
"additive" in that the 20 percent qualified capital expenditure
credit would be in addition to the 25 percent carried-forward
annual loss credit allowed under CSSB 305.
Senator Bunde asked whether, as a result of the various credits
provided in the bill, there might be a point at which the State
would be required to return money to producers.
Page 36
Section 12/13 (cont.)
AS 43.55.024(d) - (f)
A producer entitled to a tax credit may apply to the Dep't
of Revenue for a transferable tax credit certificate. Once
issued, a certificate may be used for its face value, but a
transferee may not apply a certificate to reduce its tax
liability by more than 20 percent during a calendar year.
Mr. Mintz stated that this language would "indirectly" address
Senator Bunde's question. "An important feature of realizing the
incentive nature of the credits, particularly for explorers and
producers that do not have a lot of current production, is for
them to monetize the credits that they can't use against their
own taxes." Both SB 305 and CSSB 305 would allow producers and
explorers to apply to the Department of Revenue to have their
credits turned into transferable tax credit certificates. The
Department would expedite the request in order not to impair the
value of the credit. This would assure the producer buying the
credit that their tax could be reduced by the "face value" of
the certificate.
Mr. Mintz disclosed that were an audit or other information to
later discover "something amiss" which affected the credit, the
Department could address any tax deficiency with the original
producer or explorer who had been issued the certificate.
Mr. Mintz also noted that the entity purchasing the certificate
could not utilize the certificate to reduce their tax liability
by more than 20 percent during a calendar year. This would
"prevent excessive impacts on total State revenue". This limit
would not apply to an entity utilizing its own credits.
11:26:24 AM
Senator Hoffman asked whether the credit certificate could be
transferred "only to producers or explorers".
Mr. Mintz responded that the legislation did not contain any
"express limitation on who could buy" the credit certificate.
However, the only entities "who could ultimately benefit" would
be those with "a production tax liability". Those entities
"would be the producers". He allowed that "an intermediary could
conduct a trade".
Mr. Dickinson affirmed Mr. Mintz's remarks. The credit
certificate would be useless to an entity that did not have a
production tax liability. It could not be "applied against an
income tax or royalty obligation.
Senator Olson ascertained therefore that the credit certificates
could be transferred between the major three producers.
Mr. Dickinson clarified that the credit certificates could be
available to any producer. The expectation would be "that these
would generally be generated by explorers who would then sell
them to the producers who have the income tax liability". This
would allow an explorer "to monetize these immediately by
selling them to someone who can use them".
11:27:51 AM
Page 37
CSSB 305, Section 13 (cont.)
AS 43.55.024(i) - nontransferable credit for transitional
investment expenditures
… transitional investment expenditures [TIE] are ...
capital expenditures [incurred 4/2001 through 4/2006] ...
less ... [proceeds from] the sale ... of assets ...
acquired ... as a result of [those] capital expenditures
Mr. Mintz noted that AS 43.55.024(i) in CSSB 305 served to
substitute a third credit into CSSB 305 for the transitional
investment expenditure (TIE) deductible specified in SB 305. A
TIE was defined as "what would be qualified capital expenditures
if they were taking place in the future"; however, "they're
expenditures that were incurred in the previous five years".
Page 38
CSSB 305, Section 13 (cont.)
AS 43.55.024(i) (cont.)
· a producer may ... take a tax credit ... of 20 percent
of the producer's [TIE] but only [up to] one-half of
the producer's qualified capital expenditures ...
during the month
· credits are non-transferable
· credit provision expires April 1, 2013
Mr. Mintz explained that the third credit incorporated into CSSB
305 would be "tied to new investment"; thus "a credit for
previous investments can only be taken in a time period when the
producer makes new capital investments". The maximum credit that
could be taken in a time period would be limited "to one-half of
the amount of the new capital investment". This credit is often
referred to as "the two for one provision".
Mr. Mintz stated that the TIE credit differs from the two
previously discussed credits because it would not be
transferable. In addition, the TIE credit provision would expire
in 2013.
11:29:21 AM
Senator Stedman noted that the TIE credit language was located
in Sec. 13(i)(4) lines 26-28, page 10 of CSSB 305. This language
might require revising were confusion to arise from the
intermingling of the terms "transferable and nontransferable" in
the text.
Senator Stedman also suggested that a summary page be developed
that would define the various tax credits. This would be helpful
when discussing the credit aspects of the bill.
Co-Chair Green asked whether TIE and the other credit terms
being discussed were currently defined in State Statute.
Mr. Dickinson communicated that the credit terms included in the
PPT were not currently defined in State Statute. Their
definitions however, were contained within the bill.
Co-Chair Green asked whether including the credit definitions
within the bill would suffice.
Senator Stedman responded that due to the complexities of the
bill a summary sheet would be helpful; particularly in assuring
that everyone is "on the same page" when issues were being
discussed.
Co-Chair Green stated that this information could be included
with the glossary of terms directory previously discussed.
Page 39
SB 305, Sections 22-29
CSSB 305, Sections 23-26
Original bill allowed a credit to be taken for conservation
surcharge payments; CS does not.
CS reduces sec. 201 surcharge from $.02 to $.01 per barrel
and increases sec. 300 surcharge from $.03 to $.05 per
barrel.
Mr. Mintz stated that these provisions would address "one last
credit issue"; specifically the conservation surcharges which
currently exist in the State's production tax statute. The
conservation surcharge has typically amounted to two or three
cents per barrel. SB 305 proposed a credit to be taken against
the production tax for the surcharge payments. CSSB 305
eliminated that credit. CSSB 305 also reduced one of the
conservation surcharges from two cents to one cent per barrel
and increased the other from three cents to five cents per
barrel.
11:32:21 AM
Mr. Mintz summarized the presentation to this point: "the
calculation of gross value has been discussed and "we've looked
at lease expenditures, adjustments, deducting the lease
expenditures, getting the taxable value, and applying credits
against the tax" in order to determine the actual tax amount
that would be owed.
Page 40
SB 305, Section 7
Ninety percent of production tax, net of credits, is due
each month.
The remainder is due March 31 of the next calendar year.
Mr. Mintz remarked that the material on pages 40 through 42
would address the manner in which the PPT would be paid under SB
305 and CSSB 305. The production tax would continue to be paid
monthly under both bills. However, the inclusion of upstream
costs in the equation would require "longer term aspects" to be
considered in the calculations. This could require adjustments
to be made throughout the year.
Mr. Mintz explained that SB 305 addressed the adjustment issue
by requiring producers to make a monthly "safe harbor" payment
equating to 90 percent of the tax owed. SB 305 also included a
"true-up provision" which required the balance of the actual tax
amount to be paid by March 31 of the next calendar year.
Page 41
CSSB 305, Sections 7, 12
AS 43.55.020(e) and (f)
· 95 percent of principal production tax (AS
43.55.011(e)), net of credits, due each month.
Remaining portion due at end of next calendar quarter.
· 100 percent of tax on lessor royalty interest (AS
43.55.011(f)) due each month.
· Bill does not specify payment of progressive-rate oil
tax (AS 43.55.011(g)).
Mr. Mintz pointed out that the approach taken in CSSB 305
differed from that of SB 305 in that it would require producers
to pay a 95 percent "safe harbor". The balance of the actual tax
would be due at the end of the next calendar quarter.
Mr. Mintz specified there to be three components in how the tax
would be paid under CSSB 305. The 95 percent safe harbor
provision would apply "to the principal tax which is the 25
percent tax on production tax value". Another component was "the
separate tax on the private royalty share"; 100 percent of this
tax was due each month under ELF. This tax could continue to be
paid in its entirety because, being based on the gross value at
the point of production, it did not contain many variables in
its calculation.
Mr. Mintz communicated that, "in its current form", CSSB 305 was
not specific about when the third component, which is the
progressivity tax, would be paid. This omission should be
addressed.
Senator Stedman understood the rationale behind the safe harbor
and true-up provisions included CSSB 305, however, he expressed
that further discussion should occur in regards to the concept
of collecting 100 percent of the tax on lessor royalty interest
each month as specified in AS 43.55.011(f). This discussion
should include how to deal with a situation in which the tax
paid was only equivalent to, for instance, 99 percent of the
royalty tax.
Senator Stedman also requested the Administration to be included
in the effort to develop the appropriate Progressivity rate
payment language. The goal would be to insure that the tax would
be collected rather than treated as a pledge of payment such as
an IOU "into perpetuity".
Page 42
SB 305, Section 9
CSSB 305, Section 9
[P]roducer may deduct [from royalty] the amount of the tax
paid on taxable royalty oil and gas ...
· Original bill provides a default formula for
allocating the 20% tax on net value to royalty share.
· CS provides a slightly different formula for
allocating the 25% tax on net value ("production tax
value") to non-lessor royalty share.
Mr. Mintz stated that this provision focused on the "private
royalty share of the tax". Even thought this tax would be "on a
small amount of production", the issue was complicated. While
"the whole production tax is a liability of the producer,
including that part of the production tax on the royalty share,
… the producer has the legal right to collect against the
royalty owner for their royalty share of the tax". SB 305
included "a default formula" for how the royalty share would be
calculated on the 20 percent tax.
Mr. Mintz stated that a default formula would not be required
under CSSB 305 because it contained a specific royalty tax.
"However, there are other types of royalty interests besides the
royalty owed by a lessor under an oil and gas lease. These are
usually called overriding royalty interests. These would be
typically carved out of the producer's or the lessee's share of
the production. Those are usually invisible to the regulators,
to the tax authorities", or to the Department of Natural
Resources as "they are private transactions". Since "the
producer has the right to collect that share of the tax against
the overriding royalty owner and because this 25 percent tax on
net value doesn't actually define a particular tax for a
particular lease, the bill does provide a default formula for
doing that". Were the royalty owner and the producer to agree on
"something else that's fine and the bill recognizes that";
however, in the absence of an agreement, the default formula
would be utilized. CSSB 305's default formula varied slightly
from that proposed in SB 305. This issue is "complicated", but
does not affect a significant amount of production.
11:38:26 AM
Mr. Mintz stated that pages 42 through 54 of the presentation
provided flow charts summarizing "how the new tax regime" being
proposed in CSSB 305 "would work in terms of how a producer
would calculate the production tax".
Page 43
Steps in Tax Calculation
Under CSSB 305(RES)
Page 44
GROSS VALUE OF OIL AND GAS
AS 43.55.150, AS 43.55.900
[This flow chart depicts how the gross value of oil and gas
at each property a producer is producing from in the State
would factor into the producer's Total Statewide Gross
Value of Producer's Oil & Gas.]
Mr. Mintz reiterated that "the main tax" being proposed in CSSB
305 would be a statewide tax. Thus, the first component in the
tax calculation would be the producer's total statewide gross
value of taxable oil and gas, consisting of the total value of
oil and gas produced at each of the producer's properties.
Page 45
LEASE EXPENDITURES
AS 43.55.160(b) - (e)
[This flow chart depicts the manner through which the total of
allowable deductions would be determined]
Mr. Mintz stated that the Lease Expenditures depicted on this
flow chart represented "the deduction part" of the calculation.
This calculation would include exploration, development, and
production costs of activities statewide, "modified by those
concepts of direct, ordinary, and necessary" expenses. Facility
fees, reimbursements, asset sales and other eligible adjustments
would be subtracted to provide the net cost, referred to as the
Adjusted Lease Expenditure amount.
Mr. Mintz revisited the earlier discussion about lease
expenditure credits. These credits would be generated, "when, in
the course of a calendar year", lease expenditures exceeded the
gross value of the producer's production"; that excess could be
carried forward as a credit. He explained that rather than
getting a credit when lease expenditures exceeded the gross
value "within a calendar year, excess expenditures of one month
could be added to the Lease Expenditures of another month, as
depicted in the flow chart. This would provide the total amount
that could be deducted from the Gross Value of Oil and Gas.
Page 46
PRODUCTION TAX VALUE
AS 43.55.160 (a) and (g)
[This flow chart depicts the elements of the tax
calculation, beginning with the producer's Total Gross
Value of Oil and Gas. The Adjusted Lease Expenditure amount
would then be deducted. Any allowances provided to the
producer could also be deducted. The remaining amount is
referred to as the Production Tax Value of Oil and Gas.]
Mr. Mintz reviewed the flowchart. The allowance provided to
producers producing less than 30,000 BOE of oil or gas per day
on a statewide basis. [NOTE: Mr. Mintz inadvertently stated
30,000 barrels per month] could then be deducted from any
taxable value remaining after Adjusted Lease Expenditures were
deducted. The amount remaining would be the Production Tax Value
of Oil and Gas.
Page 47
SEC. 024 TRANSFERABLE TAX CREDITS
AS 43.55.024 (a) and (b)
[One of the transferable tax credits depicted in this flow
chart is the Carried Forward Annual Loss Credit
calculation, which is 25 percent of a producer's Excess
Lease Expenditures in a Calendar Year
The second transferable tax credit is the Qualified Capital
Expenditure Credit. This credit is calculated at 20 percent
of the producer's Qualified Capital Expenditures.]
Mr. Mintz stated that the two types of transferable credits
contained in CSSB 305 could be deducted from the Production Tax
Value of Oil and Gas.
11:41:47 AM
Page 48
TRANSFERABLE TAX CREDIT CERTIFICATES - AS 43.55.024 (d)-(f)
[This flowchart depicts how a producer, with a tax credit,
could receive their Transferable Tax Credit Certificate.
First, the producer would submit an application for the
credit certificate to the Department of Revenue. If
approved by the Department, the certificate would be
issued. The producer could then sell that certificate to
another producer.]
Mr. Mintz reviewed the application process.
11:42:15 AM
Page 49
TIE CREDIT 43.55.024(i)
[This flow chart depicts how non-transferable Transitional
Investment Expenditure credits (TIEs), which are factored
at 20 percent of their value, could be applied as a credit
toward current qualified capital expenditures in a month.
TIE credit usage is restricted, in that the amount of
credit being utilized could amount to no more than one half
of a month's qualified capital expenditures.
Mr. Mintz stated that the non-transferable TIE credits were
associated with the "look-back provision for capital investments
during the previous five years". A producer possessing these
credits could only apply them in a month in which capital
investments were currently being made. The amount of credit
allowed would be restricted to less than one half of the current
investment. The credit would be factored at 20 percent of the
value of the investment.
Page 50
TAX CALCULATION: AS 43.55.011(e), 43.55.024
[As depicted on this flowchart, the "Production Tax Value
of Oil and Gas" would be taxed at 25 percent. This would
provide the Tax Before Credit amount. Then the producer's
own credits would be subtracted. Purchased credit
certificates, capped at 20 percent of the remaining tax,
would then be subtracted. The remaining tax amount would be
the Tax Payable.]
Mr. Mintz stated that this flowchart depicted the tax
calculation in its entirety under the PPT. The amount of a
producer's own credits that could be subtracted from the "Tax
Before Credit" amount would be unlimited except that the
resulting tax amount could not be a negative number. Any credit
certificates utilized by a producer would be limited in any
calendar year to 20 percent of the remaining tax payable.
Page 51
TAX CALCULATION: AS 43.55.011(f)
[This flowchart depicts how the Tax Payable under the
royalty share provisions of the bill would be determined.
The Gross Value at Point of Production of Lessor's Royalty
Share of Oil and Gas would be multiplied by 1.5 percent in
Cook Inlet or five percent tax rate otherwise.]
Mr. Mintz stated that this information would reflect how the
production tax on private lessor royalty share would be
factored. Even through the tax was on the royalty share, the
producer would continue to be responsible for the payment.
Page 52
TAX CALCULATION: AS 43.55.011(g)
[This flowchart reflects that the Progressivity tax
calculation would be activated when ANS West Coast Oil
prices reached a certain level.]
Mr. Mintz specified that the Progressivity element would be
implemented when ANS West Coast barrel prices exceeded $40 a
barrel. State Statutes would contain an "arithmetic formula"
that would calculate the tax rate based on the value of ANS.
Page 53
TAX PAYMENT
AS 43.55.020(e)
[This flowchart reflects that the committee substitute
would require a producer to remit 95 percent of their Tax
Payable on Oil and Gas produced in a Month. The remaining
tax for that and other months in the calendar quarter must
be paid by the end of the next calendar quarter.]
Mr. Mintz reviewed the flowchart.
11:45:34 AM
Mr. Mintz stated that the proposed payment schedule mirrored
that of ELF. For example, 95 percent of the tax due on oil and
gas produced in March would be due at the end of April. Any
remaining balance from the first calendar quarter months of
January, February or March would be due by the end of June,
which would be the end of the second calendar quarter.
Page 54
TAX PAYMENT
PS 43.55.020(f)
[This flowchart depicts that 100 percent of the tax due on
royalty shares in any month must be paid by the end of the
next month.]
Mr. Mintz reviewed the flowchart. This timeframe would mirror
that of existing production tax statutes.
The presentation concluded.
11:46:38 AM
Senator Stedman asked that an implementation plan, to include
insight on any expected implementation difficulties, for the PPT
be provided.
Co-Chair Green agreed.
Mr. Dickinson stated that several implementation issues were
addressed in the Department of Revenue's fiscal note. The
primary concern relative to both SB 305 and CSSB 305 was how to
include "the area of upstream costs which currently do not form
a part of either royalty" into the equation. This component has
not been audited and was unfamiliar territory. Getting this
element "to a point where the State's auditors are comfortable
with what they are doing and what they are seeing will be the
biggest challenge". Disputes would be expected. Downstream
costs, amounting to approximately $1.5 billion, were audited
under ELF; however only "eleven words" pertaining to downstream
costs were contained in current Statute. During the past 30
years, "hundreds of pages of regulations" have been generated in
the effort to interpret the words "…the actual costs of
transportation of that oil or gas".
Mr. Dickinson noted therefore that the effort undertaken in this
bill was to "strike a balance" in this regard. More direction
was given to the Department. However, more regulatory language
would be required to assure the appropriate interpretation.
Mr. Dickinson advised that while "more guidance" was included in
the bill, disputes would still occur. Extra effort was made to
address and further define areas which had been identified as
disputable.
Mr. Dickinson noted that three new positions were requested in
the Department of Revenue's fiscal note. These would be in
addition to three existing but unfilled staff positions.
Additional funded was also requested to let contracts to assist
the Department with the initial rounds of audits and in building
capacity relating to staff training and developing manuals. Such
efforts would be important and necessary to support the effort
to encourage resource investment in the State.
11:50:09 AM
Senator Stedman suggested that another handout be developed to
clarify upstream and downstream expenses in relation to the
point of production. Clearly defining these terms would be
helpful since their usage would be frequent.
Co-Chair Green suggested that a pictorial be developed in that
regard.
Mr. Dickinson noted that an upstream/downstream pictorial was
available and would be provided.
11:51:17 AM
Senator Olson recalled a prior fiscal analysis to indicate that
only three tax auditors and one technician would be required to
support this effort. Such a complicated bill would require more
manpower.
Mr. Dickinson clarified that that fiscal note requested three
new auditors in addition to the current nine production tax
auditors. The "notion of sharing" resources and eliminating
duplicated efforts in the Department of Natural Resources and
the Department of Revenue would also be factored. Further labor
force determinations would be made after the study specified in
the committee substitute was conducted.
Senator Olson asked whether SB 305 included the three positions
in its fiscal analysis. .
Mr. Dickinson understood that the changes made to the committee
substitute had not altered the fiscal note which accompanied SB
305.
Co-Chair Wilken echoed Senator Dyson's earlier remarks
complimenting the information provided in today's presentations.
Co-Chair Green thanked the Committee for their attention to the
details of the bill and the presenters for their information.
Housekeeping regarding the future hearings on the bill was
conducted.
The bill was HELD in Committee.
ADJOURNMENT
Co-Chair Lyda Green adjourned the meeting at 11:54:09 AM.
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