Legislature(2011 - 2012)SENATE FINANCE 532
03/22/2012 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB192 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 192 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
SENATE BILL NO. 192
"An Act relating to the oil and gas production tax;
and providing for an effective date."
9:13:40 AM
Co-Chair Stedman announced that PFC Energy was contracted
by the Legislative Budget and Audit Committee and worked on
behalf of the legislature.
JANAK MAYER, MANAGER, UPSTREAM AND GAS, PFC ENERGY,
presented a PowerPoint Presentation, "Discussion Slides:
Alaska Senate Finance Committee" (March 22, 2012) (copy on
file).
Co-Chair Stedman requested a definition of the word
"upstream" and a brief explanation of what services PFC
Energy provided. Mr. Mayer replied that in the oil and gas
industry "upstream" referred to all activities leading to
the production of oil or gas at the well head. The upstream
sector included exploration, project development, and gas
or oil production.
9:16:21 AM
Mr. Mayer explained that PFC Energy was a global oil and
gas consultancy. He elaborated that the business focused on
all of the "above ground" aspects of the oil and gas
industry and the risks associated with producing oil and
gas for government and industry. The firm operated under
the premise that governments set the terms for oil and gas
development and industry needed to understand how to
operate under the conditions. The company analyzed markets;
commercial, economic, and political risks; and how fiscal
policies impact project development. He furthered that an
integral aspect of PFC Energy's work examined the
relationships between governments, international oil
companies, and nationalized oil companies.
Co-Chair Stedman announced that the presentation would
begin with a historical data review of the dollar value of
Alaska's oil basins adjusted for inflation. He noted that
PFC examined comparisons of analyses made under ACES
(Alaska's Clear and Equitable Share) and re-evaluated and
updated the data according to actual costs and market
prices of oil. The presentation would conclude with an
analysis of SB 192.
9:21:41 AM
Mr. Mayer identified Slide 4, "ANS West Coast Crude
Historical Average Price (Real vs. Nominal)," that depicted
a graph of Alaska crude oil daily production & ANS (Alaska
North Slope) annual average price (real & nominal). He
relayed that a blue dotted line represented Alaskan daily
production by thousands of barrels per day beginning in
1978 until 2011. The red line depicted ANS (Alaska North
Slope) crude oil price (dollars per barrel (bbl.)) in
nominal terms and the yellow line depicted the price in
real terms. He pointed out that the ANS price of $35/bbl.
in 1981 equated to $75/bbl. in 2010.
Mr. Mayer discussed Slide 5, "ANS West Coast Crude
Historical Average Price (Real vs. Nominal)." The graph
portrayed Alaska crude oil daily production and the annual
value of ANS Production (real and nominal) from 1978 to
2011. The ANS crude oil price was multiplied by production
to determine the actual total value over time. He underlined
that in the early years the total values of production were
high until 1988 when the production peaked and began to
steadily decline along with the actual values. In 2000 the
total value began to rise from rising oil prices to a new
high period despite continued decline in production. The
early years marked high value and high production in
contrast to the current climate of high value and low
production.
9:25:29 AM
Mr. Mayer highlighted Slide 6, "ANS West Coast Crude
Historical Average Price (Real vs. Nominal)." The slide
contained a graph that illustrated the split of the real
value (gross value) of production in millions of dollars
between the government (state and federal) and the producers
and the percentage of gross value to producers between 1978
and 2011. He delineated that the percentage to producers was
not the same as the percentage of government take.
Government take represented divisible income; the revenue
after costs. The percentage to producers represented gross
revenue. The percent of gross value to producers was 65 to
80 percent in the mid-eighties and began to fall in 2006 and
sharply decline to under 50 percent in 2008. He attributed
the decline to the enactment of PPT (Petroleum Production
Tax) in 2006 and ACES in 2008. He remarked that in 2008 the
price of oil was consistently high which triggered "high
levels" of progressivity in ACES. The result shifted revenue
away from the producers to government.
9:28:16 AM
Mr. Mayer highlighted Slide 7, "ANS West Coast Crude
Historical Average Price (Real vs Nominal)." The slide
graphed the composition and amount of the state's oil
revenues: NPR-A (National Petroleum Reserve) Royalties,
Rents, Bonuses, CBRF (Constitutional Budget Reserve Fund)
Settlements, Royalty to Public School Trust, Royalty to
Permanent Fund, Conservation Tax, Special Settlements (non-
CBRF), Conservation Surcharge (Hazardous Release), Bonuses,
Rents and Interest, Property Tax, Corporate Income Tax,
Royalties, and Production Tax, from 1978 until 2011. He
noted that the production tax spiked dramatically in 2008
under ACES from increased levels of progressivity that
resulted in amplified state revenues.
Mr. Mayer discussed Slide 8, "ANS West Coast Crude
Historical Average Price (Real vs. Nominal)." The bar graph
depicted the Alaska crude oil daily production and the ANS
annual average price from 2006 to 2010. The totals were
quantified by qualified costs, net value to producers, and
the total government tax royalty. He detailed that in 2006,
costs to producers were relatively low in relation to its
net value. The producer's net value was substantially higher
than total government royalty. In 2008, costs to producers
were a higher percentage of their net value, which declined
while government royalties spiked much higher than producers
net value. The trend of higher costs, declining net value to
producers and higher government take began in 2007 and
continued into 2010 caused by the combination of high oil
prices triggering higher levels of progressivity.
Co-Chair Stedman referred to Slide 5, and determined that
the high annual real value of ANS production was
approximately $40 billion (1980) compared to roughly $20
billion today. Mr. Mayer confirmed.
Co-Chair Stedman added that the annual real value was
approximately $22 billion in 1990. Mr. Mayer confirmed and
added that coincided with the period of ANS peak production
of two million barrels per day. He remarked that today's
real value was the same with declining production, due to
increased government take.
Co-Chair Stedman felt that any discussion on oil taxes
should include the value and prospectively of the Alaska oil
basin.
9:33:06 AM
Senator Thomas cited Slide 8. He asked for clarification of
qualified costs. Mr. Mayer replied that qualified costs were
the costs (defined by the Department of Revenue (DOR))
claimed by the producers.
Senator Thomas queried how the deductions and credits were
represented on the graph. Mr. Mayer responded that the
deductions and credits were reflected in the qualified costs
(depicted as a green portion of the bar) and reduced
government royalty (depicted as a red portion of the bar).
Senator Thomas wondered who shared in the costs. Co-Chair
Stedman replied that the green portion was the industry
cost, and the government royalty was identified in red. He
clarified that the impact of the 20 percent capital
expenditure (capex) and immediate write-off of capital
expenditure shrank the red bar. Mr. Mayer confirmed.
Co-Chair Stedman wondered if the qualified costs offset the
producer's net value (depicted as an orange portion of the
bar) in the analysis. He recalled previous testimony that
industry did not count the net impact of the credits or the
immediate write-off of capital. Mr. Mayer responded that the
qualified cost on the green bar reflected the actual costs
without credits or write-offs. He stressed that the credits
and write-offs were reflected in the net value to the
producer (yellow portion of bar) and reduced the government
royalty depicted in red.
Mr. Mayer communicated that the next set of Slides re-
examined previous analyses of ACES. He pointed to Slide 10,
" "ACES Preserves Investment Climate": What has changed
since 2007?" The Slide depicted the cover page of a
presentation dated October 21, 2007 titled, "ACES Preserves
Investment Climate." Mr. Mayer related that in order to
determine whether ACES had preserved or enabled an
investment climate, it was important to re-examine the
analysis at the inception of ACES and evaluate the
conclusions in retrospect.
9:38:35 AM
Mr. Mayer turned to Slide 11, "Revisiting the Previous
Modeling Work," which contained three condensed slides that
depicted data from the 2007 presentation. The analysis
concluded that ACES preserved an investment climate. The
conclusion was discerned from an analysis of 7 hypothetical
oil field scenarios. A production profile that built-in
capital and operating costs predicated on a certain dollar
per barrel was the basis for the analyses.
Mr. Mayer chose a scenario depicted in the slide as "Field
B." He referred to the table of data at the bottom of the
slide, and noted the highlighted second row. The net present
value was calculated for the various scenarios and all were
positive values with the exception of a heavy oil
development scenario. He interpreted the assumptions of the
analyses. The analyses did not reflect ACES as the program
functions currently but as it was proposed to the
legislature at the time. He revealed the conflicting
assumptions as noted in Slide 12:
Key Assumptions to Consider
•Regime modeled is ACES as proposed, not as
enacted:
- 0.02% progressivity above the $30 level,
not 0.04%
-50% maximum production tax rate, not 75%
•Cost assumptions are much lower than recent
experience suggests:
-$10/bbl. capex and $9/bbl. opex, vs.
-$17/bbl. capex and opex
•Analysis performed from $20 to $100 crude oil
price, with focus on $40 "stress-test" price, and
$60 "base case"
•Assumed production profile is one that will
maximize economic returns for a given field size
-High peak production rate with high decline
rate means most production value occurs
within 10 years
Mr. Mayer noted that scenario "B" calculated the
progressivity rate of .02 percent. The legislature enacted a
rate of .04 percent. In addition, the legislation as
proposed contained a maximum progressivity rate of 50
percent. The legislature enacted a maximum 75 percent
progressivity rate. He added that the hypothetical field
analyses included estimated reserves. Scenario B
characterized a 60 million barrel (MMB) reserve. The high
peak production profile was not consistent with the actual
historical production profile that peaked at a lower
production rate and declined at a much slower and steady
rate.
9:45:13 AM
Mr. Mayer discussed Slide 13, "Benchmarking Government Take
- at $60/bbl." The Slide depicted a chart that compared
international median government take by tax systems. The
chart reported Norway at 81 percent, above Alaska's 70
percent.
Mr. Mayer turned to Slides 14 and 15, "Regime
Competitiveness: Average Government Take." The slides
illustrated a graph of average government take of global
fiscal regimes at $100/bbl. and $140/bbl., represented by
country. He reported that at $100/bbl. Alaska was above
Norway at the high end of the median in new development and
close to Norway in existing production. At $140/bbl. the US
was above Norway and at the high end of most regimes in both
new and existing production. He attributed both outcomes to
the high oil price coupled with progressivity in ACES.
Mr. Mayer cited Slide 16, "ANS West Coast Crude Spot Price -
Last 30 Days." The graph peaked at $128/bbl. in late
February and ended at $122/bbl. March 22, 2012. He observed
that a high oil price environment currently existed.
Mr. Mayer looked at Slide 17, "Field B in Our Model, Under
ACES as Proposed." The slide depicted four graphs and charts
of cash flow analysis and the level and composition of
government take of the "B" scenario from PFC Energy's
current model. He relayed that the results were fairly
similar using the same assumptions that were used when ACES
was proposed at $40/bbl., $60/bbl. and $100/bbl.
9:50:16 AM
Mr. Mayer offered Slide 18, "Field B", Under ACES as
Enacted." The graphs and charts reflected the same "Field B"
scenario under ACES as it was enacted by the legislature.
The analysis was similar at the $40/bbl. level; below the
price where progressivity was applicable. At the level of
$100/bbl. the net present value of a project that was worth
$400 million was 25 percent less with ACES as enacted
because of the higher cap on progressivity. The total
government take rose from 71 percent under ACES as proposed
to 77 percent under ACES as enacted. The total government
take was 84 percent under ACES as enacted and 75 percent
under ACES as proposed at over $200/bbl. price of oil.
Mr. Mayer looked at Slide 19, "'Field B', Under ACES as
Enacted, with $17/bbl. Costs." The graphs depicted the
"Field B" scenario that reflected the costs assumptions used
by PFC Energy's model and reflected the actual current
costs. The net present value (NPV) was negative for a
producer at the $40/bbl. and $60/bbl. but gained substantial
positive value at $100/bbl. The level of government take was
similar to the previous scenarios. The value for the
producer was marginal.
Mr. Mayer discussed Slide 20, "'Field B', Under ACES as
Enacted, with $17/bbl. Costs and Flatter Production
Profile." The Slide depicted the "Field B" scenario under
ACES as enacted with more realistic costs and a historically
accurate production profile in contrast to the ACES as
proposed model where production swiftly peaked and declined
rapidly. At the $40/bbl. and $60/bbl. the net present value
to the producer was negative and only slightly positive at
the $100/bbl.
Senator Egan wondered whether the producer or geologic
factors determined the production profile. Mr. Mayer replied
that geologic and technical limitations determine the
production profile. The producer would prefer to produce an
oil field as quickly as possible to maximize its net present
value (NPV). He furthered that PFC's production profile was
modeled after actual production profiles.
9:55:36 AM
Co-Chair Stedman wondered if there was any link between the
government take and the net present value. He cited the
chart on slide 20, which indicated that at approximately
$80/bbl. the government take was 75 percent and the NPV was
zero. He remarked that in previous HB 192 testimony the
state was recommended to target 75 percent government take
on current production and less than that for incremental
production. Mr. Mayer replied that it was coincidental that
the government take was 75 percent at $80/bbl. The various
outcomes were a result of a coincidence of forces
interacting rather than specific design. He elaborated that
there was an interaction of forces that moved in opposite
directions. He pointed out that government take was very
high when oil prices were low. He opined that was due to the
"regressive nature of the royalty." He cited the bottom
graph on Slide 20, which illustrated that at $40/bbl. it
would take more than double the divisible income to pay the
royalty, even after the strongly negative production tax of
more than 200 percent of the total. He believed that the tax
system should better incentivize economically challenged
projects.
9:58:28 AM
Co-Chair Stedman surmised that the state experienced a much
different outcome with the enacted ACES system than ACES as
proposed after cost and price adjustments. Mr. Mayer
confirmed.
Mr. Mayer addressed Slide 22, "CSSB 192 Using ACES Minimum
PTV (Existing Producer)" and Slide 23," CSSB 192 Using 10%
of Revenues for Minimum PTV(Existing Producer)," that
examined the impact of the revised production tax floor
proposed in SB 192. The Slides contained bar graphs and
charts that depicted what government take and economic value
was for an existing producer at 200,000/bbl. per day. Slide
22 presented the scenario under ACES. He explained that
slide 23 examined the production tax value (PTV) established
in SB 192, set at 10 percent of gross revenue as the minimum
level of total production tax value. The previous
production tax minimum was set at $20. He showed that with
the minimum proposed in SB 192 at $40/bbl., the government
take increased to 74 percent. The result under the ACES
minimum was 72 percent. He opined that the fixed percent
royalty system was regressive and was challenging at low oil
prices. He believed that the proposed minimum exacerbated
the high government take at low oil prices, similar to ACES
without the floor, due to the fixed royalty rates. He
considered the impact on marginal projects at low oil prices
problematic.
10:03:40 AM
Mr. Mayer discussed methods of incentivizing new oil
production. He turned to Slide 25:
ACES - A Harvest Area Regime, Not a Growth Regime
ACES appears to work well as a "harvest" regime
-Existing mature fields remain profitable,
including capital work required to achieve ~6%
decline (renewal capex) [capex - capital
expenditure]
-Maximum 'rent' extracted from a declining
production base is captured for the state
•ACES inhibits the development of new projects and
resources that might help stem or even reverse the
decline
-ACES is not progressive with regard to costs, so
high government take applies even to very high
cost projects
-Existing system of capital credits etc. appears
to do more to encourage 'renewal capex' than it
does new production spending
-Progressivity can have a major detrimental impact
on breakeven prices for high-cost projects at
current oil prices
Mr. Mayer observed that production from new fields tell a
different story from ACES. New production economics were
hampered by high costs for new production. He noted that the
graph (contained in the slide) depicted the NPV at a range
of prices and illustrated that as progressivity kicked in at
high oil prices the effect reduced the NPV to oil producers
and captured the value for the government on new
development. The impact increased the breakeven oil price
for producers and decreased or eliminated the economic
viability on marginal projects.
Mr. Mayer spoke to ways of incentivizing new production,
distinct from base production. Government take on base
production and new developments could simply be lowered. He
cautioned that the more changes to the system as a whole,
both new and base production, the less change can occur
specifically for new production. The government would lose a
large amount of economic "rent" on base production. Without
the distinction between base production and new development
in the tax system, incentives targeted for new development
would be more limited. Conversely, the benefit of an across
the board approach was in the ease of administering the tax
system rather than a more complex tax system that
distinguished between new and base production. In Alaska
most new production would come from new investment in
existing areas, which made distinguishing between new and
existing production difficult. The choice was a system
designed for administrative simplicity reducing overall
government take, by bracketing, reduced progressivity, and
lower caps on progressivity, or targeted new development via
specific tax measures.
10:09:58 AM
Senator Thomas asked whether ACES caused the lack of
reinvestment by creating a harvest regime. He observed that
the oil decline occurred for the past 18 years. Mr. Mayer
did not feel that ACES created the problem and acknowledged
that the oil decline and investment climate occurred
sometime before ACES. He explained that ACES could be viewed
as a fiscal regime that maximized declining production. He
cautioned that in addition to maximizing returns, new
production especially in high cost environments needed to be
incentivized.
Senator Thomas suggested that a harvest regime hampered new
oil development. Mr. Mayer agreed and clarified that new
development, either inside or far outside of existing fields
were more expensive, difficult, and technologically
challenging to develop. He exemplified development of
reservoirs that required horizontal drilling, and heavy, or
viscous oil. Technology and costs can inhibit development;
similarly high progressivity and government take on high
cost new developments impede progress.
Senator McGuire observed that capital credits were equally
valid for renewal or new production and questioned why
developers chose to use them only for renewal. She shared
that she voted for ACES because she believed that capital
credits incentivized production for development in a costly
environment like the Artic. She was troubled that new jobs
were not created and oil producers were only redeeming
capital credits as renewals. Mr. Mayer responded that some
of the renewal capex was non-discretionary. The capital
expenditure was crucial infrastructure maintenance in order
to maintain production. He reiterated that the capital
improvement work that maintained a 6 percent decline was
profitable for existing production. He added that capital
credits do improve the economics of new development, but was
not sufficient in an environment of high government take and
high costs.
10:19:03 AM
AT EASE
10:27:13 AM
RECONVENED
10:28:06 AM
Mr. Mayer continued his response. He stressed the importance
of understanding new investment versus base production. He
explained that new investment was not just investment in new
fields. New investment included capital investment using
costly new technologies in existing infrastructures by
existing producers. New investment required "significant"
new capital in a cost challenged environment. The producer
must attract investment capital based on the viability of
the project in a competitive international business
environment. He declared that his examination of
incentivizing new production did not include a tax system
that would distinguish between new and existing production.
All of the proposals to incentivize new production were
fundamentally compatible with the system of administration
used for ACES. He avoided a system that used the "mechanics
of production tax itself" as a basis to distinguish between
the production streams because of the difficulty and
complexity to administer. He reiterated that a tax system
that distinguished between different production streams
created a much greater level of complexity. The system
required multiple tax returns and precise accounting among
separate production streams.
10:33:02 AM
Mr. Mayer continued to explain that a system with different
base rates required accounting and sophisticated auditing
for new volumes of production and allocating its precise
costs. Complex accounting was required to prevent an oil
company from taking advantage of the more favorable terms
for new production by allocating more costs to the new
production stream. In contrast, a tax system that provided
an allowance through the production tax was much easier to
administer.
Mr. Mayer began his analyses of the SB 192's provisions to
incentivize new production. He related that the allowance
(an allowance on production that in any given year was above
the level of production from the previous year) for new
production only incentivized production in any given year
that was incremental to the previous year's production. A
production threshold was determined in order to demonstrate
the impacts of the allowance. He pointed to Slide 26:
"New Oil Allowance: Incremental Production on a
Declining Base."
Central to understanding the impact of the
"allowance for 'new oil'" is an understanding of
the impact of new source production on a company's
total production volumes, when that new source
production is added to a declining base portfolio.
o The charts at the bottom assumed a 6 percent
decline rate for an existing North Slope
producer currently producing 200mb/d, and
examine hypothetical new source projects that
peak at 10mb/d, 50mb/d and 100mb/d
respectively (on a working interest basis.)
o Given the pace at which such projects
typically reach peak production, only the 100
mb/d peak production new source development
is actually capable of adding production that
is incremental to prior years' volumes.
The slide included 3 graphs that illustrated the allowance
at 10mb/d (thousand barrels per day), 50mb/d, and 100mb/d
peak for new source projects.
Mr. Mayer informed the committee that the SB192 allowance
did not have an impact on new production as defined in the
bill at 10mb/d and 50mb/d. The 100mb/d projection triggered
the allowance in SB192 and revealed a significant impact on
the decline curve.
10:37:34 AM
Senator Thomas cited the middle graph that represented
50mb/d peak new source projects. He deduced that every four
or five years 50 mb/d of new development was needed just to
flatten the decline curve of a 200mb/d field. Three times
the amount of the 200mb/d field of incremental production
was needed for a 600mb/d field to offset the 6 percent
decline for each 4 or 5 year period. He estimated that over
a 12 year period a 600mb/d field would need 450 mb/d of
incremental production to produce the offset. He remembered
from previous testimony that a $25 billion investment was
needed to maintain that level of incremental production. Mr.
Mayer guessed that the calculations seemed reasonable. He
referred to previous testimony (Senate Finance Committee,
March 21, 2012, 1:10PM) by Dale Pittman (Vice President,
Production, ExxonMobil Alaska) and reported that he made a
similar point. The Oooguruk and Nikaltchug oil fields came
on line in recent years and flattened out the decline curve.
Equivalent new developments would be needed each year to
maintain a flat production decline.
Mr. Mayer highlighted Slide 27:
"A Hypothetical 100 mb/d (Working Interest) Development."
• A new source development that produced 100 mb/d at
peak for a working interest partner would be a very
significant new development. By way of comparison,
Kuparak, the second largest field in North America,
peaked at ~320 mb/d gross production
- This represented working interest production to
ConocoPhillips (the operator and majority
shareholder) of 170 mbo/d
- Kuparak took 11 years (from 1981 to 1992) to
reach this peak level of production
• Since it would take a development on the scale of 100
mb/d (working interest) to achieve "new oil" for an
existing producer under the terms of the amendment, a
development of this size has been modeled in the
following analysis
- A 7 year ramp-up to peak production has been
assumed
- Such a development would likely eclipse today's
production from Kuparak (122 mb/d gross, 66mb/d
working interest to the majority shareholder)
- It is important to note that this is a
significantly more aggressive new-source
production profile than is currently foreseen in
recent statements by the major operators on their
current development pipelines, even in the most
optimistic circumstances
Two additional graphs illustrated Conoco Phillips working
interest in the Kuparak production profile and the
hypothetical 100mb/d working interest development production
profile.
10:42:26 AM
Mr. Mayer looked at Slide 28:
Assumptions
•The following analysis assumes
-A 6% base portfolio decline, in the case of a
producer currently producing 200 mb/d
-Costs for the base production portfolio of:
•$12/ flowing bbl. operating expenditure
•$5/ flowing bbl. maintenance capital
expenditure
-Costs for the 100 mb/d (working interest) New
Development project of:
•$13/ flowing bbl. operating expenditure
•$13/bbl. reserves development capital
expenditure
•$1/ flowing bbl. maintenance capital
expenditure
-These costs are deliberately somewhat lower than the
previously referenced 10 mb/d new development, since
the hypothetical development modeled is significantly
larger, and thus likely to have somewhat lower costs on
a $/bbl. basis
Mr. Mayer identified Slide 29, "CSSB 192 Excluding New Oil
Allowance (Existing Producer)." The Slide depicted three bar
graphs and a chart that represented the cash flow analysis
of 100mb/d new development field without the allowance. The
government take ranged from 74 percent at $100/bbl. to 79
percent at $230/bbl. He turned to Slide 30, "CSSB 192
Including $10 New Oil Allowance Over 1 Year (Existing
Producer)." He noted that the application of the $10
allowance applied in a single year on production over and
above last year's production, had no effect on the 100mb/d
scenario.
10:46:18 AM
Mr. Mayer examined the allowance with different variables.
He turned to Slide 31, "CSSB 192 Including $20 New Oil
Allowance Over 7 Years (Existing Producer)." The Slide
depicted through graphs and a chart the cash flow analysis
of a 100 mb/d new development with a $20/bbl. allowance
applied over 7 years. He identified a slight increase in the
NPV for a producer and virtually no change in government
take. He looked at Slide 32, "CSSB 192 Including $60 New Oil
Allowance Over 7 Years (Existing Producer)." The slide
illustrated the cash flow analysis of a 100mb/d new
development coupled with a $60/bbl. allowance applied over 7
years. He relayed that a greater increase in NPV occurred
but the government take remained about the same. The impact
of incremental production was slight because the allowance
only applied to production over the decline base.
Incremental production was a relatively small amount
compared to the base amount.
Co-Chair Hoffman noticed that the presentation did not
contain slides with data for new producers, and wondered
why. Mr. Mayer replied that the data showed only a
marginally greater effect and felt that it was superfluous
to include.
10:50:09 AM
Mr. Mayer directed attention to Slide 34, "CSSB 192
Including Tax Holiday Based on 3 Year Rolling Decline
(Existing Producer)." The slide used the existing format
from the previous slides to illustrate the impact of a tax
holiday based for an existing producer. He outlined that the
proposal was based on incentivizing production above a given
level. The target level was set by averaging the decline
rate of a producer over 3 years. Any amount of production
over the average decline rate counted as new production and
received an exclusion from production tax for one year. He
cautioned that the tax holiday was problematic. The
exclusion was only applicable for one year and was minimal
when compared to the producer's investment in new
production.
SB 192 was HEARD and HELD in committee for further
consideration.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 192 102107 ACES SenResHouseOilGasJointHearing.pdf |
SFIN 3/22/2012 9:00:00 AM |
SB 192 |
| SB 192 032212 PFC Energy Presentation.pdf |
SFIN 3/22/2012 9:00:00 AM |
SB 192 |