Legislature(2011 - 2012)SENATE FINANCE 532
04/02/2012 01:00 PM Senate FINANCE
| Audio | Topic |
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| Start | |
| SB192 |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 192 | TELECONFERENCED | |
| + | TELECONFERENCED |
SB 192 was HEARD and HELD in committee for further
consideration.
1:07:22 PM
SENATE BILL NO. 192
"An Act relating to the oil and gas production tax; and
providing for an effective date."
TONY REINSCH, SENIOR DIRECTOR, UPSTREAM AND GAS, PFC ENERGY,
CONTRACT, LEGISLATIVE BUDGET AND AUDIT COMMITTEE, related
that PFC Energy were consultants for large global oil and
gas producers, major independents, national oil companies,
governments, and regulatory agencies. PFC Energy focused on
above ground challenges to the oil and gas industry advising
on strategy, policy, regulation, and legislation.
JANAK MAYER, MANAGER, UPSTREAM AND GAS, PFC ENERGY,
CONTRACT, LEGISLATIVE BUDGET AND AUDIT COMMITTEE, provided
members with a presentation, "Discussion Slides: Senate
Finance Committee," April 2, 2012 (copy on file). He
communicated that the presentation examined the tax credits
available to producers under Alaska's Clear and Equitable
Share (ACES).
1:10:15 PM
He outlined the tax credits available under ACES, Slide 2:
Tax Credits Under ACES
· Qualified Capital Expenditures Credit of 20 percent for
qualified capital expenditures, including exploration
· Carried-Forward Annual Loss Credit of 25 percent for
excess lease expenditures (where Production Tax
liability is insufficient to deduct costs)
· Well Lease Expenditure Credit of 40 percent for Well
Lease Expenditures (Intangible Drilling Costs) below
North Slope
· Alternative Credit for Exploration of 30 percent for
Exploration expenditures for wells more than 3 miles
outside an existing area (if outside Cook Inlet)
· Alternative Credit for Exploration of 40 percent for
Exploration expenditures for wells more than 25 miles
outside an existing area (10 miles in Cook Inlet)
· Cook Inlet Jack Up Rig of up to 100 percent for the
First 3 unaffiliated wells drilled by same jack-up rig
in Cook Inlet (now unavailable)
· Education Credit; a maximum of $5 million for cash
donations to educational institutions.
· Transitional Investment Credit of 20 percent for
Expenses before March 31 2006 (pre-PPT)
· Middle Earth Credit of $6 million for production below
North Slope and outside Cook Inlet (Expires 2016)
· Small Producer Credit of $12 million for producers with
less than 50 mb/d average production (expires 2016)
Mr. Mayer observed that small producers engaged in
challenging projects yielding marginal economic returns
benefitted most from the small producer credit. He noted
that the first five credits were relevant to PFC's ACES
discussion.
He related that the discussion would explore the
difficulties of incentivizing exploration and the
interaction between the exploration credits coupled with
progressivity under the current fiscal system. He would
further examine the interaction of progressivity with
exploration credits by removing progressivity from the
production tax and imposing instead, a progressive gross
severance tax. He would conclude with analysis of capital
credits and the return on investments by the state.
1:15:07 PM
Mr. Mayer offered a brief summary of the credits analyzed in
his presentation; capital credits and the alternative
credits for exploration. He explained that there were two
key components to ACES credits: credits claimed against tax
liability by current producers that accounted as a reduction
in state revenue and credits refunded to producers with no
tax liability that accounted as expenditure by the state. He
referred to Slide 3, "Total Impact of Credits," which
depicted a graph displaying the total impacts of both types
of credits to the state: credits claimed against tax
liability and credits refunded. The impacts of credits
claimed against tax liability varied from $400 million in
2009 to $475 million in 2013. The total cost to the state
combining both tax credits as lost revenue and expenditures
was approximately $800 million per year from 2009 to 2013.
Mr. Mayer noted that the qualified capital expenditure
credit accounted for $585 million in FY 2010 rising to $640
million in FY 2011. In contrast, the exploration credit
amounted to $41 million in FY 2010 and $13 million in
FY2011. He remarked that the exploration credits represented
a relatively small portion of the pie.
Mr. Reinsch turned to Slide 5:
Content
•Recent Trends in Exploration Activity and Basin Focus
•Credits and Incentives: Lessons from the Past
-National Energy Program (Canada)
-Norwegian Continental Shelf (Norway)
•Development Cycle Time: Incenting the Required
Activities
Mr. Reinsch announced that he would address the issues of
exploration credits and incentivizing exploration in other
countries, report on recent trends in explorations, review
credits and incentives in light of government positions on
exploration risks and discuss development cycles.
Mr. Reinsch remarked that the 1990's "set the stage" for a
period of development capital expenditure through oil
exploration and resource development. During the late
nineties through approximately 2008, capital expenditure
funds were channeled into production growth and major
resource development projects such as the Canadian oils
sands and large scale liquefied natural gas projects in
Qatar. He noted a recent rebound in global exploration
spending.
Mr. Reinsch turned to Slide 6, "Rebound in Exploration
Spending" that graphed total worldwide exploration spending
by global oil companies from 1989 through 2011. He relayed
that capital expenditure levels were flat in the first half
of the 2000's. In 2007, a sharp increase in exploration
expenditures occurred. Companies such as Statoil, Shell and
British Petroleum (BP) significantly increased capital
expenditures to capture new resource development.
1:22:54 PM
Mr. Reinsch cited Slide 7:
Trend in Worldwide Exploration: Global Players
•Exploration spending by many of the Global Players
accelerated sharply in 2005-2006 as focus shifted to
restocking the portfolio of development projects
•Statoil (North Sea) and Shell (Asia, North America)
were early movers, quadrupling exploration spending
since 2004
•The growth represents real activity gains,
substantially outpacing the Exploration & Appraisal
(E&A) Index
The slide also charted the net undeveloped properties of the
global oil companies. He observed that Shell was the leader
among global oil companies in securing any available lands
for development. He explained that the oil companies
predicted very limited access to new land for exploration.
National oil companies were strengthening control over its
resource base and severely restricting the global companies'
exploration activity. The majority of the available acreage
was located in Asia and Africa, including onshore and
offshore sites. He commented that Shell and Exxon Mobil were
dominant in North American holdings.
Mr. Reinsch declared that the global oil companies
strategically accelerated exploration spending in recent
years. He identified the regions where the majority of the
global oil industry was expending capital on exploration,
mapped on Slide 8, "Selected Global Players: Regions of
Exploration Focus." He described the region as the Atlantic
Margin Basins extending from the deep water in the Gulf of
Mexico to Brazil, West Africa coastal deep water, and the
Equatorial margin comprising of Sierra Leon, Cote d'Ivoire,
and Ghana. He added that renewed emphasis in the Arctic had
occurred in deep water offshore of Norway, the Barents Sea,
Northern Russia, and Alaska. He remarked that due to greater
control by national oil companies, the Middle East with the
exception of Qatar was no longer a growth driver in industry
exploration.
Mr. Reinsch turned to Slide 9:
Trend in International Exploration: Independents
The International Independents are a more disparate
group when it comes to exploration activity:
•Some, like Anadarko, have been material
exploration players through the last decade;
•Some, like BG and Apache, have aggressively grown
their exploration activities through the past
decade;
•Others, like Occidental and Noble, have focused
on development activity in a small number of play
areas
•Exploration spending by Anadarko, BG, and Apache
has hovered around the $1.3-1.5 billion mark for
the last few years, high for the Indies and ~60%
that of the smaller Global Players
1:28:15 PM
Mr. Reinsch stated that besides the independent's interest
in the Atlantic margin they are uniquely involved in opening
new frontier areas. He pointed to Slide 10:
Selected International Players: Regions of Exploration
Focus
The Independents are similarly positioned in the
US/Canada onshore resource plays (oil sands, shale
gas. Shale oil), and the deepwater plays of the
Atlantic Basin
• The Independents are also at the forefront of new
basin development, such as the Equatorial Margin,
East Africa Deep water, South America "North Tier"
deep water play, Argentina shale gas, and Lake
Albert basin (Uganda)
• The Independents are not as prominent in the high
cost, high risk exploration opportunities in the
Arctic offshore
Mr. Reinsch directed attention to Slide 11, "IOC Growth
Centered on Successful "New Frontiers"…." The graph
displayed the projected growth in new frontier areas of
development through 2010 and indicated a decline in
conventional areas of development.
Mr. Reinsch discussed the "Redirection of Free Cash Flow"
depicted on Slide 12. He reported that the focus on new
frontiers in nonconventional development was financed by a
redirection of free cash flow. He described a reallocation
of capital from maturing areas in Africa, Asia Pacific, and
Europe to the United States and Canada.
Mr. Reinsch moved to Slide 14:
Exploration and Government Risk Taking
•By and large, Governments have refrained from engaging
in the business of upstream risk
-In emerging basins, nascent National Oil Companies
(NOCs) will usually have "back-in provisions" within
production sharing contracts, allowing entry into
development projects as an equity participant at the
point of sanction. Are prohibited from engaging in
exploration activity
-In more mature basins, the NOC may engage fully from
license award to production (Petora in Norway, ONGC in
India, PDVSA in Venezuela) assuming it has internalized
the necessary degree of technical sophistication and
dry-hole tolerance
•Exploration credits/rebates are, in essence, a direct
engagement by the government in exploration risk. As
such, they have been used sparingly outside of the
context of the tax and royalty regime.
Mr. Reinch offered that large amounts of capital were
invested by oil companies without any returns. Governments
are generally stewards of the resource and not comfortable
with risk. He added that governments engaged in exploration
risk through exploration credits or incentives by reduction
in tax liability. Governments rarely extend exploration
credits to non-taxable entities. Governments tend to adopt
incentives and credits to broaden resource development where
production was in decline.
1:35:42 PM
Senator Thomas questioned whether a direct relationship
existed between exploration credits and up front risk in
investments in high cost areas such as Arctic and off-shore.
Mr. Reinsch responded that the opposite was true. He
elucidated that the exploration credit represented a small
portion of incentives offered by governments. Capital
credits represented 80 percent of government credits.
Exploration credits were found in areas where well costs
were low. The credits had a persuasive impact with little
risk by the government. Deep water investments with high
well costs carried significant risk for governments.
Mr. Reinsch cited Slide 15:
Canada's National Energy Program: An Experiment in
Intervention Gone Awry
•The NEP was introduced to both enhance Canadian
ownership in Upstream activities [exploration and
recovery of oil and natural gas], and to accelerate the
discovery and development of domestic resources to
enhance security of supply and support energy subsidies
to domestic consumers.
The slide included a chart that indicated the types of
incentives, credits, and risk sharing activities offered
through the National Energy Program (NEP).
Mr. Reinsch related that the program failed because the
market turned against the National Energy Program (NEP). The
program was not considered favorable to the business cycle.
He opined that the best government incentives were "robust
to the business cycle." The program was intended to
"Canadianize" ownership in the upstream activities and to
address decline. Oil production was in decline and oil
prices were rising. He highlighted the program. The
structure allowed greater incentives to Canadian companies.
"Exotic" activity received greater incentives. Drilling
deeper wells or farther from existing wells was awarded with
more incentives. The result was to drive a typically
efficient industry to place more effort into marginal areas.
1:42:37 PM
Mr. Reinsch discussed Slide 16:
National Energy Program (Canada) and Exploration
Incentives
•NEP introduced substantial distortions into the E&P
decision making process. In particular, incented
Upstream activity towards less prospective and higher
cost areas, and introduced "artificial" demand for
Upstream services
•Drilling costs (seismic, rigs, etc.) accelerated
rapidly as demand soared in new and unsupported
exploration environments
•Many companies were effectively "drilling for PIP
grants" with commercial discoveries representing the
Failure case
Canadian Arctic Atlantic Offshore
Costs
1966-1970 $4.3 mm $1.2 mm
1971-1975 $3.6 mm $3.8 mm
1976-1980 $24.4 mm $22.4 mm
1981-1985 $63.2 mm $45.8 mm
1986-1990 $44.2 mm $20.5 mm
Mr. Reinsch noted the chart on slide 16 and observed that
the program ended in 1985 in response to declining oil
prices. He pointed out that the program "incented" companies
to drill away from the established infrastructure into
frontier areas. The Petroleum Incentive Payments (PIP)
grants incentivized "drilling for nothing" or speculative
drilling.
Mr. Reinsch reviewed Slide 17:
Canada's National Energy Program
· The decline in crude prices in the mid-1980s forced the
withdrawal of virtually all aspects of the NEP
· Alberta:
-PIP grants replaced by Royalty Tax Credits (75% rising
to 90% with maximum credit per well)
-Exploration Incentives restructured as either:
12 month Royalty holiday on eligible wells to a
maximum per well;
Royalty exemption on cumulative production, linked
to well depth and location
Exploration Drilling Incentive Program: 50% credit
set off against subsequent royalties
-Moved away from credits/rebates outside of the royalty
and tax environment => reward success, not simply
effort.
· Federal:
-PetroCanada back-in eliminated;
-Royalty linked to "payout" of development
1% royalty rising to 5% at rate of 1% per 18
months
Royalty jumps to 30% net CF after Payout
-Exploration Tax Credit of 25% for well costs above
$5 mm, used to reduce Federal Income Tax. If not
taxable => direct refund of up to 40% of non-
utilized credit
1:48:11 PM
Mr. Reinsch referred to Norway's oil and gas industry, which
was similar in nature to Alaska, Slide 18:
Norwegian Continental Shelf: Incentives in a Modern
Context
•Oil production in Norway peaked in 2001 and has
fallen by ~45% since then. Growth in gas
production allowed BOE volumes to rise till 2004,
and have been in decline ever since
•Fiscal system provides incentives for exploration
activity
Base Production Tax - 25%
•Applied to net income from Petroleum activities
Special Tax - 50%
•Applied to net income generated from petroleum
activities, to capture resource rent above "normal
profits"
Government Investment - Petoro
•Engages in exploration and development activity
as full equity partner; pays share of costs and
receives 100% of revenue from its working interest
position
Exploration Incentives - 78%
•Applies to companies in non-taxable position.
Since government allows uplift of loss carry-
forward at a risk-free interest rate, it is
indifferent between refund or offset
•Introduced to expand the competitor landscape,
bringing in new Upstream companies
License access
•All companies require pre-approval for financial,
technical, and operating capability prior to
bidding on a License in the Norwegian Continental
Shelf (NCS)
1:50:17 PM
Mr. Reinsch predicted continued decline in Norwegian oil and
gas production. He explained that the special tax was levied
on income over and above normal profit margins. He
identified Petoro as the Norwegian government's equity firm
for oil and gas development. He detailed that the Norwegian
license requirements were arduous, which was not the case in
Alaska. He observed that the process was straightforward in
Alaska. Conversely, Norway's ability to rigorously screen
license applicants was the foundation for their incentive
program.
1:54:44 PM
Mr. Reinsch referenced Slide 20, "Cycle Time to Production,"
that contained a graph illustrating the project cycle time
from discovery to commissioning based on the type of
development project. He revealed that directing incentives
to produce the desired outcome was challenging, and commonly
referred to as "tool and target."
Mr. Reinsch outlined the various types of oil development
projects and its project cycle time.
· Integrated Mined Oil Sands are long term development
projects expected to take 10 or more years to establish
due to protracted regulatory process and the scope of
the project.
· Off Shore Frontier developments are areas offshore that
do not have access to established infrastructure and
take 6 to 8 years to develop.
· Onshore Frontier projects are land based areas without
access to infrastructure such as Uganda. Cycle times
are 4 to 6 years.
· Offshore Tieback Wells connect new discoveries to
existing infrastructure and shorten cycle time to 3 to
5 years. The majority of time to reach production was
spent on appraising project for financial viability.
· Enhanced Oil Recovery (EOR) Onshore areas are mature
oil fields with infrastructure in place; only testing
was necessary. Project cycle time was very short.
Mr. Reinsch judged that the immediate challenge for Alaska
lied in the medium three to five year time frame to increase
the volume of oil flowing into the pipeline to a level that
maintained government revenues. He concluded that mapping
tools to targets was an important factor in developing
exploration incentives for Alaska.
2:01:27 PM
Co-Chair Stedman asked for clarification on the licensing
requirements in Alaska compared to Norway. Mr. Reinsch
commented that Alaska does not screen the applicants for
financial, operational, or technical capabilities. Norway's
restrictive licensing disallowed any entity from bidding on
a license until pre-approved for financial, technical, and
operating capability.
Mr. Mayer furthered that incentives worked, but not
necessarily in the way that the government intended. He
exemplified Canada's failed attempt to incentivize
exploration that led to speculative and non-productive
predatory drilling practices. He stated that Norway
controlled that outcome by ensuring the applicant was a
credible producer with the intent to produce. A well-
structured incentive program encouraged desired outcomes.
2:05:10 PM
Senator Thomas relayed that the Albertan government in
Canada had raised taxes on oil production around the same
time that ACES was enacted. Production in Alberta began to
decline; subsequently taxes were decreased and oil
production increased. He wondered if that scenario was
reflected in the previous slides and was an accurate
assessment. Mr. Reinsch clarified that the presentation
focused on Canadian's National Energy Program in the 1980's.
The Alberta scenario happened in recent years and
represented a miscalculation of tools and timing. He
explained that the Alberta government had implemented a
"harvest fiscal system." Alberta believed that oil
production was nearing the end so the government acted to
increase its share of the revenue. Simultaneously, the
industry was ready to launch new production opportunities
employing new technologies such as horizontal drilling and
multiple stage fracturing of wells in conventional fields.
He elaborated that the Alberta government failed to
recognize the impact the new technologies could have on
reversing the long-term decline in conventional production.
The industry responded by moving investments to new horizons
in British Columbia and Saskatchewan in shale oil. Alberta
soon realized that the industry needed support in fostering
new technologies in traditional fields. The government
redirected its tax structure to incentivize exploration
utilizing the emerging technologies.
2:10:20 PM
Co-Chair Stedman announced that the Department of Revenue
had declined to participate in the policy discussion
regarding tax credits.
2:11:04 PM
AT EASE
2:19:37 PM
RECONVENED
Mr. Mayer concluded that the lesson from the Canadian and
Norwegian scenarios showed that high levels of exploration
credits without strict evaluation of the producer resulted
in a boom, either in speculative exploration or exploration
activity merely to obtain the credit. He declared that under
ACES, exploration credits coupled with progressivity
provided a high level of effective government support for
exploration activity.
Mr. Mayer reviewed the graph on Slide 21, "High Levels of
Exploration Support under ACES." The graph depicted crude
oil prices in the bottom axis and the left axis represented
percentages of after tax effective government exploration
contribution based on a 40 percent credit. He demonstrated
how the exploration incentive tax structure worked combined
with progressivity to the point where it benefited the
producer to drill "dry holes." He began at $55 per barrel
(BBL.) price of oil (progressivity was not applicable)
exemplifying an existing producer with existing production
tax liability. The producer spent $100 million on an
exploration project that resulted in a dry hole. The
applicable 25 percent production tax credit immediately
reduced $25 million from the tax liability paired with $40
million in exploration credits, which resulted in an after
cash flow liability of $35 million for the producer, out of
the $100 million investment. The state reduced the producers
risk for exploration by 65 percent.
2:24:34 PM
Mr. Mayer furthered that the effects were multiplied with
progressivity. He exemplified that at $110/bbl. an existing
producer that invested $100 million in exploration activity
receiving the same credits coupled with progressivity
incurred a $10 million dollar cash flow liability. The state
bore 90 percent of the burden in reduced revenue from
production tax and expenditure with exploration credits. He
maintained that at $215/bbl. the after tax cash flow
liability on $100 million spent on exploration
(progressivity was capped at 75 percent) was zero. The
state's contribution was 100 percent. At the unprecedented
price of the mid $200/bbl., a producer would receive an
after tax cash flow benefit. He warned that the result
encouraged a producer "to drill as many dry holes as
possible."
Co-Chair Stedman wondered how the immediate write-off of
capital expenditure influenced the tax structure and what
resulted from reducing the 40 percent credit to 20 percent.
Mr. Mayer answered that if the existing structure of ACES
was maintained with a 20 percent credit, the 75 percent cap
in progressivity would prevent a 90 to 100 percent
contribution by the state at any price for oil. He added
that the immediate write-off of capital expenditures against
production liability enabled the high levels of exploration
support when coupled with the 40 percent exploration credit.
2:28:36 PM
Co-Chair Stedman observed that the current structure could
drive the state's production tax value negative. He recalled
that the same conclusion was pointed out by Dr. Pedro Van
Muer in previous testimony ["Policy Options for Alaska Oil
and Gas" Senate Finance Committee presentation, February 12
- 13, 2012 (copy on file).] Mr. Mayer agreed that negative
value was one of the unintended side effects of the
inclusion of progressivity in the production tax structure
combined with high levels of exploration credits. He noted
that a severance tax option eliminated the unintended
consequences of excessively high support at high oil prices.
As progressivity increased it raised the production tax,
which qualified for immediate write-off of capital costs. He
exemplified progressivity levied on gross production (at 25
percent) instead of a profit based production tax. Costs
were no longer relevant for the gross progressive
calculation. Costs against the immediate write down of
capital were accrued on a flat 25 percent production tax.
The tax remained at 25 percent regardless of how high the
price of oil was. The after tax effect on government
contribution with a 40 percent exploration credit at
$100/bbl. of oil was 60 percent. The effect was further
reduced to 45 percent if the exploration tax was reduced to
20 percent. He added that another unintended consequence of
net progressivity within the current structure was on
potential large scale gas development. The average prices
paid on a BTU (British thermal unit) equivalent could
further decrease revenues on existing oil production by
diluting production tax value with a lower value product. He
noted that SB 192 attempted to "decouple"; accounting of oil
and gas into separate streams of production, in order to
remedy the inclusion of progressivity in the production tax.
2:32:25 PM
Co-Chair Stedman asked what the downside of progressivity
from net to gross was. Mr. Mayer stated that the only
principle downside was the transition time of the current
fiscal system to convert and administer a new tax structure.
He opined that a net severance tax system was less
complicated than the existing structure. He furthered that
it was far less complicated than the existing system
combined with decoupling as a way to remedy progressivity.
Mr. Mayer directed attention to capital credits. He reminded
the committee that capital credit was a 20 percent credit on
qualified capital expenditures as an immediate write off of
capital. He explained that the timing of credits and cash
flow; the ability to immediately expense or claim capital
credits in the current year to lessen the impact on the
producers cash flow was built into ACES and preceding tax
structures. The credit structure enabled a high government
take but mitigated the cash burden on producers at the early
stages of a project. The early stages impact the rate of
return on the project. The credit allowed a relatively high
rate of government take without penalizing the rate of
return for the producer who can claim the credit in the
first years of project development. He cautioned that
changes to the capital credit should be carefully
considered. Changes to the capital credit structure could
"deteriorate" the rate of return for marginal projects. The
ability for a producer to claim capital credits in the early
years of a project was critical to the timing of cash flow
especially on high cost developments with marginal rates of
return.
2:40:42 PM
Mr. Mayer addressed the Australian system that consisted
solely of state and federal income tax and a profit based
tax. He offered that the Australians wanted to structure a
fiscal system where government take was equal to the equity
stake in a project. The tax was levied at 40 percent of cash
flow but contributed 40 percent of the costs. The costs were
fully deductible each year. The 40 percent deduction acted
as a 40 percent investment by government but did not bear
risk. If the project failed the government was not
responsible for the costs.
Mr. Mayer reviewed Slide 25, "Capital Credit -Return on
Investment Under ACES at $50 Oil." which provided a graph
that depicted the project cash flows and returns to the
state. He reminded the committee that two capital credits
were available to new producers without existing production;
the qualified capital expense at 20 percent and the carried-
forward annual loss credit at 25 percent. He delineated that
the graph was based on cash flow economics after state and
federal income taxes. A yellow line depicted the total
divisible income from a project. The total divisible income
was revenue less expenses. A red line depicted government
take. Government take dropped as capital credits were taken
in the beginning of a project then rose with fixed
royalties, production, and property taxes. A blue line
depicted a 35 percent equity stake. The line was similar to
the government take. The 35 percent equity stake represented
the combined capital credits minus federal and state income
taxes.
2:45:17 PM
Mr. Mayer concluded that at $50/bbl. the government take was
higher; 8 percent rate of return (IRR) and negative 36
percent of the net present value (NPV), than the equity
stake; 5 percent IRR. He turned to Slide 26, "Capital Credit
- Return on Investment Under ACES at $100 Oil." He noted
that the return on investment under ACES for $100/bbl. oil
was even greater for the government take at 29 percent IRR
and three times higher NPV than the 35 percent equity stake.
Mr. Mayer remarked that the trend continued upward at
$150/bbl. oil, depicted on Slide 27, "Capital Credit -
Return on Investment Under ACES at $150 Oil." The trend
increased dramatically at $200/bbl. displayed on Slide 28,
"Capital Credit - Return on Investment Under ACES at $200
Oil" [57 percent IRR for the government take and; 33 percent
IRR for the 35 percent equity stake]. He surmised that the
state of Alaska received a significantly high cash return on
its initial investment of capital credits for a project.
Mr. Mayer highlighted Slides 29-32, "Capital Credit - Return
on Investment Under Severance Option 1 at $50, $100, $150,
and $200 Oil" sequentially. The slides portrayed the same
graph using the severance tax scenario. He pointed out that
at $50/bbl. the numbers were similar to the ACES capital
credit return on investment. As the price of oil climbed to
$200/bbl. the difference in the net present value between
the capital credit and severance options narrowed.
Co-Chair Stedman compared slide 30 to slide 26 which graphed
the rate of return for both scenarios at $100/bbl. oil. He
asked if the net present value represented the cash flow to
the state. Mr. Mayer confirmed the statement and added that
state and federal income taxes were factored into the net.
Co-Chair Stedman observed that the net present value to the
state was more favorable under ACES. Mr. Mayer confirmed
that both options had similar outcomes but were more
favorable under ACES.
Co-Chair Stedman asked if the severance tax option included
the seven year tax holiday. Mr. Mayer replied that the model
only examined the 20 percent rate.
2:51:48 PM
Senator Olson referred to slides 32 and 28. He requested
clarification on why the divisible income was represented as
a notch on the graph at $200/bbl. oil for both options. The
line peaked at approximately $750 million in 2012 then
dipped to approximately $650 million in 2014, slightly rose
in 2016 and leveled out over the subsequent years.
Mr. Mayer responded that in general a notch represented a
reaction to the impact of depreciation on a project or
federal income tax kicking in and reducing cash flow.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 192 April 2 Alaska Senate Finance.pdf |
SFIN 4/2/2012 1:00:00 PM |
SB 192 |
| SB 192 DOR Response 040112.pdf |
SFIN 4/2/2012 1:00:00 PM |
SB 192 |