Legislature(2011 - 2012)SENATE FINANCE 532
02/13/2012 01:00 PM Senate FINANCE
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| Presentation by Pedro Van Meurs on Arctic and Alaska Oil Economics: Session Two | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
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ALASKA STATE LEGISLATURE
JOINT MEETING
SENATE RESOURCES STANDING COMMITTEE
SENATE FINANCE COMMITTEE
February 13, 2012
1:03 p.m.
1:03:15 PM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 1:03 p.m.
SENATE FINANCE COMMITTEE MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Johnny Ellis
Senator Dennis Egan
Senator Donny Olson
Senator Joe Thomas
SENATE FINANCE COMMITTEE MEMBERS ABSENT
Senator Lesil McGuire, Vice-Chair
SENATE RESOURCE COMMITTEE MEMBERS PRESENT
Senator Joe Paskvan, Co-Chair
Senator Bill Wagner, Co-Chair
Senator Wielechowski, Vice-Chair
Senator Bert Stedman
Senator Hollis French
Senator Gary Stevens
SENATE RESOURCE COMMITTEE MEMBERS ABSENT
Senator Lesil McGuire
ALSO PRESENT
Dr. Pedro Van Meurs, President, Van Meurs Corporation,
Legislative Consultant; Senator Cathy Giessel
SUMMARY
^PRESENTATION BY PEDRO VAN MEURS ON ARCTIC AND ALASKA OIL
ECONOMICS: SESSION TWO
1:05:00 PM
DR. PEDRO VAN MEURS, PRESIDENT, VAN MEURS CORPORATION,
LEGISLATIVE CONSULTANT, provided members with a PowerPoint
presentation: Policy Options for Alaska Oil and Gas (copy
on file). He observed that he would focus on Session 2 of
his presentation: International Competitive Framework. He
emphasized the importance of knowing the structure of
competition. He stated he would evaluate competition for
five groups of resources: existing light oil production,
new light oil production, heavy oil and shale oil, and
natural gas.
1:05:58 PM
Mr. Van Meurs looked at slide 26, existing oil production.
Shallow water oil production had the largest peer group,
with 125 world nations that were compared to Alaska in
terms of the exporting jurisdictions and 28 oil exporters.
The Arctic Report compared Alaska with other Arctic
jurisdictions.
Mr. Van Meurs reviewed profitability for various
jurisdictions, on slide 27. He looked at the rate of return
for world competitors using a base case field of shallow
water oil production. A typical field with a $20 per barrel
cost was compared for rate of return and profitability for
each of the world competitors. Alaska, Cook Inlet oil,
which was slightly better than North Slope oil, came out
favorably when compared to other exporters. Exporters with
high costs, typically had costs over $15 per barrel. Lower
cost jurisdictions had costs in the $10 to $15 dollar a
barrel range. Jurisdictions with very low costs could
typically charge higher government take than jurisdictions
with high costs. Alaska was not badly positioned at number
nine of 28 in profitability.
1:09:00 PM
Co-Chair Stedman observed that Cook Inlet oil production
was negative in terms of revenue. Mr. Van Meurs clarified
that the analysis pertained to terms not received funds.
The review was based on a comparison of fiscal systems.
Cook Inlet with mature fields was in a later phase.
Co-Chair Stedman observed that the comparisons were based
on $80 per barrel and questioned if the comparisons would
change if the per barrel price increased. Mr. Van Meurs
affirmed that per barrel price changed the comparisons.
1:10:13 PM
Mr. Van Meurs, in response to a question by Senator
Wielechowski, explained that Cook Inlet was used because it
was a shallow water comparison. North Slope terms were
compared to other Arctic jurisdictions in subsequent
slides.
Mr. Van Meurs, in response to a question by Senator
Wielechowski, explained why investment would occur in Qatar
or Russian, which had negative rates of return. The base
cost rate in the comparison was $20 per barrel. The typical
cost in Qatar was $5 to $8 per barrel. Qatar was analyzed
at a higher cost than would be experience.
Mr. Van Meurs reviewed the color codes used in the cost
comparisons on slide 27: exporters identified in blue
compared in cost with Alaska; exporters identified in
yellow were lower than Alaska; and exporters identified in
green were much lower than Alaska. He concluded that the
government take in low cost areas were higher than in high
cost areas.
1:11:50 PM
Mr. Van Meurs looked at government take for various
jurisdictions. Alaska rated 10 out of 28 jurisdictions in
terms of attractiveness. Alaska was not unusually
positioned internationally from a competitive point of
view. Government take was based on $80 per barrel. Alaska
was at 70 percent government take at $80 per barrel, which
was not an unusual level of government take compared with
other exporters. Nova Scotia and Canada, with costly
conditions, were on the lower side of government take.
1:13:59 PM
Senator Wielechowski observed that Cook Inlet had a zero
percent tax rate for oil and a 12.5 percent rate for
royalty with large credits. Mr. Van Meurs explained that
the government take was lower because the zero tax rate was
limited and would expire. The time frame used in his
comparisons assumed a decade before production and would
fall in the new regime, 2022. There would only be three
years at the low tax rate.
1:15:01 PM
Mr. Van Meurs concluded that an increase to $120 a barrel
would not change Alaska's relative position, despite the
fact that it had a price progressive system since many
other nations also had price progressive systems. For very
high prices the scale goes "off the rails" but Alaska was
well positioned in the $80 to $120 range from an
international competitive view.
Co-Chair Stedman asked for a definition of "progressive"
and "regressive". Mr. Van Meurs clarified that a
progressive system in taxation meant that the total
government take increased proportionally with the price; a
regressive system would result in a lowering of total
government take proportionally if the price increased.
Alaska's system under the Alaska's Clear and Equitable
Share (ACES) system was structured so that the government
share went up disproportionally with increased price and
the government would receive a higher benefit of the total.
Many nations have progressive systems similar to Alaska's;
therefore, Alaska's relative position would not change
significantly with higher prices.
1:17:42 PM
Mr. Van Meurs compared Alaska's Arctic oil price under ACES
to other jurisdictions. Cost in the Arctic was dependent on
the existence of transportation systems. He observed that
slide 30 showed jurisdictions in red that were without
transportation; blue lines indicated transportation systems
in place. He concluded that prices under ACES were not out
of line with other jurisdictions. Arctic costs were
relatively similar.
Mr. Van Meurs, in response to a question by Co-Chair
Stedman, explained that assumptions were based on an
international oil price of $80 per barrel, with
transportation costs netted back. Trans-Alaska Pipeline
System (TAPS) transportation costs were $5 per barrel of
oil. Russia pipeline transportation costs were $7 per
barrel of oil. Assumptions were made for areas without
transportation.
1:20:27 PM
Mr. Van Meurs discussed net present value on slide 31.
Alaska compared well with Norway and Russia. Russian terms
were regressive; at lower costs Russian terms would come
out better than ACES. There were still quite a few low cost
Russian fields in development. The negative feature for
Russia was due to high costs. Alaska was not onerous at $80
a barrel.
Mr. Van Meurs observed that the relationships between
Arctic nations would remain stable at $120 per barrel of
oil, except that Russia would improve significantly due to
its regressive system.
Co-Chair Stedman asked how prospectivity would be dealt
with in the basin's; and questioned if Greenland's basin
was as rich as Alaska's.
1:22:34 PM
Mr. Van Meurs discussed attractiveness from a geological
point of view. He referred to slide 32. Greenland had a low
government take and was offering favorable terms since oil
had not been discovered. Canadian federal lands had good
prospectivity but had not constructed a large scale
transportation system; consequently, the Canadian
government had to offer relatively attractive terms. The
Alaskan Chukcki Sea had good prospectivity (geology) and
good government take levels. He spoke to other
jurisdictions and observed that Iceland had near zero
prospectivity. Russia's Krasnoyarsk area had been
discovered during communist times and was already in
production. He observed that opportunities were present in
the Bering Sea since Norway had concluded agreements with
Russia. Russia offered 2010 export duty region terms on
many smaller fields, which lowered government take.
1:27:07 PM
Co-Chair Stedman asked Mr. Van Meurs to address the issue
of over 100 percent government take. Mr. Van Meurs
explained that if a system was not economic at a particular
price and cost, then the government take showed up as over
100 percent. Government take in Russia would be at 80
percent with a $120 per barrel price and $15 per barrel
cost. Russian government take was very sensitive to cost
and price assumptions.
Senator Egan asked if the anticipated million barrels a day
oil production level would include Chukcki oil. Mr. Van
Meurs explained that his reference to one million barrel a
day production relied on available Alaskan resources. The
Chukchi Sea alone could produce half a million barrels of
oil a day, but it was not clear if the oil would go through
TAPS. Discoveries in the Beaufort Sea could go through
TAPS. The objective of the governor was to increase
production, not to get more oil through the line.
1:29:30 PM
Senator Wielechowski questioned how government take was
calculated. He observed that the Shell Oil Company paid $3
billion in signature bonus costs when the leases were
bought in the Chukcki and Beaufort Seas. The Great Bear oil
company paid $8 or $9 million when it acquired 500,000
acres. Studies that factor in signature bonus costs show
the Chukcki and Beaufort Outer Continental Shelf (OCS)
government take would spike to 77 percent. Mr. Van Meurs
did not necessarily agree. He emphasized that the bonus was
dependent on size of the anticipated discovery. The $3
million bonus would be immaterial in overall government
take in compared to the size of oil field.
1:31:45 PM
Co-Chair Stedman asked for clarification on upfront bonus
costs versus the net present value calculation. Mr. Van
Meurs explained that assumptions about bonuses were
included in government take since it was a payment to
government. Government take came out at the first day of
cash flow, so a 10 percent net value discount was
important, as front ended bonuses weighed heavily. Bonuses
were not as significant in the undiscounted government
take.
1:32:46 PM
Mr. Van Meurs concluded that ACES was tougher than a number
of other jurisdictions. Alaska was positioned well even
among Arctic jurisdictions.
Mr. Van Meurs reviewed slide 33 and observed that Alaska
compared well to other jurisdictions in front-end loading.
Investors considered when a government takes its payment.
Governments that can wait have a positive impact (back
ended system); taking government share upfront has negative
impact on profitability (front-ended). Discounted and
undiscounted government take comparisons showed the
relative degree that governments take their revenues early
in terms of value. Low numbers signify that governments
were beneficial in terms of their take. Governments with
high numbers on slide 33 were not beneficial to investors
in terms of government take. Alaska was the most favorable
of the Arctic jurisdictions due to tax credits that provide
early benefits. Russia required export duties from the
start; much like paying a royalty. Alaska had a favorable
distribution on a worldwide basis.
1:36:39 PM
Mr. Van Meurs discussed slide 34 and noted the importance
of incentives given by government in terms of exploration;
how much governments shared in exploration in terms of tax
deductions. A government that losses, in the case of a dry
hole, shares in the geologic risk. Alaska was the best
jurisdiction in the world along with South Africa in terms
of sharing geological risk.
1:38:30 PM
Co-Chair Stedman asked how basins would be ranked for
geographical risk outside of the tax code. Mr. Van Meurs
clarified that it was difficult to give a single geological
risk number for the entire North Slope; some areas were
relatively high, others were not. He assumed that one out
of five exploration wells would be discovered, which was
generous for some jurisdictions. Only Iceland was
considered a high risk. The government of Alaska
participated in geological risk to an unusual rate.
1:40:47 PM
Senator Thomas asked how Alaska stacked up against North
Dakota and Texas. He also questioned if the state would be
a high risk sharing government without exploration credits.
Mr. Van Meurs clarified that the risk factor was tied to
the high tax credit. North Dakota did not have tax credits.
Alaska was the most favorable in the United States and one
of top two in the world.
Senator Paskvan observed that Alaska had a net system as
opposed to a gross system and questioned if deduction of
operating and capital expenses indicated government risk
sharing. Mr. Van Meurs clarified that he was referring to
geological risk sharing not economic risk sharing. The
concept of ACES was to share in economic risk. He concluded
that economic risk sharing was embedded in ACES, but that
there was extremely high geologic risk sharing.
1:43:03 PM
Senator Thomas asked for comparisons of overall economic
risk. Mr. Van Meurs did not have economic or political risk
charts in his study. He observed that in a profit sharing
system, in general, the government observes more risk than
in a plain royalty system.
1:44:41 PM
Mr. Van Meurs concluded that the government take of about
70 to 75 percent for Alaska was reasonable compared to the
other exporters for existing operations. He felt that 65
percent for existing production gave away too much; 70 to
75 percent was well in the international competitive scale
for existing production. He observed that SB 192 retained
significant revenues on existing production in the 74 to 76
percent government take range, but did not think it was
necessarily a serious bill in terms of economic concessions
since there was no cap. He concluded Alaska also offered a
favorable time distribution of the government take and very
favorable sharing of geological risk at the 70 to 75
percent range.
1:45:50 PM
Mr. Van Meurs reviewed new production as demonstrated on
slide 37. He observed that Alaska light oil production was
rapidly declining (5 percent per year). Internationally,
there were not many jurisdictions in declining production
mode; examples were Alberta, Gabon, Trinidad and Tobago.
Both Gabon and Trinidad applied a 12 percent drop to new
blocks in order to attract new investment in an effort to
offset declining production. Terms and conditions on old
blocks remain unchanged.
1:47:03 PM
Mr. Van Meurs concluded that Gabon, Trinidad and Tobago
were three jurisdictions with declining conventional oil
production. There were not many in the "peer group" for
Alaska that would be exporting jurisdictions with a
declining conventional oil production.
Senator Paskvan observed that the administration indicated
that the anticipated decline [in production] from 2010 to
2020 would be 2.1 percent. Mr. Van Meurs clarified that his
calculations of five percent decline were taken from
published charts used as background information from the
governor for HB 110, which seemed reasonable.
1:50:00 PM
Mr. Van Meurs observed that Canada had moved in another
direction from the United States and competed differently
than Gabon, Trinidad and Tobago in their fiscal system.
Canada designed royalties on formulas with a system for a
wide range of economic conditions. Royalties were higher
when economics were more profitable; royalties were lower
in less profitable situations. Canada competes through the
structure of government take, not the level.
1:51:20 PM
Mr. Van Meurs noted that slide 41 demonstrated government
take on small high cost wells ($50 per barrel of oil cost
and 10,000 barrels cumulative) to a rich well ($20 per
barrel of oil cost and 1,000,000 barrels cumulative). The
Texas well had government take over 100 percent. Alberta
stayed almost flat and went up with the more profitable
field. He concluded that when there was new oil under
higher costs (Alberta) the system automatically adjusted to
the new situation, which is why there is so much drilling
in Alberta, as both high and lower cost wells are
profitable.
1:52:42 PM
Mr. Van Meurs reviewed slide 42, which demonstrated typical
government take on oil wells in North America. Canada was
more attractive than the United States due to improved
Canadian terms over the past 15 years. Canadian terms
reflect that it had declining oil production.
Senator Wielechowski asked if private land owner take was
included in the government take for Texas and Louisiana.
Mr. Van Meurs affirmed and observed that it was not
uncommon to pay 25 to 30 percent for government take in
those jurisdictions.
Senator French queried how many private contracts were
reviewed for an average. Mr. Van Meurs explained that
contacts in Texas and Louisiana provided an average.
1:54:55 PM
Senator French wondered if slide 42 could be applied to
slide 32. Mr. Van Meurs pointed out that North American
wells had a different price structure than Arctic fields.
He stated that the chart was based on a specific cash flow.
He stressed that wells and fields were taxed differently.
1:56:00 PM
Co-Chair Stedman concluded that the North Dakota, Bakken
Horizon oil well at 50 percent (government take) was not a
direct correlation on Alaska's light oil at 70 to 75
percent. Mr. Van Meurs responded that Alaska was compared
with world exporters. He added that a special shale oil
comparison would be made later in the presentation.
1:56:40 PM
Mr. Van Meurs noted that Canada had become more attractive.
In 1997, the typical tax rate in Canada was 45 percent;
since then both federal and provincial governments had
substantially lowered the tax rate to 25 percent. Canadian
provinces promoted progressivity in royalty formulas to
encourage companies to move into higher cost resources. The
federal and Alaskan government takes in the United States
stayed the same. Canada had pulled ahead of the United
States in terms of investors.
1:58:11 PM
Mr. Van Meurs concluded that a 10 percent drop in
government take for new production was reasonable when
compared to jurisdictions facing a declining production. He
concluded that the 60 to 65 percent government take for
more costly "new" light oil resources as proposed in HB 110
and HB 17 was a reasonable level from an international
perspective.
1:59:11 PM
Mr. Van Meurs spoke to heavy oil. He observed that Alaska
was well endowed with heavy oil resources in two groups:
· Heavy Oil: 15 - 22 degrees API; and
· Ultra-heavy Oil or Bitumen: 8 - 15 degrees API.
The ultra-heavy oil (8 to 15 degrees API) could not be
transported by pipeline or marine tanker and needed to be
produced with special production methods. Heavy oil (15 to
22 degrees API) could typically be produced with
conventional production methods, since oil flows to the
wells. The oil could also be transported by pipeline and
marine tankers.
2:00:43 PM
Mr. Van Meurs observed that Alaska has significant heavy
oil in the 15 - 22 degrees API: West Sak, Schrader Bluff,
Orion, Polaris, Nikaitchuq. Ultra Heavy Oil in the 10 to 15
degrees API was also in Alaska in large volume in the Ugnu
deposits. Separate fiscal terms were required for the two
groups.
2:01:09 PM
Mr. Van Meurs noted that heavy oil compared in North
America to Alberta oil sands, at 43 to 55 percent
government take depending on the oil price. In order to
compete, the government take for ultra-heavy oil in Alaska
had to be similar to Alberta. Alberta also had price
progressivity. At $120 per dollar a barrel government take
would be closer to 55 percent; and at $60 per dollar a
barrel government take would be closer to 43 percent.
Alberta was an immense economic investment opportunity with
500 billion of recoverable oil.
Co-Chair Stedman addressed the $500 billion barrels of oil
in Alberta. Mr. Van Meurs stressed that there were 1,400
billion in-place barrels of reserves in the Alberta oil
sands. Current special steam injection technology was
expected to recover 30 to 40 percent of in-place oil.
2:03:28 PM
Co-Chair Stedman queried the number of recoverable barrels
in Alaska. Mr. Van Meurs replied that there were 5 billion
barrels of recoverable oil in Alaska. He pointed out the
level of competition with Canada with 500 billion barrels,
which were comparable to the heavier oil in Alaska. Alaska
was fortunate that $4 billion of the $5 billion was
lighter, better quality oil.
2:04:46 PM
Senator Wielechowski queried the cost per barrel of oil in
Canada and Alaska. Mr. Van Meurs replied that the operating
and capital cost per barrel was approximately $30 per
barrel of oil. He observed that $60 to $70 per barrel of
oil was needed to be economic. He estimated that the cost
per barrel in Alaska would be comparable but slightly more
expensive with Arctic conditions. He stressed that there
were unique problems related to the process and development
in Alaska.
Senator Wielechowski asked the net present value rate of
return for Canadian heavy oil versus Alaskan heavy oil. He
questioned if government take, net present value, or
internal rate of return should be considered in comparison
to Canada. Mr. Van Meurs noted that his on shore studies,
which were not yet published, would address the issue. He
noted that investors look at all the criteria; all needed
to be attractive.
2:07:57 PM
Mr. Van Meurs concluded that heavy oil in Alaska was better
quality and could handle a higher government take 55 to 60
percent. Ultra heavy Oil had to compete with Alberta and
should have lower government take.
2:08:32 PM
Mr. Van Meurs cautioned, that at that time, it was not
known whether shale oil production would be possible in
Alaska. There were large oil shale deposits at around
10,000 feet deep. Companies would have to create reservoirs
to produce the oil by "fracking" to make the oil flow to
the well. The problem with shale oil was that different
reservoirs had different fracking characteristics. Pilot
projects would be required to identify whether reservoir
characteristics were of a nature that would permit fracking
and would result in a sufficient flow of oil to make shale
oil economic. He stressed the importance for Alaska to
identify, through pilot projects, whether shale oil was
economic. Shale oil would likely be light oil.
2:11:26 PM
Senator French referred to development of fracking
technology. Mr. Van Meurs acknowledged that fracking
technology had improved but stressed that some rocks were
not frackable. Clay would not fracture. He noted that it
was difficult to predict whether shale would be frackable
without pilot projects. Fortunately, much of Alaska's shale
oil shale was located along the highway to Prudhoe Bay. He
stressed that sufficient fiscal encouragement would need to
be given due to the additional cost of pilot tests.
2:13:12 PM
Mr. Van Meurs reviewed slide 51, North American Wells. He
observed that government take for shale oil in the United
States was approximately 60 percent across all lands.
Canada was the most attractive (40 percent). Shale oil
would be more expensive in Alaska than in North Dakota or
Wyoming due to difficult conditions and depth of
reservoirs. He concluded that Alaska would need to offer
governments take of under 60 percent.
Mr. Van Meurs, in response to a question by, Co-Chair
Stedman, reiterated that the analysis used $80 per barrel
of oil. The government take would drop slightly at $120 per
barrel of oil due to regressive fiscal systems.
Senator Wagner asked how the calculations were derived. Mr.
Van Meurs explained that they utilized contact with
federal, state and private land managers to ascertain
details of the terms. The fiscal terms for each
jurisdiction were available in North American study.
2:16:13 PM
Senator Wielechowski questioned why undiscounted government
take was used and asked if it was realistic. He asked if
Alaska's discounted rate would be higher or lower [than
other jurisdictions]. Mr. Van Meurs explained that his
study used 10 percent discounted government take as well as
undiscounted government take. Governments liked to compare
on undiscounted government take because of long term cash
flow. He stated that he would use a five percent government
take rate for Alaska. Undiscounted government take was used
for ease of comparison.
Senator Wielechowski asked if a discounted rate would be
more appropriate with the credits offered by Alaska. There
were large upfront costs to the state for exploration and
development. Mr. Van Meurs affirmed and looked at slide 33,
which showed that Alaska was the most favorable when
compared for distribution of government take. He concluded
that Alaska was looking at a government take of 45 to 55
percent in order to attract long term investment to Alaska
(assuming the pilot tests demonstrate that shale oil was
economical). He emphasized Alaska might have significant
shale oil potential and emphasized the need to define and
encourage large scale project testing and the immense
importance to the state of Alaska to set terms.
2:19:54 PM
Mr. Van Meurs spoke to natural gas. The Pacific market was
very competitive. Current major new LNG suppliers in the
Pacific LNG market were Australia and Papua New Guinea.
Government take was typically in the 45 to 52 percent
range. He stressed that offshore and onshore conventional
gas production in China was also significant. China had
1300 trillion cubic feet (Tcf) of coal bed methane gas and
1100 Tcf of shale gas and one-third of the unconventional
gas resources in the world. China was actively developing
resources with international companies. He emphasized that
China might be an exporter not importer of gas. He
cautioned not to rely on China as an importer. China's
government take was unusually low at 42 percent for dry
gas. China was purchasing companies experienced in shale
oil development and training on an enormous scale. China
also had the financial resources to develop the resource.
He concluded that China was aggressively developing its
large resources. There were some problems with Chinese
production sharing contracts and bottlenecks with training.
He reiterated that Alaska should not count on China as an
import nation in ten years.
2:22:36 PM
Mr. Van Meurs reviewed slide 54, Arctic Gas. The most
interesting country on the chart was Russia with the Yamal
Peninsula LNG project. The Yamal Peninsula project was
similar to Prudhoe Bay with 40 Tcf of gas. Most of the
shores were surrounded by six feet of packed ice and had
shallow dredging. Russian government take for gas was 24
percent, the lowest in the world. The Russian company
Novatek, with the help of the French company Total, planned
to build ice breakers and LNG tankers to ship year around
into Asian markets. In eight years, Russian tankers were
anticipated to be through the Bering Straight to establish
year around transportation across Arctic paid with by LNG.
2:25:19 PM
Mr. Van Meurs concluded Alaska would have to offer
governments take in the range of 45 to 55 percent in order
to be competitive for the production of gas; Prudhoe Bay
might be slightly higher.
Mr. Van Meurs summarized that in order to be competitive;
Alaska needed to develop a fiscal system that offered the
following government takes for the various resources:
· Existing light oil production: 70 - 75 percent
· New light oil production: 60 - 65 percent
· Heavy Oil: 55 - 60 percent
· Ultra Heavy Oil: 45 - 55 percent
· Shale Oil: 45 - 55 percent
· Natural Gas - new gas fields: 45 - 55 percent
· Natural Gas - Prudhoe Bay: 55 - 60 percent
2:26:37 PM
Senator Paskvan referred to slide 37. He observed that the
Department of Natural Resources forecasted an average
decline rate at 2.1 percent from FY 10 - FY 20 in a letter
dated 3/22/2012. Mr. Van Meurs had no opinion.
Senator Wagner returned to slide 39 and asked why Gabon,
Trinidad and Tobago had recently reduced their terms on
government take by 12 percentage points. Mr. Van Meurs
explained that there was an attempt to attract new
investors. There were no investors prior to the drop in
terms.
ADJOURNMENT
2:29:25 PM
The meeting was adjourned at 2:29 PM.
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