Legislature(2011 - 2012)SENATE FINANCE 532
03/15/2012 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| 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 | ||
| + | TELECONFERENCED |
SENATE FINANCE COMMITTEE
March 15, 2012
9:06 a.m.
9:06:19 AM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 9:06 a.m.
MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Lesil McGuire, Vice-Chair
Senator Johnny Ellis
Senator Dennis Egan
Senator Donny Olson
Senator Joe Thomas
MEMBERS ABSENT
None
ALSO PRESENT
Gerald Kepes, Partner, Head of Upstream & Gas, PFC Energy;
Senator Joe Paskvan; Senator Cathy Giessel; Senator Hollis
French.
PRESENT VIA TELECONFERENCE
Janak Mayer, Manager, Upstream & Gas, PFC Energy,
Washington, D.C.
SUMMARY
SB 192 OIL AND GAS PRODUCTION TAX RATES: Presentation by
PFC Energy
SB 192 was HEARD and HELD in committee for
further consideration.
SENATE BILL NO. 192
"An Act relating to the oil and gas production tax;
and providing for an effective date."
9:08:44 AM
Co-Chair Stedman stated that this was the initial
presentation by PFC Energy and that more detailed
information would be provided in subsequent presentations.
GERALD KEPES, PARTNER, HEAD OF UPSTREAM & GAS, PFC ENERGY,
related that PFC Energy was an expertise consultancy that
dealt exclusively with oil and gas. He explained that PFC
Energy was a global, 150 member consultancy that was
focused on the nexus between governments and industry. He
acknowledged that oil and gas were government businesses
and that companies needed to learn work within government
structure.
Co-Chair Stedman requested a definition of the term
"upstream". Mr. Kepes replied that upstream referred to all
activities associated with the exploration and production
of oil and gas. He furthered that upstream included all
onshore, offshore, deep water, and other activities.
9:10:52 AM
Mr. Kepes began a PowerPoint presentation titled
"discussion slides: Alaska Senate Finance Committee" (copy
on file), and discussed the slide on page 3 titled "fiscal
regime design: finding the intersection of efficiency and
competitiveness."
· Fiscal regime design is fundamentally about
maximizing State revenues, subject to two
important constraints:
· Efficiency: Not distorting investment
choices, or preventing marginal investments
that would otherwise have been made
· Competitiveness: There is a global market for
upstream dollars
Mr. Kepes explained that competiveness was an important
part of the context of fiscal regime design and that any
upstream opportunity had to compete globally with other
opportunities.
Mr. Kepes discussed the slide on page 4 titled "fiscal
regime design: finding the intersection of efficiency and
competiveness." He shared that an overly efficient fiscal
regime, which had a government take that was too high,
would result in a loss of competitiveness and investment.
He furthered that if the government take was lowered too
far, the objective of maximizing government take would be
lost. He related that the challenge was to find the "sweet
spot" between competiveness and efficiency, given the other
factors.
9:13:41 AM
Mr. Kepes spoke to the slide on page 5 titled "relative
government take (definition)." He explained that in the
context of the presentation, "government take" referred to
the "relative government take". Relative government take
represented the total government take over the "divisible
income."
Divisible Income equals Gross Revenues less costs,
including capex and transportation costs.
Government Take includes all payments the government
mandates in its function as a sovereign:
• Royalties
• Land rental fees, property taxes
• Production taxes
• Income taxes
Government Take does not include amounts the
government earns via a direct equity stake
Mr. Kepes discussed the slide on page 6 titled "fixed
royalty systems: inefficient, but potentially highly
competitive."
· Given varying project costs, and varying prices,
fixed percentage royalty systems are inefficient
because they distort investment, making previously
economic projects uneconomic at a given price
· Government Take from a fixed royalty system can
be very high when costs are high or prices are
low - 100% in the example of project 5
· In high price environments, however, fixed royalty
systems can be very competitive
· Government Take can be very low when prices are
high, or costs are low - only ~33% in the
example of project 1
Mr. Kepes stated that the slide illustrated a 30 percent
fixed royalty system on five different projects that had
varying costs; it showed a fiscal system design that was
very competitive, but was not efficient from the state's
point of view. He pointed out that the black horizontal
line on the chart was at 30 percent. He related that
project 5 was a high cost development, while project 1 had
a low cost. He furthered that in the case of project 5, the
system was very efficient, but that it was probably not
very competitive.
Mr. Kepes explained the slide on page 7 titled "profit-
based fiscal systems: more efficient, but may be less
competitive."
· A Profit-Based fiscal system may be:
· A contractual arrangement, such as a
Production Sharing Contract
· A tax which applies to revenues less costs
· Such systems can be capable of raising greater
revenue, while reducing inefficiency:
· In low oil price environments, or high cost
environments, Profit- Based Systems are less
likely to make marginal projects non-economic
· By capturing more rent in high oil price
environments, or low cost environments, however,
they may also not compete with royalty regimes:
· Projects 1 and 2 would be significantly more
attractive to undertake under a royalty
regime
Mr. Kepes related that a profit-based fiscal system was
more efficient in terms of generating more income for the
state, but that it may be less competitive. He stated that
the chart depicted a 50 percent profit-based tax on five
different projects and that it showed the divisible income
that was available from the scenario's projects.
Co-Chair Stedman requested a clarification of the term
"rent". Mr. Kepes replied that rent was the divisible
income and that it reflected the amount of revenue that the
state would accrue. He added that the "normal return on
capital" represented the amount of money that was returned
the investor.
Mr. Kepes summarized that slides 6 and 7 illustrated the
point of efficiency versus competiveness and that they were
examples of two end member cases. Mr. Kepes reiterated that
it was a challenge to find the proper combination of
efficiency and competitiveness.
9:18:11 AM
Mr. Kepes stated that upcoming slides would comment on and
analyze the global business environment for the Alaskan oil
and gas sector. He explained that Alaska, like any other
oil and gas sector, did not sit in a vacuum.
Mr. Kepes discussed the slide on page 9 titled "fixed-
royalty jurisdictions in U.S. Lower 48 are a key competitor
to Alaska for investment dollars." He related that the
slide made a very important point and that it examined the
global oil players' aggregated sources and uses of cash
flow. He stated that the graph on the left hand side of the
slide showed that the listed companies had an aggregate
cash surplus in the majority of the regions that they
invested in. He pointed out that during the 2003 to 2005
period, the upstream cash flow for companies in Europe and
North America was much higher than the capital being spent
in the two regions and that there was a substantial cash
surplus; over the three year period, companies generated
$50 billion of upstream cash flow premium of the capital
that they had spent in the two regions. He pointed out that
Sub Saharan Africa was the only area on the slide that was
in cash deficit from 2003 to 2005; during that time period,
companies in Sub Saharan Africa were generating slightly
less upstream cash flow than they were spending on capital
expenditures.
Mr. Kepes referenced the chart on the right hand side of
the slide and stated that the North American investment
area had changed radically for the large, global oil
companies from 2008 to 2010; during this period, North
America was no longer generating surplus cash flow, but
instead had a cash deficit of $50 billion to $60 billion.
He explained that developments in the shale plays[There are
two definitions for "play" in relation to oil activity: The
extent of a petroleum-bearing formation; also, it is the
activities associated with petroleum development in an
area.]in the Lower 48 were responsible for the change in
North America's oil investment climate; as a result of the
change, the larger, global oil companies had completely
shifted their onshore investment strategies in the region.
He offered that it was important to know where the capital
from the global oil companies was going, specifically
regarding the three major producers on the North Slope. He
concluded that the investment opportunities for the onshore
U.S. had changed and that the change was an important part
of the context regarding how companies made investment
decisions.
Mr. Kepes declared that the Lower 48 was "a very key
competitor to Alaska for investment dollars", specifically
regarding the large, global oil companies.
9:23:06 AM
Mr. Kepes discussed the slide on page 10 titled "all eyes
on the price, but what about cost." He stated that the
slide showed that over the last ten years, a lot of
attention had been on the developments in the price of oil,
but that there had not been much focus on the changes to
costs. He furthered that the graph on the slide depicted
the total spending for the global exploration and
production (E&P) sector, the Brent Index price of oil, as
well as the costs for exploration and development. He
stated that onshore development costs, which were indexed
to 100 in the year 2000, had increased to approximately 60
percent to 70 percent over that number. He pointed out that
unit cost inflation had been occurring since the year 2000
and that it was occurring at a higher rate in offshore
projects; however, both onshore and offshore exploration
and development costs were substantially higher than they
were in the year 2000. He stated that it was important to
note that the price of oil and the price of gas at the pump
were very visible, but that sometimes the associated costs
were not so visible; he pointed out that this was part of
the global environment in the context of the investment
decisions that companies made.
Mr. Kepes discussed the slide on page 11 titled "Alaska's
days of "easy oil" are gone: high costs and high government
take present challenges." He related that the slide was
meant to bring observations into focus, make comparisons,
and make some points about costs. He reiterated that Alaska
was in a global oil market and referenced the previous
slide's figure that the global industry would spend
approximately $600 billion on E&P in 2012. He stated that
the slide showed that Alaska was a "somewhat to
substantially" higher cost environment in comparison to
other oil sectors in the Lower 48; capital expenditures for
Alaska conventional oil were approximately $17 to $18 per
barrel and the operating expenditures in the area were
almost as high. He related that the slide provided specific
cost data for unconventional shale plays in the Lower 48
and for onshore, conventional E&P activities in Texas and
Louisiana. The Bakken shale oil play in North Dakota was a
high cost play, but was not as high cost as Alaska. He
specified that Haynesville was primarily a shale gas play
and that the Barnett play contained gas and oil.
9:27:35 AM
Co-Chair Stedman referenced the "new conventional" Alaskan
oil on slide 11 and inquired how Alaska's "conventional"
oil costs would compare to other sectors on the slide. Mr.
Kepes replied that for infill drilling or new opportunities
in the currently producing areas, the costs would be
"closer to what you see here between the unconventional
Bakken and maybe even around the Haynesville or less." He
concluded that the costs for drilling in and around
existing production on the North Slope were substantially
lower than the costs for "new conventional" oil in Alaska.
Senator Olson asked for a clarification on slide 10. He
noted that the header on the slide stated that oil prices
would increase by 450 percent and queried if this meant
that the price of oil would be in excess of $500 per
barrel. Mr. Kepes replied that the oil price on the slide
was an index price and that it was based on the price in
the year 2000. He explained that the prediction was a 450
percent increase to the $15 or $16 per barrel price of oil
in the year 2000. He stated that PFC Energy thought oil
prices could "drift" higher, but that it also saw "a bit of
softness" in that price as well. He urged that PFC Energy
was not forecasting that oil prices would be $400 or $500
per barrel.
9:29:20 AM
Senator Thomas inquired if revenue was considered a cost in
the chart on page 10. Mr. Kepes responded that Alaskan
state revenues were not considered on the chart and that
the chart's costs reflected capital expenditures.
Co-Chair Stedman interjected that the costs on slide 10
were aggregate numbers. Mr. Kepes responded that Co-Chair
Stedman was correct and pointed out that PFC Energy's
databases covered the entire industry and examined global
costs in aggregate. He reiterated that the numbers
represented an aggregate amount and that there would be
specific areas where costs did not increase as much, as
well as areas where costs increased at a higher rate.
Mr. Kepes discussed the slide on page 13 titled "cost
assumptions underlying fiscal analysis."
· Two key forms of analysis have been undertaken on
project economics and government take levels in
this presentation
· Existing Producer Analysis examines the economics
of the fiscal regime for an existing producer,
producing 200 mb/d in 2012, with a 6% annual
production decline rate, and with the following
costs:
· $12/ flowing bbl operating expenditure
· $5/ flowing bbl maintenance capital
expenditure
· New Development Analysis examines the
development-forward lifecycle economics of the
fiscal regime for the development of a new 10
mb/d development for a producer without existing
base production. Assumed costs are:
· $17/ flowing bbl operating expenditure
· $17/bbl reserves development capital
expenditure
· $1/ flowing bbl maintenance capital
expenditure
Mr. Kepes related that the cost figures for the existing
producer analysis were germane to Co-Chair Stedman's
earlier question regarding how "conventional" Alaskan oil
would compare to other sectors on slide 11. He explained
that the costs in Alaska for the existing producer analysis
on slide 13 were lower than the costs for the viscous and
new conventional oil on slide 11.
9:32:16 AM
Co-Chair Stedman asked for a definition of "flowing oil."
Mr. Kepes responded that flowing oil referred to the cost
of a barrel of oil in production; it was exclusive of other
cost factors outside of production and was specific to a
field actually producing.
Mr. Kepes continued to speak to slide 13 and related that a
production level of 10,000 barrels per day (bbl/d) would be
indicative of a 65 million to 75 million barrel field. He
furthered that the costs associated with the new
development analysis were substantially higher than the
costs in the existing producer analysis. The new
development analysis examined new developments that were
away from existing infrastructure and did not include
activities like infill drilling.
Mr. Kepes shared that the next four slides simulated the
existing producer and new development scenarios for the
Alaska's Clear Equitable Share (ACES) and the Petroleum
Production Tax's (PPT) tax regimes, both as proposed and as
enacted.
Mr. Kepes explained the slide on page 14 titled "PPT as
originally proposed (existing producer)" and related that
the slide showed an analysis of PPT as it was originally
proposed. He discussed the graph on the top left hand
corner of the slide and stated that it was based on an
existing producer that was producing 200,000 bbl/d. The
black line represented the "after tax cash flow." He
referenced the table in the upper middle portion of the
slide and stated that "PPT as originally proposed" had a
net present value (NPV) of just over $20 billion at an oil
price of $100 per barrel. He observed that the larger table
to the right showed that the government take reached about
60 percent through the intermediate price ranges. He
reiterated that the slide examined PPT as originally
proposed, under the existing producer scenario.
Mr. Kepes discussed the slide on page 15 titled "PPT as
enacted (existing producer)" and stated that it showed an
analysis of PPT as it was enacted, under the same producing
scenario as the previous slide. He switched back and
forward between slides 14 and 15. He noted that under "PPT
as enacted", the government take was 72 percent to 74
percent compared to the 60 percent government take figure
from slide 14. He related that the NPV on slide 15 was
approximately $17 billion and that it had decreased by
about $3 billion over the lifetime of the field in
comparison to the NPV on slide 14. He concluded that there
could be differences in how a fiscal system was proposed
and how it was enacted.
9:36:08 AM
Mr. Kepes explained the slide on page 16 titled "ACES as
proposed (existing producer)" and stated that it showed an
analysis of ACES as it was proposed, under the same
producing scenarios as the two previous slides. "ACES as
proposed" generated a NPV of $6.6 billion and had a
government take ranging from 68 percent to 74 percent.
Mr. Kepes discussed the slide on page 17 titled "ACES as
enacted (existing producer)" and stated that it showed an
analysis of ACES as it was enacted, under the same
producing scenarios as the three previous slides. "ACES as
enacted" had government take of 75 percent to 83 percent
and a NPV of about $4.5 billion; the NPV had declined by
about $1.5 billion from the NPV in the previous slide.
Mr. Kepes explained the slide on page 18 titled
"limitations on price upside: a probabilistic approach." He
stated that the slide showed PPT as proposed, PPT as
enacted, ACES as proposed, and ACES as enacted for existing
base production, under the same producing scenarios as the
four previous slides. He stated that ACES as enacted was
represented by the dark blue line and related that it was a
progressive tax regime. The red bar graph on the bottom of
the slide forecasted the probability of oil prices being
within $30 per barrel to $230 per barrel over the lifetime
of the field. He observed that PPT as originally proposed,
which was represented by the dark yellow line, was neutral
in terms of progressivity. He stated that changes to PPT
and subsequent changes to ACES had generated more
progressive tax regimes, which had a higher government take
at higher oil prices.
9:38:41 AM
Co-Chair Stedman asked for a definition of "EV". Mr. Kepes
replied that EV was the expected value of all future cash
flows for the listed projects, under the listed producing
scenarios. He further explained that the EV would be
reflective of all aggregated cash flows that were generated
over a 30 year period.
Co-Chair Stedman observed that the EV for PPT as proposed
was $22.862 billion and that the EV for ACES as enacted was
$14.988 billion; he noted the difference between the two
figures and inquired where the missing funds were going.
Mr. Kepes replied that the money went to the State of
Alaska and the federal government and clarified that the EV
on the slide represented the values for the investing
consortium.
9:40:08 AM
Mr. Kepes discussed the slide on page 19 titled
"limitations on price upside: a probabilistic approach." He
explained that the previous slide was based on an existing
producer that was producing 200,000 bbl/d; however, slide
19 represented a new development, which was producing
10,000 bbl/d in a 65 million to 75 million barrel field. He
noted that a new development would have higher associated
costs and reiterated that the EV was reflective of the
values to the investment consortium. Under this scenario,
PPT as proposed would generate an EV of $236 million in
comparison to the $12 million EV that would be generated by
ACES as enacted. He stated that a higher government take
was occurring at higher oil prices because of the
progressivity of the ACES fiscal regime; furthermore, a new
development existed in a "much higher" cost environment.
Mr. Kepes explained the slide on page 20 titled "ACES
impact on oil-price upside, and on high cost development
economics." The slide examined how ACES impacted the upside
to high oil prices, particularly regarding high cost
development economics. He reiterated that Alaska was a high
cost environment. He referenced the overall cost increases
to the industry at large and offered that it was
appropriate to look specifically at the high cost
development economics regarding new development production
scenarios. He noted that a new development was based on a
production level of 10,000 bbl/d in a 65 million to 70[75]
million barrel field. Under this scenario, a new
development in the ACES regime, which was reflected by the
dark yellow line, achieved a positive NPV at an oil price
of $100 per barrel; a project like this would presumably
not be pursued when the price was under $100 per barrel
because the conditions made it uneconomic. He pointed out
that the profitability of base production under ACES, which
was reflected by the dark red line, was much higher than
the profitability of a new development under ACES. He
pointed out that the dotted blue and green lines showed a
representation of possible changes to the ACES
progressivity structure and that the two lines showed the
high impact of the changes to the project economics of a
high cost investment scenario. He concluded that under
ACES, the base production on the North Slope was attractive
and profitable, but that there was an issue of higher costs
in new developments.
9:44:43 AM
Mr. Kepes related that the next section of slides examined
the global competitiveness of ACES and offered that the
state needed to be aware that the market for E&P investment
dollars was global.
Mr. Kepes discussed the slide on page 22 titled "regime
competitiveness: average government take." He stated that
slides 22 through slide 25 showed the average and marginal
government takes at an oil price of $100 per barrel and
$140 per barrel of oil.
Co-Chair Stedman asked for a brief explanation of where PFC
Energy had received the data for slide 22. He explained
that there were similar presentations, which used data that
did not include production tax. He pointed out the
importance of knowing what information was in the slides
and where the data had come from. Mr. Kepes replied that
the data came from PFC Energy's global databases, which PFC
Energy had been constructing for over 25 years. He stated
that PFC Energy's slides differed from other presentations
the committee had seen, both in the specificity of the
fiscal structures and the specificity of the opportunity
sets in the localities in question. He further explained
that a similar analysis might use a generic size field to
calculate the returns or government takes in 60 different
government jurisdictions. He offered that an analysis that
applied a generic, 100 million barrel field in a fiscal
system and region like New Zealand, where the field size
was closer to 10 million barrels, did not generate useful
comparative knowledge. He concluded that PFC Energy's
analysis used field sizes that were specific to the target
locations; furthermore, the fiscal system estimates were
inclusive of property taxes, costs, and other parts of the
government take structure that were particular to that
jurisdiction.
Co-Chair Stedman stated that there had been confusion
during previous presentations regarding the inclusion or
exclusion of private royalties in calculations and asked
for a clarification regarding how PFC Energy calculated
royalties. Mr. Kepes responded that in all cases, PFC
Energy included royalties in its calculations. Even when a
royalty accrued to private land owners, PFC Energy
considered it part of the government take because the
royalty was not available to the investment consortium. He
pointed out that in most of the world, very little oil and
gas production was taking place on private land and that
the onshore Lower 48 was unique in that respect; 97 percent
of shale play production activity in the U.S. was on
privately held land. He concluded that the matter of
private royalties was a "big issue", but that it mostly
applied to the onshore Lower 48.
9:50:09 AM
Mr. Kepes continued to discuss slide 22 and stated that it
showed the costs, field sizes, and fiscal tax structures
that were specific to the localities; the slides did not
input generic field sizes or generic costs. He offered that
PFC Energy's method gave a better measure of what actually
occurred in the jurisdictions. He pointed out that the
Organisation for Economic Co-operation and Development
(OECD) countries were labeled in yellow. He noted that OECD
countries generally had a lower government take, while non-
OECD countries tended to have a higher government take. He
commented that oil and gas tax policies differed in design;
some policies were designed to generate revenues for a
government, while some were structured to provide energy
"feedstocks" for an economy.
Mr. Kepes continued to speak to slide 22 and stated that it
showed, at a price of $100 per barrel, the government take
of the ACES Alaskan new development and existing producer
scenarios relative to other tax regimes around the world.
He added that the field sizes and production levels for the
specific Alaskan scenarios were as outlined in previous
slides.
9:52:17 AM
Co-Chair Stedman pointed out that there had previously been
work done that compared Alaska to other tax regimes and
mentioned in particular a comparison to the North Sea. He
observed that at an oil price of $100 per barrel, Norway
had a slightly higher government take than the Alaskan
existing producer scenario, but that the two regions were
pretty close in that respect. Mr. Kepes replied that Co-
Chair Stedman was correct and that Norway was directly in
the middle in terms of government take relative to the
Alaskan existing producer and new development scenarios.
Co-Chair Stedman furthered that there had been prior
testimony indicating that the government take for existing
production should range from 70 percent to 75 percent, and
pointed out that the existing producer scenario on slide 22
was at government take of 73 percent. Mr. Kepes commented
that Norway was a standout in comparison to other OECD
countries because it had two national oil companies that
held equity stakes in oil and gas production and that as a
result, Norway was generating additional income via the
national oil companies. He added that the revenue generated
via Norway's nationally owned oil companies was not
included with the government take on slide 22. He pointed
out that there were other factors at play that were not
reflected in the slide and that aspects such as
competiveness, the number of operating investors, or the
participation of nationally owned companies were not
represented.
Co-Chair Hoffman queried why the slide did not show the
existing producer and new development scenarios for other
countries, such as Norway. Mr. Kepes responded that PFC
Energy had the requested data and could provide it in the
future.
9:55:26 AM
Co-Chair Stedman requested that PFC Energy provide the
committee with a slide that reflected existing production
scenarios and another slide that showed new development
scenarios. Mr. Kepes responded that PFC Energy could run
the separate slides based on 200,000 bbl/d and 10,000 bbl/d
of production, but that the information generated might not
be very applicable. He related that in some cases, within
specific localities, there were no 200,000 bbl/d fields; in
other instances, a 10,000 bbl/d field would not be
economic. He stated that in the case of the Norwegian
operating environment, a 10,000 bbl/d field would not be
economic as a stand-alone development. He offered that
using the exact same field sizes as the Alaskan scenarios
would generate a less applicable analysis. He concluded
that PFC Energy could design a specific analysis that was
appropriate to the localities, which would more closely
reflect the reality on the ground. Co-Chair Stedman
observed that the committee wanted the information that was
presented to be "as reality based as possible."
Co-Chair Stedman asked for an explanation of how PFC Energy
factored in very small oil wells, such as stripper wells in
Texas. Mr. Kepes replied that the U.S. probably had the
most complex sets of applicable tax regimes due to the
nexus between private, federal, and state lands. He added
that regarding stripper wells, fiscal terms on private
lands were often were more stringent for investors than the
terms on public lands. He noted that King Ranch, Texas
consisted entirely of privately held land and that the
region might have a government take in excess of 50 percent
or 60 percent. He concluded that typically, fiscal terms on
private lands were higher than the terms on federal or
state lands.
9:59:00 AM
Senator Egan asked how a small well for an Alaska existing
producer would compare to the other localities on the
slide. Mr. Kepes referred back to slide 20 and replied that
a small well in Alaska would probably be in the form of an
infill well, which was tied to existing infrastructure and
was not a stand-alone development. He furthered that a
smaller well in Alaska could also be in the form of an
older well that was reentered or reconstructed. He
explained that some of the original producing wells were 35
to 40 years old and that the producers sometimes reused
these wells with "coiled tube" drilling rigs, which had a
lower operating cost; He added that for an Alaska existing
producer, these types of projects were relatively
profitable and would generate a government take of around
70 percent as implied on the slide's dark red line.
Mr. Kepes continued to speak to slide 20 and pointed out
that investing in existing production, infill drilling, and
replacing old wells were very profitable activities for
companies. He concluded that under ACES, investing in
existing infrastructure was "quite profitable", but that
the challenge was the higher cost of new production in
Alaska.
10:02:01 AM
AT EASE
10:07:52 AM
RECONVENED
10:08:09 AM
Mr. Kepes explained the slide on page 23 titled "regime
competiveness: average government take." He stated that the
slide examined the average government take of different
regimes at $140 per barrel. He related that under this
analysis, both the ACES new development and ACES existing
producer scenarios had gone up in government take relative
to the other regimes on the slide. He observed that both of
the ACES scenarios had a higher government take than Norway
on the slide.
Mr. Kepes discussed the slide on page 24 titled "regime
competitiveness: marginal government take." He related that
slide showed the marginal government take, which examined
the difference in government or investor take when the
price of oil increased $1 per barrel. On a marginal take
basis and an oil price of $100 per barrel, the ACES new
development and ACES existing producer scenarios were even
higher [when compared to the average government take],
relative to the other jurisdictions on the slide.
Co-Chair Stedman referenced comments that were made in a
prior presentation, which had indicated that Argentina had
a 100 percent marginal government take at an oil price of
$60 per barrel or over. He requested Mr. Kepes to comment
on Argentina and inquired why companies would invest there.
Mr. Kepes replied that as a result of export tariffs and
other more complicated factors, Argentina had created an
environment where very little investment was occurring. He
explained that the 100 percent marginal government take in
Argentina maximized efficiency from a government take
perspective, but that it resulted in a non-competitive
environment with "almost no investment." He noted that
there were political battles currently occurring in
Argentina over the issue of its high marginal government
take.
10:11:14 AM
JANAK MAYER, MANAGER, UPSTREAM & GAS, PFC ENERGY,
WASHINGTON, D.C. (via teleconference), stated that a
particular aspect of Argentina's tax structure that was
peculiar to the country was its export tax; the tax limited
exported oil to a specific maximum price level. He
concluded that investing in Argentina's export tax regime
was "very undesirable" and noted that there had been a
corresponding impact on investment levels in the country.
Co-Chair Stedman observed that there seemed to be a
relationship between the prospectivity of regional basins
and how jurisdictions' tax structures were organized. He
noted that Ireland was at the bottom of slide 24 and
inquired how much oil Ireland had. Mr. Kepes responded that
Ireland did not have "much oil" and explained that
prospectivity was not well represented on the slide. He
stated that generally, the lower government take systems
existed in jurisdictions where prospectivity was low. He
explained that governments with low prospectivity oil
basins had to offer "some of the best fiscal terms
available to investors on the planet" in order to attract
more investment. He stated that there had been no
commercial production to date in Greenland's frontier play.
He pointed out that in Greenland, despite the high cost
environment, a single company had been attracted to the
very low government take and had drilled seven "dry holes"
offshore. [dry hole: An exploratory or development well
found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or
gas well]
Mr. Kepes concluded that generally, higher government take
regimes had substantial known reserves or high
prospectivity; at a minimum, higher government take systems
had known or existing commercial production.
Mr. Kepes discussed the slide on page 25 titled "regime
competitiveness: marginal government take" and stated that
it showed the marginal government take of the global fiscal
regimes at a price of $140 per barrel of oil.
Co-Chair Stedman noted that there had been claims that
Alaska's government take was the highest in the world and
inquired if that was true. Mr. Kepes responded that Alaska
did not have the world's highest government take and that
Turkmenistan had the highest government take on slide 25.
10:15:47 AM
Mr. Kepes stated that slides 26 and 27 examined another way
of looking at progressivity and that the slides showed the
marginal government take minus the average government take
for the same regimes that were in previous slides.
Mr. Kepes explained the slide on page 26 titled
"benchmarking progressivity for a range of global regimes."
He noted that at an oil price of $100 per barrel, Columbia
was at the top of the slide and was a highly progressive
regime in terms of the impact of higher prices on
government take. He pointed out that the ACES existing
producer scenario was just underneath Columbia on the
slide.
Co-Chair Stedman queried if the regimes on the bottom half
of the slide were regressive systems, in which the
government takes went down as prices went up. Mr. Kepes
responded in the affirmative and added that in a regressive
system as oil prices went up, a larger proportion of the
divisible income when to the investor.
10:17:08 AM
Co-Chair Stedman asked if the state could manipulate the
upper part of the graph by changing the base tax rate and
the slope. He further inquired if decreasing the state's
progressivity, increasing its base tax rate, and keeping
its cash flow the same would "shorten those bars" and drive
the progressivity closer to zero. Mr. Kepes replied in the
affirmative and offered that Janak Mayer might have
comments to add.
Co-Chair Stedman asked if Mr. Mayer had any comments on
slide 26. Mr. Mayer replied that Columbia was a progressive
regime, but that it was progressive on a much lower base
rate of government take. He referenced previous slides, in
which Columbia was in the bottom half of global fiscal
regimes in terms of government take. He offered that just
looking at progressivity was only one part of the equation
and that progressivity in relation to the basic level of
government take was a critical factor to examine. He
concluded that in contrast to OECD countries, Alaska's
regime had a relatively high government take and had a
significant progressivity feature.
Co-Chair Hoffman stated that the committee was trying to
encourage new development and new oil in the pipeline. He
noted that there was a large cost spread between new
developments and existing producers under ACES and queried
if the same disparity between the two scenarios existed in
other oil producing countries.
Co-Chair Stedman asked PFC Energy to include the requested
information in future slides that it was preparing for the
committee.
Mr. Mayer stated that the disparity in costs between
existing developments and new production was particularly
important for Alaska due of the impact of the deductibility
of capital expenses and the production tax credit. He
clarified that a new producer had no prior production and
that as a result, new developments did not have a
production base against which to write-off capital credits
or net operating loss credits. He offered that the
inability to use the deductions was the principle reason
why the government take was significantly higher in
Alaska's new developments than with existing production. He
added that the difference in progressivity between new and
existing producers was a result of the actual government
take being higher for new developments, while marginal
rates stayed the same for both new and existing producers.
10:20:52 AM
Mr. Kepes spoke to the slide on page 27 titled
"benchmarking progressivity for a range of global regimes"
and stated that it showed the same analysis as the previous
slide, but at an oil price of $140 per barrel; under this
analysis, Turkmenistan had the highest progressivity. He
pointed out that a "big take away" from slides 26 and 27
was that all of the Lower 48 regimes were regressive
regimes and that when the price of oil went up, more of the
divisible income in the Lower 48 went to the investor
consortium.
Co-Chair Stedman commented that Alaska differed from other
jurisdictions in its land ownership and tax structure. He
furthered that it was his understanding that that most of
North America had a tax and royalty system, while Alaska
had a hybrid system of tax and royalty, plus a concession
system. Mr. Kepes responded that Co-Chair Stedman was
correct.
Co-Chair Stedman requested a clarification of the
differences in land ownership and tax structure between
Alaska and the Lower 48.
Mr. Kepes stated that 97 percent of the shale play
activities in the Lower 48 were on privately held land and
that each of the private land holdings could have a
different fiscal structure. He pointed out that private
land owners did not offer capital credits and did not
incentivize companies to make large investments. Many of
the investments were incremental for smaller, privately
held tracks; investments under this scenario might be
spread out over a large area of land, a long period of
time, and involve multiple land owners. He explained that
Alaska had a concession system, while the Lower 48 had
leases that were conditional and had a shorter time frame.
He stated that lease holds in the Lower 48 had conditional
language, which specified that investment had to take place
within a certain period of time or the lease would revert
back to the land owner; relinquishment provisions were in
place to insure asset liquidity and require companies to
invest. He concluded that the nature of the duration of
lease hold agreements in the Lower 48 were different than
the concession agreements in Alaska. He noted that the size
of the leases in the Lower 48 were usually smaller than the
leases in Alaska. He explained that in the case of
Louisiana's private land holdings, there might be hundreds
on land owners involved in a play that was similar in size
to the "footprint for the North Slope."
Mr. Kepes addressed the slide on page 28 titled "ACES -
effective as a harvest area fiscal 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)
· 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
10:26:19 AM
Senator Thomas noted that the production decline had been
in place prior to ACES being enacted, but that ACES had
been blamed for the lack of investment. He observed that
prior to ACES, concerns had already been raised over the
age and constraints of the facilities in Prudhoe Bay, "as
well as the pipeline situation that has arisen." He
furthered that the industry might have been looking at
projects that were aimed at reversing the decline around
the same that ACES was enacted and inquired whether ACES
had unfortunate timing. Mr. Kepes replied that he was not
in a position to comment on the political process at the
time. He offered that the natural rate of production
decline on the North Slope was roughly 15 percent a year
and that quite a bit of capital was spent to maintain a 6
percent rate. A lot of capital was going towards replacing
old infrastructure, some of which was over 30 years old. He
furthered that significant capital was being used for
things that did not generate new production, but that
maintained the decline rate. He stated that the question
was whether Alaska wanted to increase production above a 6
percent rate of decline.
Mr. Kepes responded to Senator Thomas' second question and
stated that there was a timing issue involved. He pointed
out that much of the capital equipment on the North Slope
was 35 years old and needed to be replaced. He stated that
another timing aspect was the age of the North Slope Basin;
as the basin ages, the opportunities in the field become
higher cost and more limited. He furthered that
improvements in production technology and maturing
resources had resulted in a different investment picture
for Alaska. He pointed out that the investment
opportunities had also changed throughout the world and
that there was a "massive shift of capital" from West
Africa and Alaska to the Lower 48. He offered that the
shift in capital was a "driver" that was not present 10
years ago. He concluded that timing was an issue and that
he "would not conclude that ACES was responsible for
everything." He offered that ACES was a very appropriate
regime for an area in harvest mode. He observed that under
ACES, the government was getting a higher percentage for
every barrel that was being produced and that the industry
was making profit on existing production. He added that
without respect to the long-term impacts of the production
decline, ACES was working for the state and remained
profitable for industry. He stated that ACES worked well in
a harvest area situation. He offered that the question
facing the state was whether it wanted a different result
and how the system could be changed to encourage growth.
10:34:13 AM
Co-Chair Stedman related that he had directed the
Legislative Finance Division to prepare historical data of
Alaska's oil basin for PFC Energy and that there would be a
presentation in the committee based on the data; the
presentation would determine the value of the basin, the
funds that had gone to the state from the basin, as well as
a rough calculation of what the government share had been.
He furthered that in the future, there would also be a
presentation that would parcel out the current production;
the presentation would show the increment that was being
spent to keep the North Slope's natural decline rate of 15
percent at the current rate of 6 percent and would
identify, relative to current production, what was needed
to move the decline rate to minus one percent, zero
percent, or plus one percent. He pointed out that there
would be a discussion on policy after the committee had
seen the two presentations. He noted that the current
presentation was "laying the foundation" and that the
committee would look at the subject matter in greater
detail at a later date.
Co-Chair Hoffman referenced the bullet point on the lower
half of slide 28 and inquired if Mr. Kepes had any
recommendations to address ACES' inhibitions on developing
new projects. He queried if there should be a different tax
structure for new projects. Mr. Kepes replied that the
different ways to approach the issue were laid out in later
slides, but that PFC Energy had not made a specific
recommendation yet.
10:37:23 AM
Co-Chair Stedman pointed out that he had provided PFC
Energy with the packet on the "tax holiday", which Senator
Wagoner had worked on in the Senate Resources Committee. He
noted that PFC Energy was currently working on
incorporating the tax holiday document and the "$10
allowance", which was in the current version of SB 192,
into future models. He furthered that the substance of the
current bill, options from committee members, options from
the Senate Resources Committee, and new ideas from PFC
Energy would all be considered. He concluded that the
committee would be open for concept discussions and that
the discussions would be "a subject in and of itself" in
hearings.
Mr. Kepes observed that PFC Energy had not yet completed
its analysis on the "gross minimum tax", but that it had
completed its analysis on the "$10 dollar, new oil
allowance." Co-Chair Stedman stated that the "floor"[in
reference to the gross minimum tax] subject matter was in
flux, and that changes within the system had a
corresponding impact on the floor. He offered that the
floor would probably be one of the last items that the
committee would work on.
Mr. Kepes continued to speak to slide 28. He stated that
the slide depicted the ACES base production in the dark red
and the ACES new developments in the dark yellow. The slide
compared the progressivity in ACES to progressivity of a
neutral and a regressive 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)
· 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. Kepes noted that the dark yellow line suggested that a
new development under ACES, which was based on 10,000
barrels per day of production in a 65 million barrel field,
broke even at $100 per barrel.
10:43:38 AM
Mr. Kepes discussed the slide on page 29 titled "options to
spur new developments." He stated that PFC Energy had laid
out three broad approaches to encourage new developments,
under the assumption that ACES had challenges regarding
higher cost, new developments. He observed that each
approach had its advantages and disadvantages.
· Approach: Uniform lowering of Government Take
· Implementation Options: Bracketing,
Reduced base rate, Increased
progressivity thresholds, Reduced
progressivity rates, and Progressivity
caps
· Advantages: Does not require increased
complexity of the fiscal structure, May
not present opportunities for
simplification
· Disadvantages: Incentivizing new high
cost resources through this method alone
requires giving substantial "rent" back
to producers on the mature producing
assets
· Approach: differentiation between old and new
production
· Implementation Options: Allowance for
new oil, Switching in part away from net
profits taxation to gross revenue taxation
to enable different tax rates for
different production streams without
separate cost accounting and tax returns,
and the use of some combination of
definitions for incremental production
above the base decline rate(regulator-
agreed new programs and new areas)
· Advantages: Allows significant
reductions in government take on new and
costlier developments (including heavy
oil etc.) without requiring significant
reductions on mature and producing assets
· Disadvantages: Administrative
difficulties around definitions of "new
production"
· Approach: enhancements to cost progressivity of
ACES
· Implementation Options: Changes to
allowable cost deduction or credits
mechanism etc. to provide greater
"uplift" for high capital and operating
costs while restricting negative
production tax in marginal cases,
Enhancement to royalty relief
· Advantages: Does not require structural
changes away from ACES
· Disadvantages: Increases already high
complexity and opacity, May exacerbate
problem of poor cost control
incentives, Increases likelihood of
unintended consequences, Likely less
significant impact than new production
differentiation.
Mr. Kepes discussed the advantages of the first approach on
the slide and related that more complex fiscal structures
are not generally to the advantage of governments. He
furthered that it was PFC Energy's global experience that
companies invested what was needed in order to understand
the complexity of the fiscal terms that existed. He
explained that a company generally had a better capacity to
understand and manage its side of a complex fiscal regime
than the government had capacity to administer the system.
He shared that enhancements to royalty relief, which was an
option under the third approach, could be granted on an
"investment by investment basis" for higher cost
developments.
10:49:34 AM
Co-Chair Stedman requested a definition of "uplift." Mr.
Kepes responded that uplift was often part of a cost
recovery or credits mechanism and explained that it meant
that a company received a higher credit realized for each
$1 of capital that was spent. He offered that if a company
spent $2 billion, an uplift mechanism on costs might be
that for every $1 spent, the company received tax credits
or advantages that were worth $1.20; the 20 cents on the
dollar is a uplift. He stated that there were cost or
capital uplifts in other fiscal environments and that the
uplifts were usually part of production sharing mechanisms.
Mr. Mayer added that uplift gave credits, such as the
capital credits under ACES, as a mechanism for making a
fiscal regime more progressive with regards to costs.
Mr. Kepes continued to speak to slide 29. He discussed the
second disadvantage of the third approach and clarified
that an entity was not getting the targeted impact of
granting credits if it was unsure what the credits would be
used for. He spoke to the third disadvantage of the third
approach and related that it was not good to have a system
that rewarded high cost operators or operators who may not
be as focused on cost control as others; a system like this
could result in investments being made that might not have
occurred otherwise.
10:53:54 AM
Senator McGuire requested that amendment B.7, which was
from the Senate Recourses Committee, be included the next
time PFC Energy presented models to the committee. She
specified that the amendment would make the HB 110 approach
of bracketing and reducing the progressivity rate apply
only to new production. She requested advice from PFC
Energy on how to define new production.
Co-Chair Stedman stated that PFC Energy was going to do an
analysis on progressivity and that bracketing would be a
discussion item. He referenced that there were at least two
amendments in the Senate Resources Committee and that there
were a number of ways to approach bracketing. He noted that
future presentations would examine the effects of slope
changes, base tax adjustments, and triggers. He furthered
that the presentations would not be in the direction of the
bill in front of the committee, but that the committee
would look at all of the options. He offered that
presentations might cover something that was already in the
bill, something that was changed, or might be a whole new
concept. He added that he had already met with PFC Energy
regarding the direction of future discussions and that "at
the end of the day," the state needed to make sure it was
counting its net cash flow. He referenced earlier comments
regarding the producers' high level of sophistication and
related the importance of the state understanding its own
fiscal regime.
10:56:23 AM
Senator Thomas asked for a clarification on slide 28. He
referenced the "renewal capex" on the slide and the
increased exploration activity that was currently occurring
on the North Slope. He queried what the likelihood was of a
sophisticated oil company making significant investments,
without understanding the existing tax system in Alaska.
Mr. Kepes requested a clarification of the question.
Senator Thomas inquired why Alaska would see increased
activity from companies that had opportunities elsewhere
around the world. He furthered that some companies had
claimed that they did not fully understand Alaska's tax
system at the time, but that companies had still purchased
or leased large tracks of land and had made significant
investments; he inquired if this scenario seemed likely.
Mr. Kepes offered that there were one or two cases where
companies were not fully aware of the commercial
arrangements that were required to commercially develop
reserves, at the time they took the exploration licenses.
He opined that the exploration tax credits and incentives
for exploration within ACES make it "appear to be a
reasonably attractive proposition." He stated that the
comments on slide 28 were not offered with respect to the
exploration activities that Senator Thomas was referring
to. He noted that companies had been attracted to the
incentives for exploration activity under ACES. He observed
that if an explorer made a 65 million barrel discovery, the
challenge to the company became how it would tie that
production into existing infrastructure and what commercial
arrangements needed to be made with the existing operator
of the evacuation infrastructure; furthermore, commercial
arrangements like this could be an unknown in terms of
costs and could be less attractive than more apparent
aspects. He furthered that it could be difficult to
calculate commercial development costs during an initial
exploration decision and offered that these unknown costs
could change a 65 million barrel success into a sub-
marginal economic investment. He pointed out that the major
and independent oil companies had different investment
criteria and that they might take different types risks. He
offered that it was possible that a company would invest in
a project that offered a lower return because it believed
that subsequent opportunities would be more profitable. He
concluded that a company not understanding what it was
getting into can and does happen. However, in reference to
the situation that Senator Thomas had inquired about, he
opined that the companies had less of an understanding of
what it took to be commercial success versus an exploration
success because of the "access to infrastructure issue."
SB 192 was HEARD and HELD in committee for further
consideration.
ADJOURNMENT
11:02:32 AM
The meeting was adjourned at 11:02 AM.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 192 031512 PFC Energy Presentation.pdf |
SFIN 3/15/2012 9:00:00 AM |
SB 192 |