Legislature(2005 - 2006)SENATE FINANCE 532
04/10/2006 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB305 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 305 | TELECONFERENCED | |
| + | TELECONFERENCED |
CS FOR SENATE BILL NO. 305(RES)
"An Act providing for a production tax on oil and gas;
repealing the oil and gas production (severance) tax;
relating to the calculation of the gross value at the point
of production of oil or gas and to the determination of the
value of oil and gas for purposes of the production tax on
oil and gas; providing for tax credits against the tax for
certain expenditures and losses; relating to the
relationship of the production tax on oil and gas to other
taxes, to the dates those tax payments and surcharges are
due, to interest on overpayments of the tax, and to the
treatment of the tax in a producer's settlement with the
royalty owners; relating to flared gas, and to oil and gas
used in the operation of a lease or property under the
production tax; relating to the prevailing value of oil or
gas under the production tax; relating to surcharges on
oil; relating to statements or other information required
to be filed with or furnished to the Department of Revenue,
to the penalty for failure to file certain reports for the
tax, to the powers of the Department of Revenue, and to the
disclosure of certain information required to be furnished
to the Department of Revenue as applicable to the
administration of the tax; relating to criminal penalties
for violating conditions governing access to and use of
confidential information relating to the tax, and to the
deposit of tax money collected by the Department of
Revenue; amending the definitions of 'gas,' 'oil,' and
certain other terms for purposes of the production tax, and
as the definition of the term 'gas' applies in the Alaska
Stranded Gas Development Act, and adding further
definitions; making conforming amendments; and providing
for an effective date."
This was the ninth hearing for this bill in the Senate Finance
Committee.
9:04:03 AM
Co-Chair Green communicated that the purpose of today's hearing
was to conduct a question and answer session regarding the
proposed Petroleum Profits Tax (PPT) legislation. A listing of
17 issues was distributed [copy on file]. The question and
answer panel consisted of representatives of ConocoPhillips,
Chevron, British Petroleum, Anadarko Petroleum Corporation,
Marathon Oil, and industry and State economic consultants.
Co-Chair Green communicated that the panelists would not be
required to individually respond to each question. Instead the
goal was to gleam "new ideas" and/or determine areas of
agreement.
Issue 1. The impact on exploration, investment and
production at various proposed tax rates and credit rates
(15% - 30%). Discuss the relationship between tax and
credit to identify the best balance.
Co-Chair Green identified the percentage levels of the severance
tax and credit rates and their affect on exploration, investment
and production in the State as being the most important
component of the PPT legislation.
MARIANNE KAH, Chief Economist, ConocoPhillips, agreed that the
tax rate was the most important component of the bill. The
adoption of an inappropriate PPT tax rate might jeopardize a
company's growth plans. Companies have voiced their concerns in
this respect. To that point, she "resented" the Fairbanks Daily
News Miner newspaper's portrayal that ConocoPhillips was
utilizing "terrorist tactics" in this regard as the company was
"legitimately concerned". The company, which has operated in the
State for more than 50 years, was the leading resource investor
in the State. The PPT tax rate level could either incentivize or
disincentivize investment.
Ms. Kah stressed that the PPT tax rate must "be commensurate
with the prospectivity and cost structure" of the State. The
cost structure of resource fields in Russia could be comparable
to Alaska because they too experienced arctic conditions. Even
though Russia's tax structure was high, ConocoPhillips could
afford to operate there due to the economic value provided by
the immense field sizes. In addition, large resource companies
like ConocoPhillips and British Petroleum (BP) "are buying into"
private Russian companies because they had access to 16 percent
of the world's oil resources. The prospectivity of the area and
resource access are two reasons investments have occurred there.
In contrast, Alaska's oil fields were smaller. "That would be
fine, but the tax rate needs to be reflective of that."
Ms. Kah noted that ConocoPhillips recently resumed its Libyan
operations "under the same terms" in place in 1986 when it was
"forced to leave because of U.S. sanctions". That field
contained 25 percent of the country's oil production. Libya has
a huge amount of known and undiscovered resources. For that
reason, ConocoPhillips was a participant "in these big rounds
that are coming out with really fairly outrageous tax terms".
Ms. Kah cited there being "a lot of exuberance in our markets
now: exuberance by investors who are willing to bid away all
their profits; exuberance by government who are trying to tax
away profits". This was worrisome as it was "making it
impossible for serious long term investors to invest in this
business on a sustained basis".
Ms. Kah noted that while ConocoPhillips wanted to continue
investing in the State, the 20 percent tax rate and 20 percent
credit (20/20) provisions included in SB 305, the original
version of the PPT as proposed by Governor Frank Murkowski, "was
something that we really had to swallow hard to agree to". The
State's current Economic Limit Factor (ELF) severance tax regime
would equate to a 15 percent tax rate under a progressive tax
regime structure. The company agreed to the 20 percent tax rate
in SB 305 because of their desire to further the separately
proposed North Slope gas pipeline project.
ANGUS J. WALKER, Vice President, Commercial, British Petroleum
Exploration Inc. Alaska, presented BP's perspective on the
resource situation in the State. Production was declining at an
annual rate of six percent. In ten years, North Slope production
would be approximately 450,000 barrels per day, were current
investment levels maintained. This forecast also depended on
"the big assumption" that the proposed PPT would not be
detrimental to investments in the State.
Mr. Walker pointed out, however, that in order to allow the
proposed North Slope gas pipeline to become sustainable, the
State was actually seeking to "extend the life of its oil fields
through the year 2050". BP estimated that, "in order to meet the
Department of Revenue's (DOR) latest production forecast,
investment in the North Slope" must double to approximately
three billion dollars a year.
Mr. Walker communicated that "the lowest possible tax rate"
would attract "the most possible investment". "A zero tax rate
would be best." A 15 percent tax with a 25 percent credit would
be preferred to the 20/20 tax rate proposed in SB 305. The tax
rate proposed in SB 305 would be preferred to either of the
tax/credit rates proposed in the House or Senate PPT committee
substitutes.
9:11:18 AM
DAN DICKINSON, CPA, former Director of the Tax Division, secured
as a consultant by the Office of the Governor, appreciated Ms.
Kah's determination that "the tax rate was probably one of the
most important aspects" because he would like to emphasize the
credit components proposed in the Senate committee substitute,
CSSB 305(RES). [Note: CSSB 305(RES) is referred to as CSSB 305
in these minutes] While he and Mr. Walker might disagree with
the numbers, "there is no question that to get the kind of
volumes we all hope to see, significant investments are required
in the State." For that reason, CSSB 305 would allow "a 20
percent credit for those investments as well as the allowance of
a 20 percent deduction". Qualifying capital investments would be
"underwritten by a 40 percent support by the State of Alaska".
This is a "very very important feature" of the bill.
Mr. Dickinson pointed out that while the majority of the PPT
discussion had focused on the tax rate, "the credit rate is
equally as important".
Mr. Dickinson agreed with Mr. Walker's position that at $60
barrel prices, "there's a distortion. We tend to look at prices
as driving everything, but that's masking what's going on
underneath. And underneath, at prices that are more ….
historically expected, the credit looms as an ever more
important part of that." The balance consideration must weight
the tax rate with the credit rate. The credit provisions "would
directly … incentivize the investment".
9:12:46 AM
ANTHONY FINIZZA, Analyst, Econ One Research, Inc, an economic
research and consulting firm hired by the Legislature, testified
via teleconference from an offnet location. He reiterated Econ
One's position that the PPT would incentivize new field
exploration. Recent modeling calculations indicated that the
discounted tax rate resulting from the application of the
development credits in the PPT would not increase the government
take percentage significantly higher than that experienced under
ELF. Neither the 20/20 tax/credit provisions included in SB 305
nor the 25/20 tax/credit provisions proposed in CSSB 305 "are in
a range that would stifle significant investment".
9:14:07 AM
DAVID BRAMLEY, Vice President, Charles River Associates
International (CRA), an independent resource consultant company
under contract to BP, stressed that CRA was "not unmindful of
the fact that our reputation is against what we say". "The
question about investment and level of tax take is what
economists would call a question of elasticity. That's where
there is a disagreement of view about what is the impact of a
change in tax take on investment."
Mr. Bramley voiced that CRA's analyses, which "are quite
different" from some other consultants, were based on the
"conventional economic theory" that, while "the oil business has
its own peculiarity and its own complication, it was
"fundamentally" like any other industry in that an increase in
the level of tax would lower investment attractiveness, and
thereby, decrease investment. Conversely, investment levels
would increase were tax rates lowered. While the tax credits and
deductions proposed in the PPT were important, the "net effect"
of whether they would offset the higher tax take would influence
decisions. Economic modeling analyses of the PPT thus far have
indicated that the net effect would be to drive investments
"downwards". Those who "contend" the PPT would not be
detrimental to investment must substantiate their claim, as the
laws of economics indicate otherwise.
Mr. Bramley observed that an analysis [copy not provided]
developed by CRA presented an "illustrative number … of what
might happen if investment in the State of Alaska" declined by
"a conservative estimate" of 20 percent as the result of SB 305.
Mr. Bramley reviewed some of the reasons CRA believed SB 305
would reduce investment in the State. While there had been much
discussion on the "structural peculiarities of ELF" little focus
has been given to the "level of overall tax take" levied under
ELF.
9:17:03 AM
Mr. Bramley continued that, according to CRA's analysis, when
the prospectivity and cost base of new investments in the State
were compared "to a peer group of OEDC countries", Alaska
"doesn't look attractive" even under the current ELF system.
This, rather than the structural peculiarities of ELF, would be
"the most powerful explanation of why present levels of
investment in Alaska are low".
Mr. Bramley stated that information provided by ConocoPhillips
would suggest that a 20 percent decline in investments might be
a conservative number; specifically that the level of capital
spent in the Kuparuk Unit over the last five years, increased as
the severance tax rate there decreased. In contrast, both the
investment and tax rates of Prudhoe Bay fields have remained
flat. While he "wouldn't claim a direct elasticity relationship
there", he would argue that the effect of the tax rates on
investments in these two large fields would be a viable gauge of
how investments in the State would be impacted by the net affect
of the PPT. He concluded "that the impact of the new proposals
would be more than a 20 percent reduction in investment".
9:18:44 AM
Mr. Bramley, an independent consultant, had worked with
"governments and national oil companies as well as private oil
companies". To that point, "the fundamentals of our analysis
would not differ" were CRA to advise the Legislature rather than
an oil company. While the PPT would increase taxes and thereby
increase revenues to the State, investments in the State would
be impacted. The level of that impact could be debated. He
welcomed other's perspectives in this regard; however, those who
claim the impact would be zero and that investments would remain
constant or increase must prove their case.
9:19:47 AM
MARK HANLEY, Public Affairs Manager, Anadarko Petroleum
Corporation/Alaska, would not disagree with the majority of the
comments thus far. A PPT rate of 25/20 would be more detrimental
than the 20/20 to his company, particularly in regards to
exploration activities. Charts developed by Anadarko and Dr.
Pedro van Meurs, a consultant to the Governor, indicated that a
lower rate of return would be experienced under the 25/20
proposed in CSSB 305. Net present value (NPV) calculations
indicated that the government take under either the 20/20 or
25/20 PPT proposals would be higher than that under ELF, as
barrel prices increased. Even though activities become more
economic as prices increase, the increase in government take
under the 25/20 PPT would be substantial. He noted the argument
that at lower barrel prices, the 25/20 would be better for
exploration. In response, he stated that at prices ranging from
$20 to $35, "generally at those low prices, we don't have
prospects that are economic". As prices increase, prospects in
Anadarko's portfolio would become more economic.
Mr. Hanley cautioned against increasing the tax rate without
also adjusting credits, as, even though "it's not one to one",
there "is some relationship there".
9:22:57 AM
JOHN ZAGER, General Manager, Chevron/Alaska noted that how the
tax and credit relationship would impact a company would depend
on where that company was in its business cycle. A large company
with a relatively large percent of big production rather than
exploration would be more interested in the affects of the tax
rate. On the other hand, a company highly concentrated in
exploration would benefit more from the credit component.
Mr. Zager exampled the tax/credit rate relationship pertaining
to a redevelopment program with good production potential
Chevron was furthering in Cook Inlet. "In order to get the same
net present value out of my combined business", an increase in
the tax rate from 20 of 21 percent must be accompanied by a
credit rate of 26 percent.
9:24:00 AM
DANIEL JOHNSTON, Consultant to the Alaska Legislature, declared
that high oil prices was one of the primary reasons that changes
in the State's tax regime were being discussed by the
Legislature. While the PPT bills being furthered in the House
and the Senate have been compared to the existing ELF tax
regime, he opted to stop utilizing that comparison as the
benchmark. "Once we saw that the producers were willing to agree
to 20/20, as far as I'm concerned that's an appropriate
benchmark." The Senate bill, with its 25/20 percent PPT rate "is
the high side" of what is being proposed.
Mr. Johnston pointed out that increasing the tax structure from
20/20 to 25/20 would result in an overall government take
increase of "two percentage points". That "is not a huge
difference".
Mr. Johnston stressed that the State could not do much to
counter the impact low prices would have on oil production in
the State. Such things as royalty and severance tax holidays or
an increase in credits would not alleviate the situation when
prices were in the $25 range. However, when prices increased to
levels at which the economic modeling of prospects was
considered "favorable" by the industry, "there's a whole lot of
profit to be made by both the oil companies and the government".
9:25:58 AM
Mr. Johnston referenced Ms. Kah's remarks: there was "a whole
lot of exuberance out there in the marketplace that she feels is
inappropriate and that there are a lot of companies that are
bidding too much, but I would submit that that's an acid test of
the market place when you have licensed rounds in places like
Libya and you see that kind of exuberance that drives those
licensed rounds. Perhaps that is what the marketplace is trying
to tell us, that there's justification for that exuberance." In
his opinion, people "have been fairly conservative" in Alaska in
respect to "their negotiations and their discussions and have
used oil price forecasts and assumptions that compared to the
world marketplace with its exuberance are fairly conservative".
Were the State Legislature to make investment decisions "based
on oil price forecasts that are substantially lower than what
the marketplace perceives the future to be, then we are doing a
disservice to Alaskans".
9:26:59 AM
JOHN BARNES, Production Manager, Marathon Oil Company, specified
that his company's activities were limited to Cook Inlet, "a
very old basin". Cook Inlet could be representative of "the
marginal production" that would be occurring on the North Slope
"in five or ten or 20 years".
Mr. Barnes communicated that Marathon "was not one of the
producers" that had agreed that the 20/20 PPT provisions
proposed in SB 305 "made sense"; particularly in Cook Inlet. The
last time people anticipated $50 to $100 barrel oil prices,
their expectations had been incorrect and people were laid off.
Thus, he urged the Committee to consider low price scenarios in
their discussions. He agreed with Mr. Johnston that the impact
of low prices was "difficult to fix". That should be a
consideration, especially in regards to Cook Inlet. Other
regions of the State might mirror Cook Inlet in the future.
Co-Chair Green noted that further discussion on Cook Inlet would
occur when Issue 12 came before the panel, as Cook Inlet was the
focus of that question.
9:28:32 AM
Mr. Walker informed that Committee that BP agreed to the 20/20
provisions proposed in SB 305 because "we, the producers, made
an offer to the Administration of 12.5 percent tax rate with a
25 percent credit. 25 percent for exploration and challenged
oil, and 15 percent for normal capital. The Administration's
first offer was a 20 percent tax rate, ten percent credit. That
is the operating range of the negotiations. At the end of the
day, we agreed to 20 percent tax rate, 20 percent credit, along
with all the other things that came with in that package
including transition, start date, etc. We were at the end of our
rope. We don't believe it's the best tax rate for Alaska, but we
agreed to it. So why did we agree to something that we don't
believe is the best tax rate for Alaska? We agreed to it as a
means to moving ahead with gas. But we always said and we were
very clear with the Administration that when we came to the
Legislature, we would appeal to the Legislature and enter a
debate and let the Legislature decide what the right tax rate
for Alaska is."
9:30:23 AM
Mr. Bramley identified the "heart of the underlining issues in
question one" as being that Alaska must compete in an
"international marketplace, and in order to make meaningful
comparisons" one must "understand the context in which those
comparisons were made. People would be skeptical were people
selling their house in Juneau for $500,000 to say it was under
priced because a similar house was for sale for one million
dollars in New York. The "relevant question" for Alaska would be
whether other areas in the international marketplace existed
that had "similar prospectivity, similar cost bases, but higher
tax rates and which are getting a good level of inward
investment". CRA's analyses of mature Organization for Economic
Cooperation and Development (OEDC) producing areas indicated
there were no such areas. Even Alaska's existing ELF tax regime
appeared "tough, specifically on new investments" in that
analyses.
Co-Chair Wilken asked Mr. Walker to further explain BP's claim
that production would decrease six percent annually, as the
forecast on Chart 4.9, page 40 of the Department of Revenue's
"Fall 2005 Revenue Forecast" book [copy not provided] estimated
that production would decrease 1.5 percent over the next ten
years. The lower of the three lines depicted on that chart
represented the barrel forecast if existing wells continued to
produce through 2016 and no new wells came online. The second
line represented producing wells plus wells currently being
developed. The third line presented the total of current
producing wells, "those under development, and those under
evaluation".
9:34:01 AM
Co-Chair Wilken understood the volume generated by the third
scenario would decrease from approximately 900,000 barrels to
810,000 barrels by the year 2016. This would equate to a 0.9
percent per year reduction over the next ten years. The scenario
depicting existing wells and wells under development would
reflect a decrease from 900,000 barrels to 575,000 barrels in
2016; an annual decline of approximately 3.2 percent. The
scenario solely depicting existing wells would reflect a decline
from 900,000 to 400,000 barrels in 2016; an annual five percent
decline. A five percent decline each year would therefore be the
worst case scenario.
9:35:37 AM
Mr. Walker stated that Co-Chair Wilken had raised "a very
important point". Were the industry to simply maintain surface
facilities and halt other investments in the North Slope,
existing North Slope field production "would decline at a rate
of about 20 percent per year." Because the industry continuously
conducted well work on existing stock in order "to optimize each
well", it was able to "sustain the decline rate of existing
fields to 15 percent per year". In addition, the industry
continuously invested in capital projects on the North Slope,
primarily in existing fields. Some investment has been made in
satellite fields. This allowed the industry to sustain an annual
decline of approximately six percent.
Mr. Walker noted that because the industry was concerned about
the differences between it's and Department of Revenue's (DOR)
production decline projections, it requested a meeting to
discuss the issue. The conclusion of that meeting, which was
held last week, was that "the difference between our forecast
and the DOR forecast is that their forecast will require
significantly more capital to deliver it". All parties agreed
that "the production on the North Slope was declining
significantly" and that production would fall below 500,000
barrels a day in ten years based on the existing level of
investment". It was also agreed that "significantly more
capital" than what was currently being invested would be
required to deliver DOR's forecast.
Mr. Walker stressed that any new tax regime being considered
must be "designed to attract that capital as otherwise we will
be declining at the existing rate or higher".
9:38:14 AM
Co-Chair Wilken understood therefore that were SB 305 adopted,
fields that were currently "producing would continue to
produce"; however, further investment in underdeveloped wells
would be curtailed. This would cause production to decrease 3.25
percent per year, as depicted on the aforementioned chart.
9:38:42 AM
Mr. Walker noted that even thought he did not have a copy of the
chart being referenced, he was "familiar with the
representation". The important thing to consider "is that a lot
of the production that we will develop is in the existing
fields. So it's not separate new accumulations that will be
developed." In reality it would be "much more complicated" than
simply looking at the numbers and "adding them up". The industry
would make decisions "to invest in as many projects as we can"
based on the economics as affected by whatever fiscal regime was
adopted. The industry's belief was that "there's an opportunity
to do more good business here in Alaska with the right fiscal
regime".
Co-Chair Wilken appreciated the explanation.
9:39:50 AM
Co-Chair Wilken asked Mr. Finizza to explain the information
depicted in the chart titled "Effective Average Tax Rates at
various Price Levels Impact of Increased Investment (FY 2007 -
2016)" [copy on file] which was located on page 90 of Econ One's
April 5, 2006 "Presentation on Alaska Gas Pipeline Project" to
the House and Senate Finance Committees.
Co-Chair Green expressed that this question would be addressed
once the chart had been distributed.
9:40:39 AM
Senator Olson declared that in the discussion "on the difference
between development/exploration" and what effects the PPT
legislation would have on production, a major factor was
omitted. That being "the lack of emphasis" placed on the Arctic
National Wildlife Refuge (ANWR) and National Petroleum Reserve-
Alaska (NPR-A) areas. He questioned why such little emphasis was
placed on these areas by either the State's consultants or the
industry.
9:41:34 AM
Mr. Bramley communicated that BP had considered including the
prospectivity in ANWR in their analysis. Were those areas to
hold the resources acclaimed by the United States Geological
Survey (USGS) and other authorities, their inclusion would have
"changed the perspective of our analysis. However, ANWR is
closed. And … the question is does it make strategic sense to
set the fiscal strategy in the expectation of ANWR opening." No
response could be provided since the future of ANWR was unknown.
Mr. Bramley stated that while NPR-A and other areas were
reasonably well licensed, little drilling had occurred. However,
there was nothing to "to suggest that the authorities who've
licensed the existing acreage in NPR-A and on the Slope and the
people who have drilled there have done anything other than
drilled the best prospects first." This would be typical of any
maturing area. "So, I find it hard to see from an NPR-A point of
perspective that there is additional economic prospectivity that
would significantly change the equation that people are looking
at."
9:43:53 AM
Mr. Johnston stated that a tremendous amount of discussion
occurred in the effort "to clarify the dramatic difference
between exploration and development". Had the PPT only affected
fields such as Kuparuk and Prudhoe Bay, the subject of
prospectivity and field comparisons would change significantly.
"Half the time when we talk about prospectivity it's in the
exploration context which is a lot different than looking at
those two established known fields. It's not to say that there
is no risk associated with trying to increase the production
there, but it's a lot less risky and a lot less costly in many
respects than typical high risk exploration." This is the reason
Cook Inlet was "treated like such a step child up until now and
why I agree" with Marathon's position that "they wouldn't have
agreed to 20/20 and I wouldn't blame them. So sometimes we have
to stand back and think in terms of development economics and
the terms that would be appropriate for what will constitute 80
percent of the value of our work here on these bills and then
the other problem and that's future exploration in various parts
of Alaska."
9:45:25 AM
Mr. Walker addressed "the comparison on risk between exploration
and infield development". "More and more expensive technology"
was being required to garner the "maximum recovery" from the
State's aging large fields. In addition, risks in developing a
field were also increasing. BP's technology portfolio for Alaska
included a $100 million expenditure for enhanced oil recovery at
the Endicott field. Were that technology successful, it would be
applied statewide and an additional 450 million barrels might be
recovered. Nonetheless, this was "a big risk" for BP. "The
business is changing" and each barrel was getting harder to
recover. Investments in technology and increased risks would be
required to harvest the "huge resource that exists on the North
Slope".
9:46:46 AM
Ms. Kah also pointed out that heavy oil comprised a significant
amount of the remaining resources in existing fields. Increased
risk would be required in order to develop technology which
would allow that type of oil to be commercially extracted. In
addition, additional expenses would be incurred as remaining
resources "are further and further away" from the existing
pipeline infrastructure. BP, which had a larger percent of its
portfolio in OCED countries than its competitors, was
experiencing a much larger production decline than anticipated.
An increase in capital costs for reinvestment on a global scale
was also being experienced. "Nobody has properly forecast what
the production decline rates are in the mature fields around the
world, not just Alaska. I think it's a global issue."
9:47:47 AM
Mr. Hanley pointed out that, regardless of whether or not one
considered ELF "broken", it had attempted "to identify less
economic fields and factor in provisions to address less
productive wells and smaller field size.
Mr. Hanley stated that sustainability per well and prospectivity
considerations should be applied to any "possible discovery of a
huge field in ANWR". The problem with the PPT bill is that it
was a "one size fits all" bill. Anadarko was optimistic that
there were more Alpine size fields in the State. However it was
unlikely that those fields would be close to existing
infrastructure. The PPT also did not "provide for risk factors
or prospectivity". A developer would expect to pay a high
severance tax under ELF were a large field found whereas a lower
tax would be levied on a small, less productive fields.
Mr. Hanley stated that regardless of whether the tax structure
of ELF was correct or not, "at least it tried to address the
economics of a field". That consideration was absent from the
PPT, such things as heavy oil, existing infrastructure, new
exploration, and existing production, and exploration activities
should be considered. While the tax rate was always important,
credits would also be important to an explorer. One size fits
all does not really apply to activities in Cook Inlet.
9:50:00 AM
Mr. Dickinson stated that "a proxy for cost" for such things as
per well productivity or the size of field existed in ELF. The
reason to consider the net basis of costs as proposed in the PPT
was to "avoid figuring out those proxies". Were the cost of
extracting heavy oil to be "extraordinarily expensive to
develop" then the credits would play a very large role in
getting that development". Mr. Hanley might be correct that a
flat rate would not address the entirety of circumstances,
however, "we believe that it does". It would be "more effective
than using a proxy" in terms of "the range of things that have
been looked" at. The hope is that barrel prices would maintain a
price level which would benefit the industry and the State as
the PPT would be detrimental to the industry were prices at the
"at the lower extreme of for example $20 per barrel".
9:51:36 AM
Senator Hoffman shared that he was a member of the Legislature
when ELF was last revised in 1990. No one at the time
anticipated oil prices to escalate to the $60 or $70 range. Last
year ANS West Coast prices "fluctuated from $41 to $62 per
barrel". For the first quarter of 2006, prices averaged above
$60 per barrel. "Part of the equation for incentives to look for
new fields has to be the price, as well." That consideration
must not be overlooked, for were oil prices to remain high for a
long time, given what's happening over in China and India, I
think many people believe that the $50 per barrel price average
might be the norm." It could also be the low.
Senator Hoffman, in order to further understand the issue, he
asked whether BP could share the "types of profits" they
experienced in the State in 2005.
9:53:26 AM
Mr. Walker responded that the $50 and $60 barrel prices
experienced in 2005 allowed BP and the industry to experience "a
very good year". Alaska had also benefited by those prices. BP
paid in excess of 2.5 billion dollars in tax and its profits
from its Alaska activities were slightly less than two billion
dollars. It was the best year BP experienced "in decades". While
that was "a lot of money", it should be noted that BP's presence
in the State was large.
Mr. Walker characterized Alaska as "a price play. Alaska only
makes sense at medium and high prices". The company's 2006
breakeven point in Alaska would be $22.50 per barrel. State
taxes equating to $6.50 per barrel and federal government fees
amounting to 47 cents would be paid at that price. "That is the
nature of the regressive tax regime" the State has. "It is
protected on the down side and gives a little bit extra to the
oil companies on the upside." The proposed 20/20 PPT tax regime
"would significantly shift the balance at high prices. DOR
estimated that, at $60 per barrel, the State would receive
approximately one billion dollars more a year under the PPT than
under ELF.
Mr. Walker stated that "under the 20/20 proposal there has been
a significant shift from the oil companies to the State at
higher prices and that's something which we agreed to and is
something which we think is appropriate and is part of the
agreement that we came to with the Governor."
9:55:34 AM
Ms. Kah stressed that while "it is true that oil prices"
increased 2.5 times since 1999 in real terms, industry costs
"also doubled during that time period". The fact that costs
increased, "but at a lower pace", would account for the
industry's record level earnings. However, costs were catching
up. "Replacement costs are quickly rising to the level of price
so we won't be able to profitably invest even at this price
level if tax rates continue to go up on top of that given that
the cost structure is rising."
9:56:13 AM
Senator Stedman expressed that even though "the issue of taxes"
was constantly being referenced, the issue was really one of
establishing the appropriate "selling price of the people's
commodity". Royalties and tax systems were two of the limited
mechanics through which the State could "sell" its assets. The
tax rate proposed in the PPT would increase the price of the
people's commodity to acceptable levels. We should "not lose
sight" of that effort. "There has been a global movement in
recent years" to adjust the relationship between government take
and oil and gas industry take. "We are not leading the pack; we
are actually following a worldwide trend."
9:58:00 AM
Co-Chair Wilken asked Dr. Finizza whether his interpretation of
the Slide 90 was correct in that the green line reflected the
provisions of CSSB 305; the blue line indicated the affect of
the House committee substitute; and the top horizontal black
line at the 12 or 13 percent tax rate indicated the "average
historical" government take for the North Slope under ELF. The
horizontal line slightly below the top line was the projected
ELF rate going forward for the Prudhoe Bay Unit (PBU). The
horizontal line at approximately the six percent tax rate was
the projected rate going forward under ELF for all fields. Thus,
at a barrel price of $50 with no industry investment, the
effective tax rate, as depicted on the chart, would be
approximately 16 percent. The State was endeavoring to encourage
investment.
9:59:32 AM
Mr. Finizza stated that the first solid line on the chart
reflected the continuance of historical investment levels.
Co-Chair Wilken acknowledged. Were oil companies to increase
their investments to $2.5 billion a year, they would be entitled
to the two for one incentive component included in the PPT. This
could effectively reduce an oil company's tax rate to "the
average historical rate at $50 per barrel". This would be higher
than the projected tax rate under ELF, but would be slightly
above the range they had been paying under ELF.
10:00:24 AM
Mr. Finizza stated that Co-Chair Wilken's understanding of the
chart was correct. The chart was intended "to show the effect of
roughly doubling the investment rate". The industry could
"decrease their effect tax rate" by increasing investments and
using the deductible provisions proposed in the PPT.
10:00:57 AM
Co-Chair Wilken asked the producers their interpretation of the
chart as he understood the chart to indicate a "win/win for you
and for the State by increasing your investment with us".
10:01:12 AM
Ms. Kah stated that since the unpredictably of prices was a
given, the industry would assume "a much more conservative mean
and a very wide range around it, but we certainly would not
invest at a $50 a barrel price." Today, for instance, under the
"current forward curve which appears to be at $60 a barrel
today, we have a series of new financial investors who are using
the commodity prices in the forward curve specifically to hedge
their stock and buy portfolios".
Ms. Kah shared that this has resulted in "huge financial
rotations into our markets" which "are inflating the entire
forward curve". She was unaware of any analyst who believed
"that the forward curve today is a true representation of
forward price expectations because so much money is coming into
the curve wanting to go long and there is nobody on the other
side who wants to go short five years out. They're creating an
imbalance and their prices are now higher than what true price
expectations are in the forward curve." She knew of no one who
would "use the forward curve for investments".
Ms. Kah stated that another consideration would be "cyclical
factors" such as an increase or decrease in economic growth.
While she knew of one research firm which predicted that 15
million barrels a day of oil would be added over the next five
years, she was skeptical of that as she was aware of the delays
that some projects were experiencing. Markets fluctuate and
"supply and demand do respond". She doubted however that prices
of $20 a barrel would be revisited or that recent high prices
would continue. Thus, extreme prices would not be used as the
mean in industry investment decisions. She avowed that an
increase in investment would not occur when oil prices were in
the $30 and $40 range.
10:03:15 AM
Co-Chair Wilken understood therefore, that in order to obtain a
ten percent tax rate at, for example, a $40 barrel price, a
company must increase its investment by $2.5 billion. However,
Ms. Kah has attested that a company would not make such an
investment at that price.
Ms. Kah specified that the price point at which her company
based its decisions was privileged and could not be disclosed in
a public hearing situation. Nonetheless, a price of $40 would
"on the aggressive side for us". The economic analysis of
projects in Alaska must be competitive with other projects in
the company's portfolio. "The high cost of operating in the
State and the smaller prospectivity … just makes it tougher and
tougher".
10:04:09 AM
Mr. Johnston thought that the terms "current prices and current
price forecasts" had been confused in the conversation. He
understood Co-Chair Wilken's question to be how might a long
term stable forecast price of $40 a barrel affect an investment
decision as opposed to how would a current price of $40 affect
it.
10:04:38 AM
Ms. Kah stated that her remarks were to the long term forecast
rather than to a today price.
Mr. Johnston ascertained therefore that the company would choose
not to invest at a long term forecast of $50 a barrel.
10:04:52 AM
Ms. Kah corrected her previous remark. Her response was not to
long term forecasts.
Mr. Johnston asked Ms. Kah to further clarify her position.
10:05:23 AM
Ms. Kah qualified that the company's long term price forecast
did not include a $50 barrel price so therefore, no investment
would be made on that assumption. However, regardless of price,
the company would compare Alaska's projects to other projects in
its portfolio. A multitude of factors were involved in
investment decisions. BP would not invest at a $50 outlook
price.
10:06:06 AM
Mr. Walker spoke to the Slide 90 chart. He asked Mr. Finizza
whether Econ One had adjusted the production volume resulting
from increased investment when it calculated the affect of the
additional investment on the tax rate.
10:06:38 AM
Mr. Finizza replied that the volume had not been adjusted. The
chart presumed that production levels would remain consistent,
as the affect of the increased investment on production was
unknown.
Mr. Walker offered to share his company's assumptions with Econ
One, whose analysis had not accounted "for the extra production,
the extra revenue, the extra State revenue, and the impact on
both the oil companies and the State" of the extra production
resulting from the development. The analysis must include the
different volumes that would arise from differing levels of
investment.
Mr. Finizza agreed. The graph should be revised to reflect the
increased volume. "The lines on the chart depicting the level of
tax experienced by a $2.5 billion increase in investment "could
actually fall rather than rise".
Mr. Dickinson understood that the graph was based on the
Department of Revenue production forecast.
Mr. Finizza affirmed.
10:08:51 AM
Mr. Dickinson referred to Mr. Walker's earlier testimony
attesting that absent increased investment, production would
decline and the Department of Revenue forecast would not be met.
In order to achieve the level of production included in the DOR
forecast, more investment would be required. The graph should
therefore reflect production levels resulting from that
investment. This would be "consistent with that view" that more
investment would be required to maintain that production. The
graph would support the effort to encourage investment by
allowing it to have "tax consequence".
10:09:42 AM
In response to a question from Co-Chair Green, Co-Chair Wilken
acknowledged that his question had been answered.
Co-Chair Wilken noted that Slide 91 of the aforementioned Econ
One presentation (copy not provided) addressed the differences
in government take as affected by the 20/20 provisions in SB
305, and the 25/20 provisions in CSSB 305. The differences in
government take would increase over time. He was struggling
"with whether the demand and the competition for capital is so
competitive that an increase in the government take in Alaska of
3.8 percent, 4.3, 3.5 percent" would lower the State's
"competitiveness and attractiveness down to the point where …
its' been suggested that we would lose 20 percent of the
investment". Had the government take been projected to increase
13 or 14 percent he would have agreed; however, a three to four
percent government take increase on oil prices in the $40 and
$50 per barrel range would not be sufficient enough to "tank
Alaska".
10:12:15 AM
Mr. Bramley recognized Co-Chair Wilken's question as targeting
"the heart of what's really important here"; that being how
investment decisions were made. As he understood the process,
oil companies, regardless of size, "exercise capital discipline"
throughout their capital allocation process. A variety of
reviews were conducted on the competing projects in a company's
portfolio of investment opportunities. "There is a constant
churn of those opportunities and a constant process to rank and
screen those in some way using all kinds of calculative
budgeting techniques."
Mr. Bramley stated that the prospect of any change in a tax
regime, regardless of the size of the change, would "act like a
change of price into a market". Thus, the effect of an increased
tax take on any Alaskan project in any company's portfolio would
"relegate all of Alaska's proposals" and the outcome would be
conflicted. A tax increase of 20 percent might have little or no
impact on some of the best Alaska projects; some marginal
prospects might be deferred or even dropped. The result of the
change in the tax regime would be that "some would accept it,
some won't, and there would be some kind of net affect". "If the
net affect of the tax credits, deductibility, and tax rates is a
negative one, then investment attractiveness can only go down,
and consequently investment will go down, and there will be some
effect on production."
10:15:34 AM
Mr. Johnston reminded the Committee "that Alaska is not the only
province on this planet" that was considering changing its tax
terms. "In that context, and particularly when you consider the
modest change that being contemplated here, when all is said and
done, and the dust settles, we will find that Alaska changed
much less than most of the other countries" discussing adjusting
their rate structures. Since Alaska was not the only entity
considering changes to its tax structure, the effort "is
terribly appropriate" in consideration of Mr. Bramley's remarks.
"In this context of all the changes that are taking place right
now, it's a whole different matter."
Mr. Finizza noted that Mr. Bramley had provided a good
perspective of the types of things a board room would consider.
A chart developed by Ms. Kah [copy not provided] indicated that
a change in the tax rate could transition the net present value
(NPV) of some projects from being economic to being
uncompetitive. However, the proposed tax structure might improve
the NPV of some projects.
10:17:15 AM
Mr. Finizza stated that a project requiring "a front end loaded
large capital investment" would benefit from the credits and tax
sheltering the PPT would provide. Thus the NPV of that project
"might actually rise relative to the same project under ELF".
Therefore, he believed that "the shuffling that goes around in
the boardroom" relating to a fiscal change could go the other
way as well as there are other provisions in the PPT besides the
tax rate.
10:17:58 AM
Ms. Kah could not identify any project that would benefit from
the terms of the PPT with the exception of an unsuccessful
exploration project. The only direction the PPT would drive
projects would be in a "negative direction". Many Alaskan
projects, particularly those relating to heavy oil, "are
marginal to begin with". A project with high costs "would be
more likely to slip across that line and get deferred" than a
large robust resource that could absorb a tax increase. This was
why she was "worried about Alaska". Changes to the tax system
must be done "right" in order not to jeopardize projects.
Senator Hoffman revisited Co-Chair Wilken's remarks regarding
how significant the impact of a three percent increase in
government take might be. On April 3, 2006 the Committee heard a
presentation from the DOR in which it was specified that at a
$40 barrel oil price, the PPT would garner $20.4 billion over a
24 year period as opposed to $15.4 billion under ELF; a five
billion dollar difference. At a $60 barrel price the PPT would
garner $42.4 billion verses $32.9 billion under ELF; a ten
billion dollar difference. "Although the point percentages may
be small, the numbers are quite large."
Co-Chair Green appreciated the dollar amount perspective because
"the percentages can appear very small, but then multiply out".
10:20:11 AM
Senator Stedman contended that the dollar estimations were "the
root of some of the finer points of the discussion" and
arguments. In his opinion, "the incremental difference between"
the 20/20 proposed in SB 305 and the 25/20 proposed in CSSB 305
would not be "ruinous to the State of Alaska". One might think
that "we're making these gigantic changes" because of the level
of money being discussed, however, accurate amounts could not be
determined until the final PPT percentages were determined.
Senator Stedman reminded the Committee that the industry take in
Alaska was $1.8 billion more in FY 2006 than that of FY 2005. He
communicated that as the discussion continued, there would be
some, including himself, who would refer to discuss the issue in
terms of percentages because decisions based on the intensity of
dollar increases would not be "in the best interest of the
citizens of the State of Alaska".
10:21:42 AM
Mr. Johnston "totally" agreed with Senator Stedman. He, for the
most part, had never "spoken in terms of dollars". He "resented"
those times that the Administration and the industry professed
that the State would "get an extra, you know, so many zillion
dollars a year because" of the PPT. While it might be a lot of
money, it was "misleading" as large dollar amounts were the norm
in the international business marketplace. "If you get an extra
billion dollars a year, that's one thing, but if you get an
extra billion dollars a year when perhaps you should have been
getting an extra billion and a half now that's quite another
matter". Such distinctions should be addressed as large dollar
amounts could result from "very small percentages". The effort
should be to determine the proper percentages, "and then let the
chips fall were they may". He avowed that the PPT proposal being
considered "was not even close" to being detrimental to the
State.
Mr. Walker took "exception" to Mr. Johnston's remarks. "These
are very large numbers, indeed". The House and Senate PPT
committee substitutes would garner significantly more revenue
for the State than the one billion dollars expected under SB
305.
Mr. Walker voiced that, in percentages, ELF would provide Alaska
32 percent of the proceeds at barrel prices of $60. The 20/20
PPT proposal in SB 305 would provide the State 40 percent.
According to BP's numbers, the company's share would reduce from
43 percent to 38 percent. This could be viewed as an industry
marker. The transition from ELF to the PPT would result in "a
significant shift in share". This shift in percentage take would
result in a significant shift in dollars.
10:24:13 AM
Mr. Bramley addressed Mr. Johnston's remarks about the tax
regime changes that have been occurring on the worldwide market.
The higher price environment prompted some changes in tax take:
the one most comparable to Alaska would be the United Kingdom
(UK). The UK increased its take from 30 to 50 percent. Venezuela
and China also increased their terms. However the overall
systemic changes would not be considered "clear cut". Numerous
investors actually experienced "improvements" or "softer terms"
during the last several years in countries such as Indonesia,
India, Peru, and Syria. While this would not support there being
a downward trend occurring, "it is not a clear cut picture of an
increase in tax terms".
Mr. Bramley responded to Mr. Finizza's point that NPV might, in
certain cases, improve under the PPT. The only "convincing case"
substantiating this would work conducted on a dry well. In that
regard, the State would support a portion of "the cost of dry
hole drilling". That would be attractive at higher tax rates.
CRA could not identify any other situation in which NPV would
increase as a result of credits provided to, for example, a 50
million barrel field, which would be the size of a typical field
in the State. PPT would be less attractive for investment under
any other scenario modeled by CRA. He asked that supporting
evidence of the improved NPV situation suggested by Dr. Finizza
be presented.
10:27:12 AM
Mr. Finizza acknowledged Mr. Bramley's remarks. He asked Mr.
Bramley about the modeling CRA had done; specifically whether it
had modeled a plan with the 5,000 barrel allowance as proposed
in CSSB 305, as that was the scenario contemplated in his
remarks.
Mr. Bramley stated that CRA's modeling had concentrated on the
provisions of the original bill which provided a $73 million
fixed allowance against the severance tax. The $12 million
credit and the "company wide" production allowance by the House
and Senate committee substitutes, respectively, were discussed.
While the provisions in the committee substitutes would provide
incentives "to new investors on their early investments", those
provisions would "migrate towards that of all existing
taxpayers" who had "substantial positions" "built up" over time.
Since it would benefit new investors, CRA did not consider the
5,000 barrel allowance proposed in CSSB 305 "to be central to
the issue", as, over the last five years, more than 90 percent
of the investment occurring in the State was conducted by the
four largest resource companies. While small companies might
grow and make "a real contribution" to the State, that scenario
should not be "the primary question in looking at the effect on
investment" resulting from these new proposals.
10:29:01 AM
Mr. Finizza anticipated that a similar response would have
greeted another incentive proposal that had been considered but
not furthered. That proposal, which would have forgiven the tax
on "X" number of barrels from new fields, would have also
increased the NPV of a field "early on".
Mr. Bramley responded that a thorough analysis would be required
to determine the affect of such a proposal specifically on new
fields and new participants. However, he anticipated it would
have a positive affect on the economics of "early investments".
Co-Chair Green stated that the panel discussion would now
address Issue 2. One and a half hours had been devoted to Issue
1.
Issue 2. WTI vs. ANS.
Co-Chair Green stated that whether to base the PPT tax structure
on the West Texas Intermediate (WTI) price or the Alaska North
Slope (ANS) price should be carefully analyzed. The effort
should be to utilize a price system that would best serve the
State.
10:30:29 AM
Ms. Kah recommended the tax structure be based on a wellhead
price, as that would be "the only way you can really insure
you're actually getting at the revenues of the project". She
stressed that at times, there was a "disconnect" in ANS and WTI.
This disconnect would increase over time because the sulfur
content in the world's crude supply was increasing. A premium
was being placed on light sweet crude oil as compared to oils
with higher sulfur levels. This was the result of such things as
global environmental restrictions that required reductions in
products' sulfur levels.
Ms. Kah revisited her previous analogy of selling a house in
Anchorage or Juneau at a price set in West Texas. "It doesn't
compute. You'd expect to see disconnects," regulatory issues and
tax structure alterations due to that disconnect. Utilizing a
wellhead price would avoid a multitude of problems. "It is
closest to the real value of the project."
10:31:47 AM
Mr. Dickinson agreed that the tax should be levied at the
wellhead. The WTI debate primarily evolved around the rate
triggering the Progressivity factor included in CSSB 305.
Mr. Dickinson stated that when determining which index to use,
one should consider that both WTI and ANS had experienced "major
swings" and the difference between the two could range between
five dollars to "parity". "There is no question that ANS is
typically going to be trading several dollars below WTI." A
concern with ANS was that is was narrowly traded. There could be
as few as zero and as many as three trades a month. ANS and WTI
move in "lockstep" approximately 27 days per month. The
relationship between the two was revisited when a sale of ANS
occurred. "The ANS market simply isn't liquid." While he
disagreed with it, he noted there was concern that ANS could be
manipulated; a person could demonstrate that companies with
large internal refinery operations could make a sale at a loss
that could "lower the differential and move things around". "The
question really should be "is the thinness of the market for ANS
more of a set-back or more of a detriment than the fact that WTI
is not ANS and is measuring something different".
10:34:35 AM
Mr. Zager also supported utilizing a wellhead price as the tax
basis. In a previous presentation, he had suggested the
Committee consider developing a system based on net profits, as
this would avoid the discussion of how to determine the
appropriate marker between WTI and ANS. This issue could be
readdressed when Issues 10, 11, and 12 were discussed.
10:35:02 AM
Issue 3. $73 million allowance vs. $12 million credit vs.
5000 bbl plan. Discuss the different impacts each option
has on the state, the majors and the independents.
Mr. Walker communicated that how the different basins in the
State would be addressed in the PPT would be a matter of policy.
His company would support some basins being excluded from the
provisions of the PPT. While he appreciated there being concern
as to how applying the PPT to Cook Inlet might affect investment
there, he noted that "large tax increases" would also affect
investment in the North Slope.
Mr. Walker spoke to the $73 million credit proposed in SB 305,
and urged that a "level playing field" be considered for all
basins including operations in Cook Inlet and on the North
Slope. He spoke against including the $73 million exemption, the
$12 million credit, or the 5,000 barrel per day allowance in the
bill.
Co-Chair Green asked for confirmation that Mr. Walker preferred
to eliminate all allowances from the bill.
Mr. Walker affirmed that to be the request. Excluding such
provisions from the bill would create a level playing field. "I
recognize that we won't necessarily be aligned with other
panelists" in this regard.
10:37:21 AM
Mr. Hanley understood that the $73 million allowance was
included in SB 305 to "mitigate some of the tax increase" that
would be experienced by companies that had "lower tax rates
already because they had less productive levels" or, who were,
under ELF, "paying no severance tax on their field". In
addition, as attested to by Dr. Pedro van Meurs, the consultant
to the Governor, the allowance would be an incentive to new
entrants in the resource development industry in the State.
However, the allowance was limited in that "once you've used it
once, or to the extent that you have production, it no longer
can be used in future exploration, you have to use it against
existing".
Mr. Hanley explained that his company was "kind of in the
middle". Since his company had existing production, the
allowance could be applied "to decrease the increase in the
taxes at Alpine". The allowance would have more impact on
producing companies with small production levels than it would
on larger operations. The elimination of the $73 million
allowance would increase the tax rate on his company's entire
portfolio by five percent.
Mr. Hanley compared the $73 million allowance and no termination
date included in SB 305 to the $12 million credit proposed in
the House PPT committee substitute. That $12 million credit
would be equivalent to a $60 million allowance at the 20 percent
tax rate proposed in that bill. However, the House committee
substitute credit would not be of much, if any, value to "new
players" because a termination date was attached to it. The
credits would expire before they could be utilized by a new
player because of the time required to bring a new project to
production.
Mr. Hanley opined that the 5,000 barrel per day exemption
included in CSSB 305 would only be of value to perhaps two
existing companies. The seven year termination date accompanying
it would "assuredly" provide no value to a new player.
Mr. Hanley considered the request for a level playing field to
be interesting; particularly as one does not currently exist.
The $73 million allowance proposed in SB 305 could be
interpreted as a leveling of the playing field as it would apply
to any company. It could provide the equivalent of $12 to $14
million in credit each year for ten years to companies with
existing production such as Anadarko, BP, and ConocoPhillips.
"The irony is" that "it would be worth zero" to a new player
"until they actually had production, which might be ten years in
the future." He considered the $73 million allowance in SB 305
to be more valuable than the 5,000 barrel per day exemption
proposal in CSSB 305.
10:41:25 AM
Mr. Dickinson communicated that the Administration chose the $73
million allowance provision because it would be of value to
producers with small levels of production or those conducting
"very expensive operations". While it would be a factor in the
economics of larger operations, it would not be as significant.
An incentive based on volumes had been considered by the
Administration but rejected. The $73 million allowance in SB 305
could be compared to the credit provision included in the House
committee substitute, which would equate to approximately a $60
million allowance.
Mr. Dickinson addressed an issue of concern with the credit
provision included in the House committee substitute. A producer
with a ten million dollar investment that qualified for the
credit could elect to increase their investment to $12 million
and thus qualify to receive approximately three million dollars
in tax benefits. "There is a time period" in which there "is a
perverse incentive" in that a producer could "receive more than
a dollar for dollar benefit". This technical issue could be
corrected.
Mr. Dickinson noted however that even a company benefiting to
the maximum under the House provision would receive "a smaller
deduction than they would" under SB 305. Thus, most companies
would prefer the $74 million allowance provision.
Mr. Dickinson qualified that companies with production levels
below 5,000 barrels a day and profits below $73 million a year
would be neutral on the issue. A company with production below
5,000 barrels per day but revenues exceeding $73 million dollars
in profits a year would prefer CSSB 305. Generally though, a
company would realize that the SB 305 would provide more
benefits than CSSB 305.
Mr. Dickinson specified however that "from a revenue point of
view", the State would determine that, under the Senate plan,
"the only revenue we are allowing to leave as a consequence of
this are for the smallest players at the beginning of their
growth cycle". In summary, the Administration believed that the
73,000 allowance should be the preferred approach.
10:45:26 AM
Senator Stedman noted that the Senate Resources Committee had
been reluctant to further the $73 million allowance plan after
they realized the measurements were based on oil prices of $40 a
barrel. The value of the allowance must be viewed in terms of
actual oil prices.
10:45:51 AM
Mr. Finizza supported Mr. Dickinson's remarks favoring the $73
million allowance.
10:46:16 AM
Ms. Kah advised that any benefit should be equally applied to
all companies or at least all companies within a geographic
area. Her concern regarding CSSB 305's 5,000 barrel plan was
that it would "penalize the very companies who are most likely
to provide most of the investment, most of the production
decline mitigation, and most of the jobs in the future".
10:46:51 AM
Mr. Zager agreed that SB 305's $73 million allowance plan "would
be the most accommodating" to companies. The House's $12 million
credit, or $60 million dollar allowance equivalent, would not
be. Since there was a "tax on profits and a tax on dollars" the
"exemption should be based on dollars as otherwise you get into
barrels and a lot of barrels in the State have very different
profitability's associated with them, so the most profitable
barrels would actually get the biggest exemption. The least
profitable barrels would get the smallest exemption if it's
based on barrels."
10:47:33 AM
Issue 4. Point of Production. Further explanation.
In response to Co-Chair Green's remark that visual aids would
assist the discussion on Issue 4, Mr. Dickinson advised that
visual aids were being developed and would be available in the
afternoon. [See Time Stamp 12:17:45]
Co-Chair Green stated therefore that the discussion on Issue 4
would be postponed until the visual aids were available.
10:47:58 AM
Issue 5. Credits and deductions applicable for capital
investments in the gas pipeline. What is, what isn't.
Mr. Dickinson stated that CSSB 305 would allow "anything
upstream of the point of production", which would be any
activity "involved in getting the gas out of the ground and
moved to a point where it moves into typically a common carrier
pipeline" to qualify for deductions and credits. The exception
would be that the gas treatment facility in which the resource
would be processed into a pipeline ready condition, would not
qualify. To that point, he advised that discussions were
continuing in regards to "certain aspects of treatment verses
processing".
10:48:45 AM
Mr. Dickinson also noted that the gas transmissions lines that
move gas from fields such as Alpine or North Star "would not be
considered upstream" activities under the terms of CSSB 305, and
therefore would not qualify for credits or deductions. They
would receive downstream deductions.
Co-Chair Green asked whether diagrams distinguishing the point
between upstream and downstream gas activities were available.
Mr. Dickinson assured the Committee that diagrams would be
provided.
10:49:55 AM
Mr. Hanley agreed with Mr. Dickinson and characterized the
distinction between upstream and downstream activities as being
"a policy call". Neither SB 305 nor the House or Senate PPT
committee substitutes would allow the gas treatment facility to
qualify for credits. The industry would argue that any process
required "to get our gas into pipeline quality shape" should
qualify for the credits and deductions.
Mr. Hanley understood that the PPT's credit and deduction
components were intended to "offset the gas tax increase" the
PPT would impose. Therefore, "to leave out a significant portion
of our costs in getting that gas ready and eligible for going
into a pipe seems to us not to make sense". While a Prudhoe
Bay/Point Thomson treatment facility had been considered part of
a proposed gas pipeline contract, there were other places such
as the Nenana Basin and Cook Inlet that would also require gas
treatment facilities. This would substantiate the industry's
request that the point of production be downstream of the gas
treatment facility.
10:51:23 AM
Co-Chair Green asked Mr. Dickinson whether this issue was part
of the on-going discussions he had mentioned.
10:51:47 AM
Mr. Dickinson responded that diagrams would be provided that
would "crystallize the issue" raised by Mr. Hanley. A large
facility close to the location of the proposed gas pipeline was
currently being considered part of the transportation system. A
large treatment facility located in a remote location might be
considered differently. Further information would be provided to
the Committee regarding this issue.
Co-Chair Green understood therefore that language to address
this issue was being developed.
Mr. Dickinson affirmed.
10:52:24 AM
Senator Dyson expressed the "struggle" Legislators have had in
determining whether the PPT bill should be "a general
application oil bill" or an oil and gas bill. "Allowing
deductions or credits for conditioning gas that's specifically
for a pipeline further blurs the line of whether this is a oil
bill or is an oil and produced gas … or is an oil and … gas
monetization bill." However, he considered this "the first step
in maybe a three-part play that gets us to a gas pipeline". His
worry was that the deductions and credits included in the PPT
might be "manipulated to the point where the producers are
paying very little more if anything at high prices for the
extraction of the people's gas".
Senator Dyson shared his desire to design a program that would
either disallow "downstream or midstream" processes pertinent to
a gas pipeline from qualifying for credits or, if they were,
that the process be clearly defined.
10:54:19 AM
Mr. Hanley responded that the issue primarily revolved around
the economics of existing fields and exploration economics. One
of the challenges was whether a 20 or 25 percent tax rate would
be "appropriate on gas". His company considered the PPT to be a
tax bill on gas and oil. The current ten percent ELF tax rate on
gas would increase to 20 or 25 percent under the PPT. That rate
would be modified by the credits included in the bill. "On a
relative basis, you could argue that the tax rate is 12.5 and 15
for oil, modified by its ELF, and a relative basis gas just went
up higher."
Mr. Hanley stated that his company viewed things from an
exploration perspective. "We have exploration risks, development
risks, and all those types of things on gas. Same thing in the
Nenana Basin, I think you'll see some of the folks down there
looking at it a little bit differently than an existing field
that we're trying to get developed. And that's exactly our
concern. There's some difference potentially."
10:55:45 AM
Senator Stedman stated that when the PPT was initially
discussed, "there was a de-linking between the oil and gas
pipeline knowing that eventually there's going to be a
connection, within months not years. So that is a issue on the
table as far as how connected this bill is to gas". Legislators
were unsure about "what's coming at us, if it is". This
uncertainty caused him to hesitate. "Clearly, if this is
connected into that, directly with gas, I would expect that
that'll get revisited here in our Special Session because we
can't make those decisions without seeing what's underneath the
shells that are being moved around the board right now". This
legislation was the only "piece" that the Legislature was
provided.
10:56:51 AM
Co-Chair Green recalled Mr. Johnston recently declaring "that
there should definitely be a distinct PPT for gas".
10:56:53 AM
Mr. Johnston could not recall the exact context of that remark.
However, the State has treated "Cook Inlet like a stepchild" as
the effort has focused on the North Slope which is the primary
production area in the State. Gas exploration on the North Slope
has also been overshadowed.
Mr. Johnson continued that in most areas of the world "where
there is not a well-established gas infrastructure or market for
gas, the terms are typically better for gas than for oil because
it's so much more difficult to make a living with a gas
discovery than an oil discovery". Therefore, he agreed with Mr.
Hanley's position on the gas issue. The treatment of gas for
exploration should be "handled with care".
Co-Chair Green expressed that she might have misinterpreted Mr.
Johnston's recent remark.
10:58:08 AM
Mr. Dickinson reminded the Committee that even though "Anadarko
is not a party to a stranded gas contract negotiation, these
rules will be the rules that will govern their situation."
Provisions might be developed that could allow other companies
to participate in areas of the Stranded Gas Act.
10:58:38 AM
Mr. Johnston understood that the rules Mr. Dickinson was
referring to were those in the PPT legislation.
Co-Chair Green affirmed.
Mr. Johnson expected that different rules would apply to the 35
trillion cubic feet of known gas reserves on the North Slope.
Mr. Dickinson responded in the affirmative. "The narrow point is
there are three producers who are in negotiation with signing a
contract relative to their tax obligations, their royalty
obligations. Anadarko is not one of those three."
RECESS 10:59:26 AM / 12:17:45 PM
Co-Chair Green called the meeting back to order.
Issue 4. Point of Production. Further explanation.
Co-Chair Green stated that Issue 4 would now be addressed as
visual aids were now available.
Mr. Dickinson distributed a diagram labeled "Figure 9. North
Slope Pipelines" [copy on file]. The diagram depicted the
current North Slope pipeline based on information collected from
a study on upstream facility costs conducted by the Department
of Natural Resources. The Trans Alaska Pipeline Service (TAPS)
running south from Pump Station 1 was depicted in the lower
middle portion of the diagram. "Practically all the oil marketed
from the North Slope is in the Trans Alaska Pipeline." Oil from
Prudhoe Bay, which supplied a significant percent of the oil in
TAPS, runs through gathering centers and flow stations to Pump
Station 1. West of Pump Station 1 was the "publicly regulated"
Oliktok Pipeline "which carries crude from Kuparuk". Feeding
into the Oliktok Pipeline from the north was the Milne Point
Pipeline which carried oil from that field. Oil from the Alpine
Field Processing Facility fed into the western end of the
Oliktok Pipeline via the Alpine Pipeline. East of Pump Station
One was the Endicott Pipeline which flowed from Duck Island. The
Badami Pipeline fed into the Endicott Pipeline from the east.
East of the Badami Field was the Point Thomson field. The hope
was that when that field was developed, its oil would feed into
the Badami Pipeline.
Mr. Dickinson identified the point of production for oil as the
point at which the oil in the gathering lines from the various
fields moved into the Alpine Pipeline, the Oliktok Pipeline, the
Endicott Pipeline or the Badami Pipeline.
Mr. Dickinson stated that the point of production for gas "would
be very similar". Gas transmission lines would flow "from each
of the separate units to the head of the gasline heading down to
the Lower 48". Some of the gas processing and gas treatment
would be conducted at stations in the various fields. As
currently proposed, the gas pipeline project would have "a very
large gas treatment plant" located at "the inlet to the main
line". That plant would primarily treat gas from Prudhoe Bay,
but might handle additional gas from other places including
Point Thomson.
Mr. Dickinson stated that the costs associated with the
pipelines would qualify as a deduction "when calculating the
gross value at the wellhead".
Mr. Dickinson also noted that each pipelines would have a tariff
assigned to it. That tariff as well as the TAPS tariff would be
subtracted from the gross value at the point of production for a
field.
AT EASE 12:23:12 PM / 12:23:34 PM
Mr. Dickinson stated that the gathering lines would be
considered upstream of the point of production. The pipelines
would be downstream of the point of production.
Mr. Dickinson then distributed a map titled "North Slope Oil &
Gas Activity & Discoveries January 2006" [copy on file], which
depicted areas in which development was currently occurring or
might occur in the future. Additional pipelines would be
required to link these fields to TAPS.
Mr. Dickinson addressed another diagram, titled "Figure 8: Point
of Production for Gas - Prudhoe Bay - December 1986 - Present"
[copy on file] which was based on a DOR study regarding current
operations at the Central Gas Facility (CGF). Points of
production in the gas process were depicted on the flow chart by
circles with a slash through them.
Mr. Dickinson explained the current production process on the
North Slope. Well fluids flowed to separation facilities in
which oil and gas separating would occur. The oil would then
flow to a LACT Meter at Pump Station No. 1 where it would enter
TAPS. Some of the gas would move to meters indicated on the
diagram by circles with a slash through them and containing the
letters "A" or "A/A". That gas would be utilized to support
North Slope operations. The majority of the gas currently flowed
though the meter depicted on the diagram as a circle with a
slash through it and containing the letter "B". That gas would
move to the CGF. Currently, "at that point, all the things that
occur from then on, including the production of natural gas
liquids (NGL)" were considered gas.
Mr. Dickinson understood that the issue of concern raised by Mr.
Hanley was to certain processes that occur in the separation
facility such as the "dehydration" process that well fluids are
subjected to in order to prevent hydrates from forming in the
gas and "interfering with pipeline operations". The concern was
to whether "there are certain things that go on now in a
separation facility that might be considered under the
definition we're proposing 'gas treatment', and because that's
upstream of the gas processing, would that make a problem in our
definitions".
Mr. Dickinson stated that Mr. Hanley's second point was to
suggest that the State should make a policy call and recognize
all treatment processes as being upstream operations. This would
allow them to "be available for credits".
Mr. Dickinson stated that under the proposed set of definitions,
approximately half of the gas stream, depicted on the diagram as
"gas to reinjection", leaving the CGF facility would move to a
gas treatment plant and then to the proposed gas pipeline. This
stream currently amounted to approximately nine billion cubic
(BCF) feet per day. As proposed in the PPT, the point of
production for gas would be the point where the gas left the CGF
and entered the gas treatment plant (GTP).
12:27:55 PM
Co-Chair Wilken understood that the "MI-NGLs and Blendable NGLs"
gas streams flowing out of the CFG, as depicted on Figure 8,
would be unaffected by the changes being proposed in the PPT.
Mr. Dickinson affirmed that "not all the gas" emitting from the
CGF would flow to the GTP. Some would be used for reinjection.
12:28:42 PM
Mr. Hanley pointed out that a component was missing from the
Figure 8 diagram. Gas used for reinjection purposes would not
require having CO2 removed from it as gas going into the
pipeline would. Thus, the diagram should locate the GTP after
the point at which gas designated for injection was emitted from
the CGF. Gas coming from the CGF would not be pipeline quality;
gas leaving the GTP would be.
Mr. Hanley specified that the point of production for gas would
be between the CGF and the GTP.
In response to a question from Co-Chair Wilken, Mr. Dickinson
clarified that the point of production for gas should be between
the CGF and the GTP.
In response to a question from Co-Chair Green, Mr. Dickinson
stated that under current Statute, the point of production for
gas was after the final separation of oil and gas, as specified
on the diagram by the circle with a slash over the letter "B".
That point was currently between the separation facility and the
CGF.
Co-Chair Green understood that under the PPT the point of
production for gas would be after the CGF.
Mr. Dickinson affirmed. He also noted that under the PPT any
fluids leaving the CGF and flowing to Pump Station No. 1 and
into TAPS would be considered oil. Gas would transit from the
CGF to the GTP where it would be processed into pipeline
quality.
Mr. Dickinson referred to the location of Pump Station No. 1 on
Figure 9. Mr. Hanley's concern was to development that might
occur a vast distance away from that area. Specifically whether
the point of production would be a practical one or a good
policy call in regards to gas in a remote area that might be
"taken out of the ground, run through a set of processes" and
transited to the main pipeline or utilized for industrial uses.
12:32:13 PM
Mr. Dickinson referred to language in Sec. 28 (B) page 24 lines
9 through 19, of CSSB 305, which defined the point of production
for gas. The point of production for gas would be after
processing when it was "recognizable and measurable as gas". The
"notions of complete separation", which were included in current
definitions, were eliminated.
Mr. Dickinson noted that the definition of gas processing was
specified in Sec. 30 subsection (D)(18) page 25, lines 6 through
16; gas treatment was defined in Sec. 30 subsection (D)(19) page
25, lines 18 through 21 of CSSB 305. Gas processing would be
considered upstream of the point of production and that
investment would qualify for credits. Gas treatment would be
downstream of the point of production and while those expenses
could be deducted, investments in the gas treatment plant would
not qualify for credits. The "series of gas processes" were also
listed in Section 30 subsection (D)(18). As specified in Sec.
30(18)(A)(ii) and (iii), the purpose of gas processing was to
extract and recover liquid hydrocarbons. That process would be
upstream of the GTP or "an inlet to a system taking gas to
market".
Mr. Dickinson continued that gas treatment would "render that
gas acceptable for tender and acceptance into a gas pipeline
system". This would include the incidental removal of liquid
hydrocarbons (CO2) from the gas.
Mr. Dickinson stated that the Committee might consider "more
closely" defining the gas treatment process in order to further
separate it from the processing process. Specifically that the
definition of the "GTP for a major gas sale may not replicate as
easily if you take it to other places around the slope,
particularly ones that don't have any infrastructure already".
12:35:30 PM
Co-Chair Green asked whether language could be crafted to CSSB
305 to address that issue.
Mr. Dickinson affirmed that effort to further narrow the
"restrictions in gas treatment" were occurring.
12:35:55 PM
Senator Stedman asked that the Figure 8 flow chart be revised to
include the GTP and the point of production final metering
point. The effort should provide a clear distinction to whether
an activity would be considered upstream or downstream. In
addition, acronyms should be defined. The Legislature should
clearly depict those processes rather than having a "closed club
on what we're talking about".
Senator Stedman specified that "the point of production and
where the credits and the amount of credits are applicable to
which portion of this pie gets extremely important". "The
earlier we start solidifying some of this stuff the better". The
increased detail on Figure 8 was an improvement over earlier
diagrams.
Co-Chair Green asked whether the glossary of PPT terms [copy on
file] which had been previously provided to the Committee would
suffice as an acronym definition page.
12:38:12 PM
Senator Stedman opined that printing the definitions of acronyms
on each handout would be more beneficial to the public.
Legislators were advantaged in this regard, as they had more
resources.
Mr. Dickinson stated that an effort had been taken to reduce the
number of acronyms in today's handouts. For example, CGF was
defined on Figure 8. However, an effort to continually update
the glossary of terms would occur.
12:38:55 PM
Senator Hoffman asked how the gas treatment and gas processing
diagrams pertaining to the North Slope would apply to Bristol
Bay.
12:39:06 PM
Mr. Dickinson explained that a pipeline or a tanker facility
would be constructed in Bristol Bay. The point of production
would the point at which the gas or oil could be accurately
metered. Since those facilities would be independent of other
infrastructure, a diagram specific to them would be helpful.
Mr. Dickinson expressed that Mr. Hanley's concern would apply to
this area; specifically were a new facility built that held both
a treatment and processing plant. The Committee should develop
"the best tool" through which to identify where the separation
point between upstream and downstream processes would be.
12:39:50 PM
Mr. Hanley opined that part of the confusion was that the
definition of the processing activity made no reference to a
CGF. Thus, a person could not clearly distinguish whether the
CFG would be considered processing or treatment. Thus, he
"encouraged" the Committee to further clarify the distinction
between the CGF and the CTP.
12:40:45 PM
Co-Chair Wilken pointed out that CGFs were not unique to Alaska.
He inquired as to whether processing facilities were
traditionally considered part of the upstream or downstream
process.
Mr. Dickinson communicated there being no single industry-wide
standard. 100 pages of one [unspecified] publication were
committed to this "long litigated issue". Furthermore, the North
Slope differed "from most other places because of its
isolation." Thus the effort regarding the North Slope "has been
trying to take a series of market based definitions and then
work at them within the context of the North Slope …" In
general, the rule had been to "draw a difference between
transportation costs and getting ready for transportation
costs," such as treatment and further upstream activities. The
laws have had to adjust to advancements in technology.
Co-Chair Wilken understood therefore that this had been "a
subject of discussion and negotiation for every major … area".
Mr. Dickinson concurred.
12:42:33 PM
Issue 6. Re-openers. Discuss 30 year commitments and
suggest alternatives.
Mr. Hanley shared that it was "unclear" to some in the industry
whether "we will be able to get the certainty" of a long term
commitment. While it has been implied that certainty would be
provided in the gas pipeline contract, some companies viewed the
increasing tax take level proposed in the PPT to result from
Legislative concern "over a longer period that it may be locked
in". It was unclear as to how the gas pipeline contract would
affect this issue.
Co-Chair Green stated that addressing this issue at this time
might be "premature". It might be more appropriately addressed
in the gas pipeline discussions.
Mr. Dickinson communicated that "there is nothing in this
statute which is …. different from any other statute; there's no
re-openers in this statute per say. People are obviously looking
…down the road."
Issue 6 was withdrawn from the discussion.
12:44:23 PM
Issue 7. Incremental Cost/ bbl by ANS Cost (Sensitivity).
Discuss the incremental costs of lifting a barrel of oil as
ANS rises.
12:44:32 PM
Ms. Kah reiterated her previous remarks regarding the global
resource industry: barrel prices have increased 2.5 times and
costs have doubled. While prices might be becoming more stable,
costs have continued to increase. It would be expected that over
time, costs and prices would "equalize" even thought "they might
not be the same in any given year". ANS expenses had increased
faster than other areas in ConocoPhillips' portfolio due to
aging infrastructure and the production declines in certain
areas.
12:45:18 PM
Mr. Hanley proclaimed there to be a problem with establishing a
base trigger for Progressivity without a consideration of costs.
His argument would be that there was not a direct relationship
between the standard "consumer price index (CPI) and the costs
that occur in the oil industry". Dr. Kah had shared that in the
1980s, costs to the industry had actually decreased below the
CPI. Were a gas pipeline to come to fruition, he suspected that
drilling costs and development costs on the North Slope would
increase due to competition for steel and labor. Thus, basing
such things as Progressivity on net figures rather than on an
index would more appropriately reflect actual industry costs.
12:47:09 PM
Mr. Walker agreed. Such things as increased fuel costs, steel
costs, inflation, and global demand on industry goods and
services would increase industry costs as barrel prices rose. In
addition, "as volume declines, the unit cost per barrel
increases", for, as volume declined, the fixed costs of running
the infrastructure on the North Slope increased. This would
"underscore the need" to increase volume in the pipeline.
Co-Chair Green understood therefore that no standard formula
could be applied to "the relationship between the cost of a
lower price per barrel and a higher price per barrel".
Mr. Walker affirmed it would be difficult to apply a formula to
that process. Nonetheless, there was a clear relationship
between the two.
12:48:51 PM
Mr. Zager stated that as prices remained high, other types of
production would become more economical. He also noted that the
panel members, being producers, could not represent the entirety
of the oil industry in the State. Missing from the equation was
a vast number of service businesses. Like the State, the service
sectors "see the producers making lots of money". Therefore,
they are going to get their rent out of it. The value of their
stocks would increase faster than those of the industry because
"they are going to continue to extract rent out of the equation.
That drives their profitably." This would support Ms. Kah's
theory that other costs would eventually catch up.
12:49:46 PM
Senator Stedman expressed that more concrete rather than
abstract information should be gathered. The percentages of cost
increases for such things as labor and equipment should be known
rather than simply to accept a "blanket statement" that costs
would accelerate as prices increased. While there might be
"pressure on certain areas", the cost comparisons from last year
to this year would indicate that costs decreased. He advised
against generalizing.
12:50:53 PM
Mr. Walker questioned there being a decrease in costs, as his
company "has seen very significant pressure on costs in the
upward direction".
Co-Chair Wilken agreed with Senator Stedman that a more in-depth
discussion should occur regarding the relationship between
increasing revenue and costs, as he doubted that a 100 percent
increase in revenue would be accompanied by a 100 percent
increase in costs. He acknowledged that "incremental costs"
would be associated with an increased market place price for
oil.
12:52:10 PM
Mr. Dickinson affirmed that a more detailed answer to this
question would be provided.
12:52:24 PM
Ms. Kah disclosed that BP experienced 15 to 20 percent cost
increases over the past year. Those increases had affected every
aspect of their operation including drilling rates and other
services and labor. She shared that an intense competition for
manpower has also occurred.. "There is a serious manpower
shortage given the level of activity we have in our company
today." She identified replacement costs as being "the biggest
factor" in setting "prices in the long term". Those costs would
"affect what we actually see as an oil price in the market".
12:53:08 PM
Mr. Hanley could not disagree with Senator Stedman and Co-Chair
Wilken: costs might increase or decrease. They were difficult to
measure. However, costs would be taken into account were they
applied to the net, as actual expenses would be deducted from
the gross. This approach would remove the need to determine "an
index". The basis upon which the Progressivity trigger price
would be established was a separate issue.
Senator Stedman stressed that, during a more thorough discussion
on the mechanics of the Progressivity element, the issue of net
must include whether to "include or exclude the use of the
credits before we do the calculation". He would support
excluding the credits.
12:54:47 PM
Mr. Barnes observed that prices for products being sold "lead
the price for the services that are required to produce it". The
experience of the industry had been that "when prices are very
high, our costs went up". The "industry contracted" both times
prices decreased in the past 15 years. Experience has shown that
there is "an intrinsic lag time" following a price increase in
which there would be a shortage in personnel and material such
as steel. Care must be taken when seeking a relationship between
cost and price because of this.
Ms. Kah agreed with the concept of a net profit basis. There was
no single indicator to the question of cost. The effort would
require a manpower indicator, a drilling indicator, a material
cost indicator, and a fuel cost indicator. Utilization of a
general inflation indicator would not suffice as there was no
relationship between CIP inflation rate and the industry.
Therefore, the conclusion was that a net profits basis would be
the most appropriate means through which to account for industry
costs.
12:56:23 PM
Mr. Johnston asked for clarification as to whether the
references a net basis were to "the escalator for the
Progressive feature or are we taking about something based on
net verses gross as the tax base for this progressive based
tax". To further clarify his question, he stated that "if you
had an escalator that was based on just price increases" as was
the design presented in both the House and Senate committee
substitutes, "that's one thing and it doesn't take into account
costs. We know that and that's one of the weaknesses, there's no
doubt. In fact there's a bit of irony in inconsistency there to
try and create a progressive feature that's going to then govern
a ordinarily regressive tax that's a severance tax."
Mr. Johnston continued. "Now you could still leave the
progressive element based on oil prices as they've been
designed, but have that apply to a profits based tax. And that
way, if you have a producer that's agonizing over heavy oil with
the higher costs and the lower prices associated with that you'd
still use the same escalator but they have a lower profit and
therefore they pay less in taxes. Their tax rate might still be
too high perhaps, but… so there's two different ways of viewing
this issue of gross verses net, and I'm not exactly certain in
the minds of us here which one you guys are actually
contemplating, if not both perhaps".
12:58:06 PM
Mr. Zager replied that the "short answer is both, in that we've
got a net profits tax. Its going to be nominally set at 20
percent and the idea is that as profits per barrel grow then not
only will the amount you pay grow but the percentage of that tax
will grow. And so, that was the concept that you use a net
profits trigger to decide when you're making larger profits or
windfall profits and then you escalate that percentage as you
go".
Mr. Johnston understood therefore that the concept would be to
apply the tax rate determined by that to profits.
12:58:51 PM
Mr. Dickinson understood that the concept being proposed by the
producers would be to change both the tax rate base and the
progressivity element proposed in both the House and Senate
committee substitutes.
Co-Chair Green asked whether the Senate Resources Committee had
discussed utilizing net verses gross in the formula.
Senator Stedman affirmed that discussion had occurred.
12:59:48 PM
Mr. Johnston acknowledged there being "weaknesses" in the House
and Senate PPT proposals; however, as Mr. Dickinson had noted,
"the credits do apply to costs and, so, when you do have the
higher cost environment, that isn't accommodated with this
Progressive sliding scale, we do have the progressive element
from the credits themselves that do accommodate in a fairly
direct way a higher cost situation rather than a lower cost
situation. Dollar for dollar though it doesn't have nearly the
dramatic affect that the severance tax would, or the PPT tax
would".
1:00:29 PM
Senator Stedman reminded the Committee that the primary purpose
of the Progressivity issue "was to keep the regressive nature of
what we'd have without it at bay so as prices advanced, the
State's share stays relatively flat or slightly increases.
Without it we'd have a regressive system in place when we add
our taxes and royalties along with our PPT tax. So this is a
piece in there to fix an overall problem. And when we get in and
start meddling with going from gross to net and taking credits
in it and these other issues and setting different trigger
points that slide up and down with costs, at the end of the day
we still need to make sure it does what it is intended to do and
my concern is it gets neutralized and then we're at a regressive
state where prices advance and our percent goes down."
Co-Chair Green advised that the discussion had advanced to
include Issue No. 9.
Issue No. 9 Progressivity on net vs. gross. Discuss
options.
1:01:38 PM
Mr. Zager agreed with Senator Stedman's perspective; the
exception being that he would replace the phase "when prices go
up" to "when profits go up". This distinction would address the
"underlying assumption that profits and price are directly
linked. They are not, especially" over a lengthy time frame.
There could be a scenario "where your prices might go up, costs
could stay in parallel so our profits have not increased at all,
yet we're getting hit with an excess profits tax because the
price is much higher than originally conceived".
1:02:14 PM
Mr. Johnston specified however, that profits could increase even
in a scenario where both price and costs doubled. An example
would be a scenario in which barrel prices increased from $30 to
$60 and costs increased from $10 to $20 a barrel. The doubling
of prices and costs scenario would generate $40 in profits as
opposed to $20 in profits at $30 per barrel price with a ten
dollar cost per barrel.
1:02:42 PM
Mr. Zager communicated that a scenario in which a company's
actual profits doubled would trigger an escalator, as it was
tied to profits rather than to a percentage of profits. However,
were a $20 profit margin experienced at a barrel price of $60 as
well as $120, no escalator would be triggered. However, were the
rate structured on a percentage change, an increase in the rate
could be triggered.
1:03:15 PM
Mr. Johnston professed there being "a lot of virtue and solid
logic behind trying to make this more profits based as opposed
to a proxy for profits based" system. However, "getting from the
one", as Dan Dickinson would agree, "to the other" was a
"complex" process which would require a significant amount of
consultant time. The complexity of this process had been
challenging and "agonizing" to not only the Legislature but to
consultants as well.
Co-Chair Green acknowledged.
Mr. Walker added to the discussion pertaining to the
Progressivity question in Issue 9. The question revolved around
net verses gross. His company would prefer net "because it is
reflective of the profits".
Mr. Walker stated that the PPT provisions proposed in CSSB 305
were "too complicated. Alaska has a extremely complex fiscal
system and we would certainly encourage you to ultimately select
something that is transparent and as simple as possible".
Mr. Walker did not support the Progressivity component in CSSB
305. "We think the regressive nature of Alaska's tax regime
combined with Progressivity makes it less attractive. But if you
were to have progressivity, if you really feel that
progressivity is part of the ultimate solution, then we would
suggest steering you towards something very simple." A two tier
or three tier system has been suggested in which "you choose a
different production tax for different tiers, depending on the
price. And that tax rate could be chosen in the broad operating
band of prices as a tax rate that would genuinely attract
investment to Alaska so therefore we would say something lower
than 20 percent." When prices were high, the State "could
afford to adopt a slightly higher tax rate and get higher share,
and then at the very low prices, where everybody acknowledges
the industry is really struggling, perhaps adopt a significantly
lower tax rate when industry really does need some serious
help."
Mr. Walker concluded that there were numerous ways to revise the
tax structure. "And we would just say that if you are determined
that progressivity is part of the final solution, that we would
suggest something very simple. We'd also give credit to John's
[Hanley] proposal around trying to tie it to profits, because
moving it towards actual profits is always a good thing."
1:06:18 PM
Mr. Johnston specified "the conflict though" would be that
keeping it simple and having it based on net would be difficult.
It was actually quite simple as proposed. It's "one flaw" was
that "it's not profits based, not fully profits based. If we
depart from what has been proposed, it ain't going to be
simple."
1:06:46 PM
Ms. Kah characterized the original PPT bill, SB 305, as being
regressive and the Committee was "talking about making it even
more regressive". The industry considered CSSB 305's
Progressivity element, which would be triggered by higher oil
prices, to be a windfall profits tax. "We think its adding
complexity, particularly because it's on a different basis, it's
on the gross whereas the PPT itself is on profits. It's taking
away the upside which I think really does hurt our project
economics, so it will discourage investment and it will reduce
the production and jobs in the long term, even if it does have a
short term revenue benefit." However, were the Committee to
support the Progressivity component, the industry would urge
basing it "on a net basis. Do it on the same basis as the PPT
itself, and that would get rid of some of the complexity." In
addition, she urged that the trigger price for Progressivity be
set "at a high enough level that it would have minimal
interference with our project economics…"
1:08:02 PM
Mr. Johnston disagreed with the majority of Ms. Kah's
statements. He would not characterize a windfall profits tax as
"an evil thing". Since the provisions in the House and Senate
committee substitutes would slightly increase the State's take
beyond that proposed in SB 305, it would be "unfair" to suggest
that the State would be taking away the "upside" when prices
increased. The House and Senate's effort were for the State "to
participate a little bit more in the upside". He preferred the
progressive nature of the House and Senate bills to that
proposed in SB 305.
1:09:08 PM
Ms. Kah reminded the Committee that the windfall profits tax
levied by the federal government in the 1980s had been
detrimental to the nation's economy. Studies found that "it did
reduce investment in production and greatly increased imports in
the United States". BP's prospective projects were evaluated
under prices ranging from $20 to $80 a barrel. Probabilistic
weightings were applied to the various prices. Removal "of the
upside would lower the expected value of the project". It would
be unrealistic to think that that might not hurt a project's
economics.
Senator Stedman expressed that "the devils in the detail in this
one". There would be "a smaller probability of prices at $60 and
$80 than there is at $40 and $50 and $30". The proposal being
furthered in CSSB 305 differed from the federal windfall profits
tax as it would implement a tax to keep "the government take
basically flat".
Senator Stedman requested that the State's consultants provide
an analysis that would consider the lower probability of prices
ranging in the $70 or $80 range. He expected that the impact
would not be "very big". The progressivity issue was "not even
remotely close" to the federal windfall profits tax scenario.
This purpose of this effort was "to keep the government take
figures flat as prices" advance. A system that would balance the
State take over a range of prices would be preferred to one that
"was unbalanced into the disfavor the State".
Co-Chair Green asked whether the information requested by
Senator Stedman might have been previously provided.
Mr. Johnston affirmed that the information had been included in
one of the earliest PPT presentations.
1:12:04 PM
Mr. Johnston characterized the tax structures proposed by the
House and Senate as progressive in that they would not hold the
government take neutral as oil prices increased.
Mr. Johnston stated that the windfall profits tax levied by the
United States government "in the 1970s and 1980s was poorly
designed and didn't meet the objectives for which it was
designed". The United States' windfall profits tax was only one
of several nations' efforts that have existed. "Most of them
have worked fairly well at least in the eyes of the countries
that have them now. Most countries wish they had had them at
this point in time and most of them did not behave as poorly as
ours did back then."
1:13:08 PM
Mr. Zager revisited the "complexity issue". The PPT would
require companies to calculate their net profits each month
through a complex calculation methodology. Companies maintain an
accurate accounting of the number of barrels of oil produced
each month, "so the additional step of dividing the net profits
by the barrels and coming up with a number doesn't seem to add a
lot of complication".
Mr. Barnes stated that the complexity issue was a concern. "We
can all accept being taxed. We do that as citizens. We can all
accept a tax rate that changes, but you'd like to be able to
manage the issues that you manage." He was "worried about taxes
that are linked with either outside indices or events that are
outside of my control as an operator. If I can control my costs
better and I actually increase my profitably per barrel then
perhaps it is okay for that to be shared with the State".
Mr. Barnes stated that basing the PPT on basing the PPT on a net
basis "more accurately reflects the operator's ability to do his
business correctly and share whatever benefit he might create."
1:15:06 PM
Mr. Walker disclosed that BP had determined that, under CSSB
305, the State take would be 63 percent as compared to a 61
percent tax rate under SB 305. That 63 percent would increase to
67 percent were barrel prices to increase to $100. The Senate
system would be progressive. The objective of holding government
share flat as prices increased "would be a very different thing
that what is currently proposed". He would appreciate BP being
advised were its interpretation of the bill incorrect.
1:15:52 PM
Mr. Dickinson shared that the Administration would prefer to
make the windfall profits issue irrelevant, either by removing
the Progressivity element or by moving the trigger point to such
a high point, $100 or $120 for example, "that you're truly
dealing with extraordinary price interruptions. At that point,
net verses gross is not a real difference."
1:16:28 PM
Senator Stedman communicated that, absent the Progressivity
component, the State would experience a regressive tax system at
prices in the $40 to $70 a barrel range. This would not change
were the trigger point moved to a barrel price of $100 or more.
Senator Stedman stated that the goal was "to keep everything
kind of stable through the price ranges".
1:17:34 PM
Mr. Dickinson cautioned against confusing total government take
with State take.
Issue 8. Acceptability of 2 for 1 provision and
appropriateness of a sunset
1:18:02 PM
Co-Chair Wilken recalled that in prior meetings, Mr. Hanley, Mr.
Barnes, and Mr. Zager suggested that the seven year timeframe
for the two for one provision be increased. Thus, he inquired
how extending the time period to ten years would affect the
State. Currently this provision would allow investments made
five years prior to the effective date of the bill to qualify on
a two for one basis for seven years after the effective date.
1:18:50 PM
Mr. Johnston communicated that, while it was be unlikely that
the industry could recoup those costs in seven years, the State
would experience little, if any, difference were the time frame
extended to ten years. The two for one provision would offer "an
additional incentive for investment". He supported the look-back
provision to a certain extent. He was less concerned about the
termination date relating to this provision than he was to the
timeframes of such things as the $73 million allowance or the
$12 million credit or the 5,000 barrel per day exemption
provisions addressed in Issue 3.
Mr. Dickinson further clarified the math pertinent to this
provision. The two for one five year investment/seven year
recoupment period would require a producer to "spend 40 percent
more per year to make the total recoupment". Were the provision
to specify a one dollar recoupment for each dollar spent in a
five year period, the producer would have to "spend 70 percent
in each year to recoup the same amount over seven years".
Therefore, the two for one recoupment formula would require a
producer to double that expenditure to 140 percent per year over
seven years to recoup their investment. Were the seven year
recovery period expanded to ten years, a producer would be
required to spend the same amount per year "in those ten years
as you did in the five years prior because you'd be doubling on
the one end and halving on the other".
1:21:56 PM
Mr. Walker considered transition provisions to be appropriate
and appreciated the two for one recoupment provision included in
CSSB 305. It would be a good solution as more investment would
be required in the State. Industry requested that the transition
provisions be designed in a manner through which a company which
had invested capital could "genuinely take the benefit" of the
provisions. In addition, BP would suggest that "the $40 test" be
eliminated in order to allow the full benefit of the transition
provisions.
1:22:48 PM
Mr. Hanley stated that one's view of the transition provisions
would depend on "where you are in a point of time, and what your
plans are already". His company worked with ConocoPhillips on
many projects, including a 22 percent ownership of a $400
million dollars investment in two satellite fields in the State
during the past year and a half. Depending on what projects were
being considered, it might be unrealistic for his company to
invest an additional 40 percent. Companies planning to
participate in the construction of a gas pipeline would be able
to make such expenditures.
Mr. Hanley stated that his company's position would align with
that of the Administration. The desire would be to allow
investment recoupment without consideration of such things as
the two for one provision. In order to allow "the State to pick
up 40 percent of the costs", his company would have delayed its
recent work a year. Instead, his company's investment decisions
were based on the rules of the existing tax regime and high oil
prices.
Mr. Hanley acknowledged however that the two for one provision
would be an incentive for a company to invest more. His company
would be better served by a ten year recoupment timeframe.
1:24:50 PM
Mr. Johnston asked Mr. Hanley whether the pipeline expenditure
opportunity he had referenced was to Point Thomson and the
central processing facility pipeline expenditures, as only those
pipeline projects "would be eligible for the credits and applied
to this as well".
Mr. Hanley affirmed. A lot of dollars would be spent in existing
fields as well as in future fields.
1:25:58 PM
Mr. Hanley reiterated that the timing of a project's
expenditures was a consideration. A recent $100 million dollar
investment made by Pioneer Natural Resources was an example of a
project that would benefit from the two for one provision. That
company would be able to recoup that expenditure since it had
plans to spend an additional $300 million on the project in the
next few years. On the other hand, Mr. Hanley's company's
expenditure was made too early to benefit from this provision.
This was an example of the timing issue associated with the
provision.
Ms. Kah agreed with the remarks pertaining to this issue. BP was
appreciative of the two for one transition provision as its
plans would accommodate such expenditures. However, "as a matter
of fairness", a one for one recoupment provision would be "more
fair in terms of rewarding people who haven't delayed their
projects, who have been investing in the past".
1:26:42 PM
Mr. Barnes spoke to the investment scenario in Cook Inlet. It
would be difficult to determine whether a significant amount of
investments would occur there. "Not only is it being timed out,
but there is also the operating environment that you're in".
Thus, while the two for one provision would be of value, the
proposal included in the original bill would be the preferred
approach.
1:27:15 PM
Co-Chair Green asked Mr. Dickinson whether consideration had
been given to allowing a company to choose between two options.
A company such as Anadarko might be better served by a five year
look-back program while a company such as BP or ConocoPhillips
might be better served by the two for one provision.
1:27:49 PM
Mr. Dickinson stated that providing two options could be
considered. SB 305 specified that a company would "get the
recovery if you had come in and spent". If the company left the
State, no recovery would be forthcoming as "you would need
something to take it against so there would have to be
continuing economic involvement". That was a very important
consideration to the Administration.
1:28:34 PM
Co-Chair Wilken stated that it was a struggle to keep abreast of
"all these moving pieces" in this legislation., To that point,
he asked whether the two for one component would be considered
"a major or minor portion of moving from the 16 percent net tax
… closer to the historical rate" depicted on Chart 90.
Discussion ensued between Co-Chair Wilken, Mr. Dickinson, and
Mr. Johnston about how two for one component might impact the
graph lines on Chart 90.
Mr. Walker joined the conversation and specified that a company
would only benefit from the two for one component were it to
continue investing in the State.
1:30:40 PM
Mr. Dickinson clarified that the information on Chart 90 was
based on SB 305, which did not contain the two for one
provision. That provision was included in CSSB 305.
Issue 9. Progressivity on net vs. gross. Discuss options.
Co-Chair Green stated that this issue had been addressed earlier
in the discussion.
Issue 10. Cap on Progressivity. Discuss options
1:31:53 PM
Mr. Walker stated that "clearly the concept of having uncapped
progressivity would be very dangerous" because of such things as
market conditions, and price and cost changes.
Co-Chair Green understood that the industry was opposed to
Progressivity. Thus, were one included in the PPT, the industry
would support an upward limit on it.
Mr. Johnston stated that consideration of a limit should "depend
on the nature of the Progressivity". However, imposing a limit
would be "a contradiction in terms" for "if you're going to be
progressive, you're progressive".
1:33:07 PM
Co-Chair Wilken assumed chair of the meeting.
1:33:26 PM
Issue 11. Progressivity trigger. Discuss options
Co-Chair Wilken noted that a variety of trigger points from $40
upwards had been discussed.
Mr. Dickinson emphasized the fact that the higher the dollar
amount of the Progressivity trigger, "the less impact there
would be on investment decisions". Thus, he hoped the Committee
would "take it out of the range where it would negatively impact
investment decisions".
Co-Chair Wilken expressed that that point would be "a function
of modeling and a general comfort level of those who have to
make the decision".
Mr. Dickinson stated that even though investment decisions
consider a wide range of oil prices, the industry would not rely
on the high price to support a project's basic economics. The
decision would instead be "how robust is this under various
prices".
1:34:35 PM
Mr. Johnston stated that the issue of how far to increase the
price of the Progressivity trigger would be "a function of the
slope of the progressivity element. He would be uncomfortable
with a starting point much greater than $40 per barrel,
considering the slopes being discussed.
Co-Chair Wilken stated that one factor in making the "final
decision" would be whether the ultimate goal was to maintain "a
relatively flat" or to slightly increase government take.
1:35:36 PM
Mr. Johnston stated that the inclusion of a Progressivity
element in the PPT would indicate that the Legislature was not
content to maintain "a relatively flat overall" or neutral
government take. The progressive element "must be sufficiently
aggressive to overcome the regressive affect of the royalty, but
it is aided to a certain extent by the progressive affect of the
credits. The credits almost in and of themselves neutralize the
royalties that exist and that's why the system as it's proposed
by the Governor was fairly neutral". SB 305 actually held
Government take fairly constant under most circumstances.
Mr. Johnston stated that "if we agree that it should be a system
that's progressive" then the question was how progressive should
it be. "Part of the answer to that question is looking around
the world to see how progressive systems are when they are
progressive. About 20 to 25 percent of the systems in the world
are progressive to one degree or another". He considered a
Progressivity feature that increased government take by five
percent to be "fairly modest by world standards as far a
progressive systems go". A five percent increase, in his
perspective should be the "absolute minimum". The State should
not impose "the least progressive of all the progressive systems
on this planet. And I don't think we necessarily need to be
average in that regard, but the slope has got to reflect our
views of what would be appropriate and we're just on the low
side in my opinion as its designed now in both the House and the
Senate".
1:37:59 PM
Ms. Kah rebutted that it would be "particularly important to
minimize shaving off the upside for Alaska" because Alaska "is
viewed as a price play in our portfolio" due to the high cost of
doing business. Imposing Progressivity on "the upside above $40
a barrel" would be detrimental to the "attractiveness of Alaska
in our portfolio". She urged the Committee to increase the
Progressivity trigger point to the upper range of the prices
considered in the industry's economic modeling".
Mr. Walker noted that the government take at $40 a barrel under
a 20/20 tax regime would be 66 percent. At $20 per barrel it
would be 115 percent. "It takes a long time for you to move away
from the fact that you already have a regressive regime that
takes royalties from gross revenue. And the government take at
low to medium prices is very high". Therefore, setting the
Progressivity trigger point within a $40 to $60 a barrel price
would curtail the benefits to industry and "therefore the
attractiveness of Alaska."
1:39:16 PM
Co-Chair Green resumed chair of the Committee.
Co-Chair Wilken asked regarding the calculation supporting the
66 percent government take number.
Mr. Walker stated that that number was based on "BP's
financials".
1:39:31 PM
Senator Hoffman also asked for further information in this
regard.
Mr. Walker stated that at $20 per barrel, the government take
was 115 percent. At $40 per barrel the government take was 66
percent and at $60 per barrel the government take was 62
percent. BP had previously provided this information, but could
redistribute it.
1:40:04 PM
Mr. Johnston communicated that revisiting these numbers would be
helpful. BP's government take statistics at those prices
differed from information provided by ConocoPhillips.
1:40:26 PM
Mr. Bramley expressed that Mr. Johnston might be referring to
ConocoPhillips' statistics which were specific to a new 50
million barrel field. That calculation indicated that both the
existing system and the PPT as proposed in SB 305 "were quite
severely regressive at lower prices". At a price of $20 per
barrel the government take on that new field would be
approximately 70 or 80 percent.
Mr. Walker clarified that the information provided by BP
reflected how the PPT would affect the entirety of BP's
operations in the State.
Co-Chair Wilken referred to an unspecified chart [copy not
provided] and asked Mr. Walker to confirm that at a $40 barrel
price, the total government take under ELF would be 63 percent.
Total government take under the PPT at that price would be 66
percent. The total government take at $60 would be 57 percent
under ELF and 62 percent under the PPT. The State's portion of
the government take at $40 under PPT would be 44 percent and the
State take at $60 would be 40 percent.
Mr. Walker affirmed.
1:42:41 PM
Senator Hoffman clarified that these numbers pertained to SB 305
and therefore would "not reflect the higher numbers" in either
the House or Senate committee substitutes.
Mr. Walker appreciated Senator Hoffman's clarification. BP's
statistics were based on the 20/20 PPT as proposed in SB 305.
The State take would increase under the House or Senate
committee substitutes; BP's take would decrease.
Co-Chair Wilken clarified that the BP statistics reflected the
government take under the original PPT bill.
Mr. Walker affirmed.
1:43:28 PM
Issue 12. Cook Inlet Provision, Should Cook Inlet be
treated differently
Mr. Zager recognized Cook Inlet as being "very different from
the North Slope", since Cook Inlet does not compete for capital
on the global market, and a comparison to other regimes with
escalators would not be applicable. Cook Inlet competed only for
domestic capital. It would be appropriate to treat Cook Inlet
differently as it was very mature in its life cycle.
Senator Hoffman asked whether the Nenana Basin and Bristol Bay
should also be treated differently.
Mr. Zager stated that would be a policy call. There was "good
rationale" for treating those new and isolated basins
differently.
Senator Dyson asked how providing royalty relief would affect
Cook Inlet, as he understood that the credits and other
provisions in the bill would provide "a significant boom for
Cook Inlet explorers" in both their successful and unsuccessful
exploration efforts. That was not currently the case. He asked
for further information about how the tax credit and royalty
might interplay and what the Legislature might do to royalties
that might further incentivize gas exploration and production in
Cook Inlet.
1:45:37 PM
Mr. Zager understood that the royalty reduction would apply to
certain Cook Inlet oil platforms were they to fall below certain
production levels. This bill would expand incentives; only
remote fields or successful efforts had previously "enjoyed"
such benefits. The PPT would provide additional incentives for
gas exploration in Cook Inlet. He had not considered how the
royalty structure could be changed to further encourage gas
exploration, as he understood they were to continue status quo.
1:46:22 PM
Mr. Barnes stated that the provisions of CSSB 305 would provide
"better predictability" about credits and royalties. This would
allow a company to make knowledgeable decisions to things within
their control or things that "are predictable as opposed to
what's going to be discussed or negotiated". Anything that could
be factored into a projects' economics would be beneficial to
investment decisions.
Mr. Barnes reiterated that Cook Inlet should be treated
differently, particularly in consideration of its marginal and
aging fields. These considerations were addressed in ELF and
should be considered in the PPT. Credits might not be the
appropriate tool for a company might find itself in a position
"where you will not spend money to try to recover lost taxes.
That's the future of every oil field and gas field in the
State." Taxes would increase operating expenses, and as a
result, increase what would be "required to pay your bills and
you'll shut in fields sooner, you'll reduce ultimate recovery,
which is reserves, and you'll reduce near term production."
Mr. Barnes appreciated the discussion regarding "how steep the
State take is at low prices", as the term "low prices was
surrogate for the word low margins". Cook Inlet "is a test case
for what will become of all the other basins in the field, its'
just a matter of time".
Mr. Barnes responded to Senator Dyson's question by stating that
any tool that was "predictable and that works around the
margins" "would be worthy of discussion.
1:48:58 PM
Mr. Johnston observed that while the credit provisions contained
in the bill "have a lot of virtue" in regards to furthering
exploration and development investment in the State, they would
not offer "downside protection" to oil companies or assist in
"extending the life of an otherwise marginal field or dealing
with a situation where oil prices get quite low".
Mr. Johnston pointed out that the concern about government take
exceeding 100 percent was not limited to Alaska. This scenario
would "more likely" occur in Alaska's since many of its marginal
fields were approaching their economic limit. A profits based
tax system would not provide relief on a marginal field because
it was tied to profits. In contrast, royalty taxes could be
adjusted downward as they are not based on profits. This
mechanism has been used under ELF to "accommodate the marginal
platforms in the Cook Inlet".
Mr. Johnston stated that the credit provisions contained in the
PPT proposal would assist in furthering exploration; however,
"at $20 a barrel or $25 a barrel there's nothing you can do with
this fiscal system, as far as Cook Inlet is concerned for sure.
And as far as the North Slope, and some of those places, as $20
to $25 a barrel, there's almost nothing you can do with this
fiscal system and so I say don't worry about that so much."
1:50:46 PM
Senator Dyson could not pinpoint the cause of his frustration:
it could be "his ignorance" of the subject, his inability to
properly pose his question, or "the feeling that you guys didn't
answer my question". Continuing, he asked for confirmation that
the State's royalty tax on gas in Cook Inlet was approximately
12.5 percent.
Mr. Barnes affirmed that the royalty tax rate in Cook Inlet was
12.5 percent.
Senator Dyson thus questioned whether lowering that tax rate
further would encourage gas exploration in Cook Inlet.
Mr. Barnes apologized for not directly answering Senator Dyson's
earlier question. The complication on "straight royalty relief"
in Cook Inlet was that there was also private and federal
royalty taxes in addition to the State's royalty tax. Thus,
while the State had alleviated some of its royalty impact, "in
the past, the track record on actually achieving royalty relief"
had been mixed. This was a complicated issue.
1:52:56 PM
Senator Dyson asked Mr. Johnston to explain why more effort had
not been applied to the gas royalty issue.
1:53:21 PM
Mr. Johnston responded that "royalty relief, if it could be
accomplished, would make a difference, no doubt". However, one
should be mindful that gas royalty rates were not a significant
issue in Alaska as its gas reserves were remote and less
valuable than oil. On a worldwide scale the typical government
take on gas was ten percent lower than the oil tax rates.
Alaska's terms were inline with the majority of other gas tax
terms.
Mr. Johnston thought that the $73 million credit provisions
included in SB 305 would have encouraged gas exploration when
gas prices were "sufficiently high". Even though that provision
was changed in the House and Senate PPT bills, were the royalty
rate cut "in half … you'd get these guys attention".
Issue 13. Transitional Capital Look-Back. Discuss options
Issue 14. Impact on PPT on Facility Access Fees
Issue 15. Profit in Tankering/Pipeline. Should profit in
transportation be included as a cost.
Issue 16. Effective Date. April 1, 2006 or July 1, 2006
Issue 17. 95% safe harbor and quarterly true-up. How the
industry is treated by other tax collectors
Co-Chair Green noted that due to other Legislative commitments,
the hearing must conclude. To that point, she asked the
panelists to provide written responses to the five issues that
had not been addressed, particularly Issues 13, 16 and 17.
Co-Chair Green thanked the panel for their participation.
The bill was HELD in Committee.
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