Legislature(2013 - 2014)BARNES 124
02/11/2013 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB72 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | HB 72 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 72-OIL AND GAS PRODUCTION TAX
1:03:11 PM
CO-CHAIR FEIGE announced that the only order of business is
HOUSE BILL NO. 72, "An Act relating to appropriations from taxes
paid under the Alaska Net Income Tax Act; relating to the oil
and gas production tax rate; relating to gas used in the state;
relating to monthly installment payments of the oil and gas
production tax; relating to oil and gas production tax credits
for certain losses and expenditures; relating to oil and gas
production tax credit certificates; relating to nontransferable
tax credits based on production; relating to the oil and gas tax
credit fund; relating to annual statements by producers and
explorers; relating to the determination of annual oil and gas
production tax values including adjustments based on a
percentage of gross value at the point of production from
certain leases or properties; making conforming amendments; and
providing for an effective date."
1:04:07 PM
DAN SULLIVAN, Commissioner, Department of Natural Resources
(DNR), began his co-introduction of HB 72 with Commissioner
Bryan Butcher, Department of Revenue (DOR), by way of a
PowerPoint presentation entitled, "A Durable Tax System that is
Competitive for the Long Term." He said HB 72 is important to
the state, present-day Alaskans, and future generations. The
presentation will provide a background of the Trans-Alaska
Pipeline System (TAPS) challenges, review the investment that is
happening throughout the U.S. and the world which is hitting
all-time records, and show that the TAPS throughput decline is
not inevitable. He said the basis for the bill comes from the
integrated efforts of DNR and DOR. He shared that he just
returned from the North American Petroleum Expo (NAPE) meeting
in Houston, Texas, where the state made a presentation and he
had the opportunity to meet with several companies.
1:06:50 PM
COMMISSIONER SULLIVAN said TAPS is a critical state and national
energy infrastructure asset [slide 2]. The history of TAPS
shows the important role played by the federal government, and
Congress in particular, in getting TAPS up and running. That
federal partnership is needed to turn around the throughput
decline, but it has not been seen. At one point TAPS carried
2.2 million barrels a day, representing 25 percent of U.S.
domestic production [slide 3]. [The decline] is important and
urgent to the state. Referring to the "giveaway" discussion
that has occurred over the past several years, he maintained
that the ultimate giveaway is the loss of 40,000 barrels per day
over the past year that is no longer in the pipeline or in
Alaska's economy. That is about 14.7 million barrels lost over
the past year, which at $100 per barrel is about $1.5 billion
that is gone and no longer in the Alaska economy, whether in
state coffers or circulating around the economy. That is the
giveaway the administration is trying to turn around.
1:09:24 PM
COMMISSIONER SULLIVAN turned to a graph depicting the challenge
of declining Alaska North Slope (ANS) production [slide 4]. He
stressed that a mature field, like Prudhoe Bay, is not the same
thing as a mature basin. Significant opportunity for both
conventional and unconventional oil still exists on the North
Slope. He related that in his meetings with other companies,
the consistent theme is that almost every company sees this
basin as providing enormous opportunity.
COMMISSIONER SULLIVAN pointed out the urgency to the state of
the TAPS throughput decline challenge [slide 5]. Two years ago
TAPS had a shutdown when it was 40 degrees below 0, and although
the state dodged the bullet it was not clear at that time
whether the pipeline could be brought back up. This issue is
not a scare tactic, but a problem that is in the present. The
lesson learned is that the lower the TAPS output, the more risk
like what happened two years ago. Companies are certainly going
to be spending more dollars to maintain the infrastructure to
avoid these kinds of technical challenges, but that has
consequences for tariffs and less revenue for the state, and for
companies that want to come to Alaska. The best way to address
any of these challenges in technical aspects of a premature TAPS
shutdown is to get more oil in the pipeline.
1:11:53 PM
COMMISSIONER SULLIVAN said the state has many positive things
going for it to address this challenge [slide 6]. Number one is
that the North Slope is a world class hydrocarbon basin that is
still relatively unexplored. He related that the administration
thinks the state has enough resources, and the potential for
resources, to secure the state's future for decades to come, an
important point for how to address the TAPS throughput
challenges. Turning around the TAPS throughput challenge is
going to require billions of dollars of additional investment
[slide 7]. The North Slope is one of the few places in North
American where both large conventional and shale oil plays can
be looked for at the same time.
1:13:42 PM
COMMISSIONER SULLIVAN stated that when looking at HB 72, an
important consideration is the energy production going on in the
U.S. and globally [slide 8]. The "World Energy Outlook 2012"
report, put out by the International Energy Agency (IEA),
predicts that the U.S. will be the largest producer of oil and
gas by 2020. This huge renaissance of oil and gas production
bodes well for Alaska. Plus, there has also been a huge boom in
global investment in oil and gas exploration and production.
Last year the Financial Times estimated that about $600 billion
was spent on exploration, much of that going to countries in the
Organisation for Economic Co-operation and Development (OECD),
which includes the U.S. The good news is that for 2013,
[exploration and production] spending is projected to be $650
billion. The more depressing news is that in 2012 Alaska got
about one-half of one percent of that, despite sitting on still
one of the world's great hydrocarbon basins. He said Alaska
needs to be leading, not an anchor, on this American energy
production renaissance and needs to be focused on becoming more
competitive to get in on this boom in exploration and production
investment that is predicted to continue this year.
1:15:41 PM
COMMISSIONER SULLIVAN said the administration, as well as the
companies, believe Alaska has the geology [slide 9]. A global
investment boom is happening, but the question still remains as
to whether [Alaska's production decline] can be turned around.
The administration looked at whether other basins have turned
around their throughput declines and found that their declines
have not only flattened out but have come back up. The articles
shown on slide 9 are examples of what is predicted to be a very
strong investment boom in the United Kingdom's (UK) oil and gas
sector. A couple years ago the UK raised its oil and gas
production taxes and not surprising was a decline. So the UK
government reformed its taxes which resulted in an immediate and
significant impact on investment and jobs, an analog to Alaska
that is very relevant.
1:17:41 PM
COMMISSIONER SULLIVAN pointed out that there are many examples
in individual fields, as well, one example being the Forties
Field in the North Sea [slide 10]. Apache Corporation acquired
that field from BP and with investment and technology the
decline was reversed. It is important to learn lessons from the
many examples that are being seen all over the globe, he said.
Alaska is one of the few big basins not seeing a turn around and
it is important to address that [slide 11]. The administration
is addressing that by undertaking a comprehensive plan. A
missing piece with regard to competitiveness is the issue of
making Alaska's tax regime more competitive. Common themes
heard at last week's North American Petroleum Expo (NAPE) were
the recognition of a huge resource basin on the North Slope,
enormous opportunity, but also the cost. In particular,
questions were being asked about Alaska's taxes and more
specifically about progressivity. He found that companies are
keeping an eye on what is happening in Alaska this legislative
session and Alaska's competitiveness is at the forefront for
those companies that want to invest in the state.
COMMISSIONER SULLIVAN said important activity is happening in
Alaska [slide 12], but that only the surface is being scratched
in terms of the multiple billions of dollars of investment in
Alaska necessary to turn around the TAPS throughput challenge -
and those dollars are out there. While there is a good start
with a diversity of players and resource plays, a lot more can
be done and tax reform is a critical component of that.
1:21:01 PM
BRYAN BUTCHER, Commissioner, Department of Revenue (DOR),
reviewed the governor's four principles of tax reform [slide
13]. He said the base of looking at these principles has to
come from a point of trying to make Alaska competitive. At
current prices, Alaska has the highest oil taxes in the U.S.,
the highest in North America, and the second highest of all OECD
countries, being second to Norway. If oil prices went up $10
per barrel, Alaska's taxes would surpass Norway. Alaska has
extremely high taxes at the high oil prices seen over the last
five years. Combined with Alaska being one of the most
expensive places to explore, develop, and produce oil, it is no
surprise that Alaska is not seeing a lot of the investment,
development, and production that is occurring in many other
areas in the world, including many jurisdictions with far less
oil than the state of Alaska.
1:22:20 PM
COMMISSIONER BUTCHER specified that the first of the governor's
four principles is that tax reform must be fair to Alaskans,
which means Alaska needs to be competitive while keeping a fair
share in both the short and long term. The second principle is
to encourage new production. While this needs to be done in new
smaller fields, it is vital that it also be done in the current
legacy fields. The DOR long-term production forecast predicts
that, over 10 years out, over 50 percent of the oil expected to
be produced will come from legacy fields. The third principle
is that it needs to be simple so that it restores balance to the
system. Right now Alaska takes a disproportionately large share
on the high end and a very small percentage on the low end. The
result is that when the price of oil is low and the state really
needs the income, it sees very little income; and on the high
end the state brings in larger surpluses than needed to meet its
budget. The bill looks at trying to balance the system in this
regard.
1:24:10 PM
COMMISSIONER BUTCHER, continuing his discussion about the third
principle, said that in addition to restoring balance, Alaska's
tax structure needs to be simple. Alaska has one of, if not the
most, complex tax structures for oil in the world. Companies
looking at investing in Alaska have had difficulty figuring out
the entire picture for Alaska's [complex] oil tax structure:
what it means at certain price levels, how the progressivity
works, how the tax credits work. For example, Texas has just
the 1 percent and North Dakota has 8.5 percent up to $50 per
barrel and then 11 percent. In talks with jurisdictions all
over North America as they were turning around and Alaska was
not, the emphasis was on simplicity. A good example is the
state of North Dakota which has just one person working on oil
taxes because it is simply a matter of multiplying what is
produced times the price times a certain percentage. It is very
difficult for a new company to understand Alaska's tax system
well enough to be able to explain to its board of directors what
an investment in Alaska would mean. That the tax has to be
calculated monthly, rather than yearly, makes it even more
difficult.
1:25:49 PM
COMMISSIONER BUTCHER moved to the governor's fourth principle:
the tax system needs to be durable for the long term. He said
Alaska's oil taxes have been changed a number of times in the
last seven years and now it's looking at changing them again.
When a state is constantly changing its tax structure, a company
that is contemplating where to invest is unable to determine
what is going to happen to its investment over the 10-year to
30-year period of investment. He related that the governor is
hoping to set up a tax system that will work short-term and
long-term and will work for current producers and new entrants
and that over a longer period of time is something the companies
can rely on.
1:27:02 PM
COMMISSIONER BUTCHER noted the team working on [oil tax reform]
is much more integrated than it has been previously, with
expertise from DOR and DNR brought to the table, along with the
expertise of consultant, Econ One Research, Inc., that was asked
to analyze where Alaska is and is not competitive. Econ One is
familiar with Alaska, having worked over the years on oil taxes
and gas issues for the administration and the legislature. He
highlighted the process the team went through [slide 14], saying
the team began with a review of previous work by both the
administration and the legislature from the time of the economic
limit factor (ELF) to the production profits tax (PPT) to
Alaska's Clear and Equitable Share (ACES). The team identified
what it considers problems with the current tax system:
declining production, competitive environment, progressivity,
and tax credits. Additionally, the team looked at the impacts
of production decline not just on revenues, but also on the
Trans-Alaska Pipeline System (TAPS).
1:29:42 PM
COMMISSIONER BUTCHER next looked at the jurisdictions in North
America that are the largest oil producers along with the state
of Alaska [slide 15]. He explained that the green dotted line
on the graph is the price of oil, which bounced up and down
between 1977 and the mid-2000s but which has had a sustained
price increase over the last 8 years except for one dip that
came right back up. Turning to the states depicted on the
slide, he noted that North Dakota had very little production for
decades, but then had a giant jump when the price of oil went
up, surpassing Alaska in production. He explained it was not
economic to produce shale oil in North Dakota until oil rose
above $70 a barrel; therefore, if today's price was $40-$50,
that upturn would not have been seen. Higher oil prices
combined with technology created the jump in North Dakota. He
said this same thing happened in Alberta - once oil prices
became sustained at higher than $30 per barrel it became
economic and profitable to produce northern Alberta's oil sands.
1:32:16 PM
COMMISSIONER BUTCHER, continuing his look at oil producing
states [slide 15], directed attention to a comparison of Texas
and Alaska. He pointed out that Texas, which has produced oil
much longer than Alaska, began a production decline in the mid-
1970s while Alaska was on its production increase that peaked in
the late 1980s at 2.1 million barrels a day, at which point
Alaska and Texas come together. For the most part over the next
decades the Alaska and Texas declines were almost identical.
Then came the 2004/2005 jump in oil prices, at which point Texas
flattened out and then began turning around. Alaska,
unfortunately, has continued the decline that Texas would have
seen had the price of oil not jumped. Unlike North Dakota where
the increased production is from shale oil, the turnaround in
Texas was almost 100 percent from conventional oil, until the
upward shot of the past two years that is almost entirely due to
oil shale. Thus, the high prices allowed a state that was on
the same decline as Alaska to turn around. Commissioner Butcher
added that, similar to Alaska, the North Sea had a mature field
that was declining; but this area has been turned around a
couple of times. "The idea that once an oil field is declining
is simply not true," he said. He related that the U.S.
Geological Survey (USGS) does not consider Alaska's North Slope
to be a mature oil field because over 70 percent of it remains
minimally explored, if at all. The tendency is to think
specifically about only Prudhoe Bay and Kuparuk, but Alaska has
lots opportunities and their sizes and levels need to be found.
1:35:04 PM
COMMISSIONER BUTCHER compared a 50 million barrel development in
Alaska to comparable developments in the Lower 48, Norway, and
the United Kingdom's North Sea [slide 16]. At a price per
barrel of $100 and a net present value (NPV) discounted at the
industry standard of 12 percent, a company would earn: $4.07 in
Alaska, $5.52 for unconventional oil in the Lower 48, $2.34 in
Norway, and $8.25 in the North Sea's brownfield, which has seen
the real jump in investment over the last year. Ideally, Alaska
would be more competitive with countries and states that are
seeing jumps in investment; the closer Alaska gets to Norway the
less likely its competitiveness.
1:37:05 PM
COMMISSIONER BUTCHER said progressivity is complicated and
unpredictable, for both the state and investors [slide 17].
Alaska's tax includes a 25 percent base rate, increasing by 0.4
percent for every $1 per barrel that the production tax value
exceeds $30 per barrel up to $92.50 per barrel, at which point
it goes down to 0.1 percent per dollar until the total tax rate
equals 75 percent, a cap the state has yet to come close to. He
noted the production tax value (PTV) is the price per barrel
minus transportation costs minus lease expenditures.
Progressivity is calculated monthly. He pointed out that when
state-by-state comparisons are made on oil tax rates, Alaska is
frequently listed as 25-75 percent. Unrealistic as that 75
percent number is, when companies are looking at 7 percent in
Texas they may take a step back before even digging into the
complex nature of progressivity. Alaska's tax system also has
high marginal tax rates. At today's higher oil prices, 80
percent of each increasing dollar goes to the government, most
to the State of Alaska, some to the federal government.
Alaska's high marginal rate means that at high prices, companies
do not get as big a bite as they would in other jurisdictions
[to make up for losing money at low oil prices].
1:39:31 PM
COMMISSIONER BUTCHER reviewed a graph of Alaska's production tax
credits [slide 18], saying this was a piece the administration
looked at when focusing on what should be in the bill. Shown on
the graph in red are credits applied against production tax
liability; these are companies that take their tax credits off
what they owe in taxes to the state. Shown in grey are tax
credit certificates refunded; these are companies doing work
that qualifies for tax credits but that are not producing, are
not paying taxes to the state, so the state pays the credits in
cash to these companies. The state is paying a tremendous
amount of money in credits, he said. To determine whether these
credits are leading to new production, DOR put together a five-
year look back from ACES to today. A direct connection between
the tax credits and production was not seen, but rather a
connection to increased spending. In particular, the state is
looking at $800 million in the current fiscal year and
potentially $1 billion in fiscal year 2014. At high oil prices
these numbers tend not to be noticed because they are one piece
taken out of a very large amount of money coming into the state.
However, Commissioner Butcher cautioned, as everyone knows, oil
prices go up and down, and if oil prices dropped to $80 or $90
per barrel the State of Alaska would find itself in billions of
dollars of deficit. These tax credits are not price sensitive,
so if oil prices dropped to $60 or $80 per barrel the state
would still owe $1 billion. While the focus is on areas in the
budget that need to be funded, there is still that number of $1
billion. This number would mean one thing if it was directly
connected to a future production, but it means quite another if
there is not that connection.
1:42:56 PM
REPRESENTATIVE P. WILSON asked whether DOR's look back found
that tax credits were given to companies for doing maintenance
that would have been done anyway.
COMMISSIONER BUTCHER replied that, until this current year, this
was something DOR was unable to define in enough detail to know.
When DOR started this process two years ago, the department
heard from this committee that it needed to be known what the
state was getting for these tax credits. In DOR's defense, he
pointed out that the department had to write up and administer
over 70 regulations with the passage of ACES, so the focus was
on that rather than this detail. In its five-year look back,
DOR asked the companies to voluntarily provide more information,
but this information could not be required because DOR was
looking back. While the companies were helpful and are
following the law, it was still not enough information to define
specifically and DOR was unable to connect it directly to
production. Starting this calendar year, 2013, DOR is requiring
much greater detail from the companies, so going forward DOR
will be able to provide a better snapshot.
1:44:55 PM
CO-CHAIR SADDLER concluded from slide 18 that lots of cash is
walking out the door - $800 million to $1 billion. He inquired
whether there is any importance or information that should be
attached to the ratios of what is actually being applied to
production versus not.
COMMISSIONER BUTCHER responded DOR focused on that but did not
really come out with a determining. [The ratio] has been more
or less 50:50, but DOR has not figured out specifically why that
might go back and forth.
COMMISSIONER SULLIVAN interjected that the [graph on the] slide
makes the point that the grey areas are cash payments out the
door without any kind of tie to any production.
1:46:05 PM
REPRESENTATIVE SEATON remarked that he is confused as to DOR's
direction here. He recalled industry's strong testimony during
development of PPT and ACES that trying to tie directly to
production was counterproductive because the lead time from
investment to actual production was so long that the value of
the state's participation was drastically diminished if it was
based on sometime proving that oil went into the pipeline rather
than based on investment up front. He further recalled industry
testifying that it most needed help with exploration because of
the potential for a dry hole. However, what he is hearing from
DOR now is that the state does not want to give credits to risky
exploration but instead to tie credits only to things that can
be demonstrated as production.
COMMISSIONER BUTCHER pointed out that the administration is not
looking at eliminating these credits, but at reimbursing them
when there is production. In looking back over a six-year
period, DOR did not need to see exactly that receipt of X
produced Y, but the department did not see anything. In looking
at the fields potentially coming on over the next 5 to 10 years,
there is not a whole lot there. The expectation in spending
billions of dollars from the state treasury was that it would
lead to something. The North Sea saw $50-$60 billion in
investment. If, as hoped for, Alaska got $20 billion in new
investment from new companies over a number of years, the state
would be looking at paying out $8-$12 billion in cash to these
companies. He said he does not even know that the treasury
could make it to the point in which there would potentially be
production if the state got the kind of boom and investment
under its current tax structure that Commissioner Sullivan's
work would hope to lead to.
1:49:55 PM
COMMISSIONER BUTCHER, returning to his presentation, discussed
tariffs in TAPS [slide 19]. He shared that a growing concern
was identified with DOR's revenue modeling, which did not
dynamically link throughput with TAPS tariff rates or capture
any added capital expenditure ("capex") or operating expenditure
("opex") for low-throughput mitigation measures. This means DOR
would look forward one to three years to determine what would
happen to the tariff as lower throughput occurred and what the
expected effects would be to the State of Alaska. [Preliminary
observations are that] low flow mitigation capital and operating
expenditures could increase tariffs by as much as $1 (18
percent) per barrel by 2019 and as much as $2.50 (33 percent)
per barrel in 2022. [Assuming the price, production, and tariff
used] in DOR's Fall 2012 Revenue Sources Book, a $1 increase in
the TAPS tariff will decrease state oil and gas revenue by an
average of $110 million. While there can be argument about how
many decades the pipeline has left, he stressed it is known that
the decline in throughput is causing more problems due to
cooling of the oil and more water, which requires more capital
spending which then results in tariff increases that
subsequently reduce the revenue the state gets from its 12.5
percent royalty oil.
1:52:05 PM
COMMISSIONER BUTCHER highlighted the proposals in HB 72 [slide
20], saying the bill would: eliminate progressivity and credits
based on capital expenditures; reform remaining credits to be
carried forward to when there is production and a company is
paying taxes; and establish a gross revenue exclusion for newer
units and for new participating areas in existing units. The
benefit of the gross revenue exclusion is that it can be used to
focus on other more challenged developments. Lastly, the bill
would not make any changes to Cook Inlet and Middle Earth; these
two areas would be held harmless because the bill specifically
applies to north of 68 degrees North latitude.
1:53:50 PM
COMMISSIONER BUTCHER compared current law with HB 72 [slide 21].
He said the current base tax rate of 25 percent would remain at
25 percent under the proposed bill. Progressivity in current
law would be removed by HB 72. Some of the current tax credits,
cash reimbursements and reduced tax revenue to the state, would
be altered and some would be eliminated. The proposed bill
would provide a gross revenue exclusion (GRE) for new oil. For
fiscal year 2014, eliminating progressivity would reduce state
revenue by $1.5 billion, but changing the tax credits would
reduce the amount the state pays out by $1 billion; therefore HB
72 has a much more modest fiscal note than did [the governor's
previous proposal in] House Bill 110.
1:55:06 PM
REPRESENTATIVE SEATON, referring to slide 10, said that a year
ago DOR was asked for examples and the only example the
department could come up with was the turnaround of the Forties
Field. The lesson was that the Forties Field was owned by a
single legacy producer unwilling to re-invest in the field, so
the field was sold to a more nimble independent that invested
and turned around the field. The three legacy owners on the
North Slope - Prudhoe Bay being the biggest field - have joint
operating agreements under which each owner must agree to an
investment, otherwise that investment does not go forward. Now,
he continued, the proposal is to change the tax structure for
the legacy owners when the example provided to the committee is
for a field that the legacy owner was unwilling to invest in to
turn around. Members need some information and some security
that there will be a reversal in the attitude of the legacy
owners about investing in and turning around their fields. He
asked why the Forties Field is a good example for the situation
on the North Slope, given that the legacy owners would not be
selling the fields to someone with a different attitude.
1:58:02 PM
COMMISSIONER SULLIVAN replied the point of today's overview is
to give the committee a sense, at a high level, of what is going
on in different fields and basins and what is driving the
different production decline turnarounds, whether it is in
fields basin-wide, which is what slide 15 is focused on, or
whether it is the North Sea incentives, or more specific fields
themselves. The idea was not to get into details of exactly why
BP [sold] or Apache purchased a field, or what the implications
are for a veto power of the operating agreement at Prudhoe Bay,
but to give the committee a sense of what is happening basin-
wide and can happen to specific fields. Sometimes in the debate
it is heard that this is Alaska's future and nothing can be done
about it. [The administration] does not believe that, and more
importantly, there are examples all over the world showing that
that does not have to be Alaska's future. The point of the
various slides was to demonstrate at a high level that this
turnaround, that is absolutely fundamentally critical to the
future of Alaska, is doable. This tax reform proposal is also
to help with getting more competition on the North Slope - more
investors, huge investors, medium-sized investors, small
investors. More investors on the North Slope would provide
Alaska the opportunities that can either turn around fields or
discover new fields. It is not just focused on the legacy
producers. Growing the pie is what this tax reform proposal is
ultimately about. While the question is a good one, [slide 10]
was meant to give an overview sense, not the detail, that a
turnaround in production decline is doable in Alaska.
2:01:57 PM
REPRESENTATIVE SEATON clarified he was not saying it was not
doable. If, as in the example, it took a change in ownership, a
change in the structure of the investors, instead of a change in
the tax rates to make the change, should the state take a look
at the structural change that took place to do that? He said he
wants to ensure that the actual structural impediments to
turning around the fields are addressed instead of just assuming
that a change of one thing will address those structural
changes.
COMMISSIONER SULLIVAN allowed the aforementioned is a valid
point. He said [the administration] is trying to address the
throughput decline across a number of areas, some of which have
to do with tax reform and some of which do not, but tax reform
is a fundamental element.
2:03:39 PM
CO-CHAIR SADDLER, regarding slide 16, requested an expansion on
the $4.07 per barrel that would be earned under ACES in Alaska
at a price of $100. While he understood that the net present
value of 12 percent changes the calculation, he said people have
heard that there is lots more profit per barrel than the $4.07
that is shown on the slide.
MICHAEL PAWLOWSKI, Oil & Gas Development Project Manager, Office
of the Commissioner, Department of Revenue (DOR), first noted he
is the advisor for petroleum fiscal systems to the Department of
Revenue. He then replied that looking at the net present value
(NPV) is but one of several financial metrics. The net present
value per barrel takes the lifecycle earnings over the entire
future development of this field and pulls all of that expense
in cash back to the first years; so, it is just one way of
looking at something. The earnings that people talk about
typically are thought of as the cash margins that are earned
each year on that development, which is actually a different
metric than what this slide is showing. In the Econ One
presentation included in the committee packet, it can be seen
that each region is compared not just on net present value or
internal rate of return, but rather on a range of metrics where
each tells a different story about what the actual economics
look like. Slide 16 is showing that after the costs and after
the cash flows have been brought all the way back to today this
is the way they look like for this specific field. In the past,
the use of analytics, one analytic versus another, has been
limited, so going forward there will be focus on the variety
because each one will show Alaska in a different context.
2:06:06 PM
REPRESENTATIVE TUCK, returning to the BP/Apache example on slide
10, recalled that at a joint committee meeting last year PFC
Energy stated BP does not specialize in getting the last drop of
oil and oftentimes sells to companies that are experts in this
regard. He further recounted that PFC said Alaska is clearly in
a harvest mode and that ACES was working well for that harvest
mode situation. He concurred that more competition, not less,
is needed on the North Slope, but said the hard part is trying
to get the legacy people to move and how to get them to move.
He said he, too, is concerned about the amount of money going
out and that it is unknown what the state is getting for it.
However, the governor's bill of the past [House Bill 110] did
not guarantee anything either and he does not know about HB 72.
He understood the legacy fields have an advantage in that an
unsuccessful well has better tax advantages than those for the
new companies. Profits on the North Slope are very good right
now, he opined, but the companies [are not increasing
production] because it is not in their best interest to do that
right now based on what they have going on in the rest of the
world. A nice thing about Alaska's current tax credit system is
the state is guaranteeing that those investments are happening
in Alaska and that is what is happening with those new
companies. It would be nice to know what information the state
is receiving for the money it is spending so that legislators
can make better decisions going forward. He offered his hope
that if this information is not in the sectional analysis or the
bill that the administration will allow the legislature to put
those provisions in the bill to ensure that the right decisions
are made going forward.
COMMISSIONER SULLIVAN responded that everyone agrees on the
importance of legacy producers as well as getting new investors
up to Alaska to explore and to maybe partner with some of the
legacy producers. He said no one sees the progressivity aspect
of ACES as a positive element in their decision making to come
to Alaska. It is an issue raised by every company he has talked
to and he is very convinced that it affects new entrants as well
as the legacy producers.
2:09:17 PM
REPRESENTATIVE TUCK, referring to slide 16, inquired whether the
brownfield is located in the North Sea.
COMMISSIONER BUTCHER confirmed that it is.
CO-CHAIR FEIGE added that the difference between the terms
brownfield and greenfield is that greenfield is open land and
brownfield already has some development on it.
2:09:47 PM
REPRESENTATIVE TARR drew attention to slide 18 and recalled that
Commissioner Sullivan stated the credits are not helping in
terms of investment. Presuming that fiscal years 2013 and 2014
are based on the Fall 2012 Revenue Sources Forecast, she asked
why there is a jump upward in those two fiscal years for tax
credits if the companies were not investing [in Alaska].
COMMISSIONER SULLIVAN answered there might be some correlation
between the investment credits, the exploration credits, and new
companies coming up to explore. By nature of the way those are
designed right now, there is no requirement, no nexus, between
the spending [and production]. The governor's bill would
tighten that nexus significantly with regard to not just
spending, but credits that relate to [indisc.], something with
which most legislators would agree.
COMMISSIONER BUTCHER interjected that tax credits incentivize
spending, but it is not known that they incentivize production.
For companies currently producing there is a spending jump of
over $100 million from fiscal year 2013 to 2014, but the
question is whether the state is getting more production for
those dollars.
2:12:46 PM
MR. PAWLOWSKI then provided a PowerPoint overview of HB 72
entitled, "Overview of HB 72 Oil & Gas Production Tax," noting
the purpose of his presentation is to familiarize members with
the bill's different sections and the specific provisions that
they relate to. He reiterated the governor's four principles
[slide 2]: tax reform must be fair to Alaskans, must encourage
new production, must be simple so that it restores balance to
the system, and must be durable for the long-term. He said
these principles are all geared toward the ultimate goal of
making Alaska competitive while adhering to these principles.
2:14:09 PM
MR. PAWLOWSKI reviewed highlights of the proposal [slide 3],
saying that HB 72 balances the elimination of progressivity and
credits based on qualified capital expenditures. First, not all
of the credits are being reformed or gone through by the bill;
for example, the exploration stage credits under AS 43.55.025
are not adjusted by HB 72. Credits being adjusted are the
qualified capital expenditure credit, the net operating loss
carry forward credit, and the small producer [credit]. The key
is to look at progressivity as a revenue generator, with its own
impacts and issues, balanced against credits that are based on
purely capital expenditures. Second, the credits being retained
would be reformed to be carried forward to when there is
production, the principle of being fair to Alaskans in that when
the state gives an incentive there is corresponding production
in revenue to pay for the incentive being given. Third, is
establishing a gross revenue exclusion for the newer units and
the new participating areas within existing units, encouraging
new production by offering an incentive that is geared directly
towards that new production. Both the second and third
proposals are geared towards new production - the incentives,
credits, are received by a company when it produces oil. The
gross revenue exclusion is given when the new oil is produced.
2:16:08 PM
REPRESENTATIVE P. WILSON understood that net would still be used
in the rest of Alaska's tax system, except for the proposed
exclusion that would use gross.
MR. PAWLOWSKI replied correct. The bill would maintain the base
25 percent net tax, which is the core of the current tax system.
The progressivity and the qualified capital expenditure credits
would be removed. Currently, the net operating loss credit,
which is an additional 25 percent, can be cashed out from the
state by someone who does not have a tax liability. In HB 72,
that credit would have to be carried forward to be used when the
producer actually has a tax liability.
2:17:17 PM
REPRESENTATIVE SEATON surmised the gross revenue exclusion is
just another mechanism and understood it would lower the revenue
by one-fifth, or 20 percent. He inquired whether there is any
difference between that and just saying the tax rate for new oil
is going to be 20 percent instead of 25 percent.
MR. PAWLOWSKI replied the aforementioned is right conceptually,
but the difference is in the execution. Previous proposals by
the administration had functionally different tax rates in
recognition that some of this new development for infrastructure
has much more challenged economics that a lower tax rate is
necessary for. However, different tax rates for different
fields causes the Department of Revenue a serious problem with
apportioning costs by field back through the net system. A
gross revenue exclusion allows the ability to offer a lower tax
rate on that new production because it only taxes 80 percent of
the value and it avoids all of the complicated accounting and
apportioning costs that come up when there are separate tax
rates. Remembering that one of the core principles is trying to
be simple, it was decided that the gross revenue exclusion was a
better mechanism to get to the ultimate goal of providing
incentive for new oil without complex accounting.
2:18:49 PM
REPRESENTATIVE SEATON concluded that although it is a different
mechanism the effect is the same as lowering the tax rate to 20
percent on new oil.
MR. PAWLOWSKI responded he would have to look at the specific
math that 20 percent is the exact number because it would move
around based on costs and the way the gross revenue works.
However, it is effectively correct that it is just offering a
lower tax rate in a simple way.
2:19:16 PM
MR. PAWLOWSKI returned to his presentation, stating the fourth
highlight of HB 72 is that the majority of the bill relates to
the no changes to the Cook Inlet and Middle Earth provisions.
2:19:30 PM
MR. PAWLOWSKI next provided a sectional analysis of the bill
[slide 4], beginning with the elimination of progressivity under
[Sections 1, 2, and 26]. Section 26, page 23, line 12, would
repeal AS 43.55.011(g), which is the identification of the
progressive part of the tax. Repeal of AS 43.55.011(g) causes
multiple other things within the statute to then happen. The
first of those impacts is in Section 1, beginning on page 1,
line 12. Under current law, a portion of progressivity is
directed to the community revenue sharing fund. The idea was to
have three years of funding for community revenue sharing in an
account that could forward fund a balance for revenue fund
sharing in the future. Eliminating progressivity eliminates
that fund source for community revenue sharing. The first of
two important changes is on page 2, line [2], which eliminates
the language "an amount equal to 20 percent of the". The
concern about this language is that it limits the amount of
money available to go into the revenue sharing fund. As can be
seen from page 2, lines 5-6, the revenue sharing fund is
intended to be $60 million per year or, when needed, up to $180
million. Twenty percent of progressivity when prices are low
and when there is no progressivity is zero. When the governor
looked at this issue, it was to meet the intent of the actual
financial benchmarks for community revenue sharing that are set
at $60 million and $180 million. The 20 percent language was
seen as a limitation and could potentially lead to underfunding
the community revenue sharing fund, so that problem is dealt
with by eliminating the language "an amount equal to 20 percent
of the". Page 2, line 3, moves the revenue source for funding
of the community revenue sharing fund to AS 43.20.030(c),
receipts from the Alaska Net Income Tax Act. This tax is paid
by other corporations as well as oil and gas companies, thus
providing a broader and more stable source of funding. In
fiscal year 2013 the total amount of revenue from this tax was a
bit over $660 million and is projected to be a bit over $700
million in fiscal year 2014.
2:23:47 PM
CO-CHAIR FEIGE surmised the better Alaska's economy does overall
the more money will be available for revenue sharing.
MR. PAWLOWSKI answered correct.
2:23:58 PM
REPRESENTATIVE P. WILSON inquired whether all money from [the
net income tax] currently goes into the general fund or whether
some goes into the permanent fund.
MR. PAWLOWSKI replied the money that goes into the permanent
fund is a function of the royalties, bonuses, and leases paid to
the state. [The net income tax] is just tax revenue so it is
general fund revenue, just as the progressivity revenue is
general fund revenue. With elimination of progressivity the
source of funding to community revenue sharing goes away, so
another source had to be found.
2:24:41 PM
REPRESENTATIVE SEATON recalled that when this was developed the
state was in deficit spending and had eliminated the municipal
and community revenue sharing program entirely. This was put in
so that when there were surpluses through progressivity there
would be funding for the fund because during times of deficit
spending the legislature has historically not taken money out of
savings to give away through municipal and community revenue
sharing. He asked whether, with this change, the governor is
now saying that he is committed to funding municipalities and
communities at $60 million a year even if the state is in
deficit spending and taking money out of savings, which is
different philosophy than the legislature had when it put in the
mechanism of funding municipal revenue sharing with surpluses.
MR. PAWLOWSKI responded he will take that question to the Office
of Management & Budget for an answer because he is not equipped
to speak to the actual spending plans. However, the point was
to ensure that the revenues for community revenue sharing were
replaced with a different mechanism.
2:26:32 PM
REPRESENTATIVE SEATON said an answer from the Office of
Management & Budget would be appreciated.
MR. PAWLOWSKI added that corporate income taxes are necessarily
subject to income. As incomes rise the more money available to
go into the community revenue sharing fund. Corporate income
tax has risen as oil prices have gone up, so there is a
sensitivity. If there was no income for the companies there
would be no corporate income tax receipts and therefore no money
for the revenue sharing. However, in this instance it is better
diversified because there are other businesses that pay into the
net income tax.
2:27:36 PM
REPRESENTATIVE TARR recalled the thinking behind the funding of
municipal revenue sharing through oil development was that it is
a common property resource, so that wealth would be shared with
and distributed to local communities. Therefore, the proposal
seems like a fundamental shift in the way those funds are
acquired. While those funds would be going into the general
fund, would there be a reason to be concerned about that in
terms of the way that change would change the situation, she
asked.
MR. PAWLOWSKI allowed that is a fair point, but noted that
mining and fisheries businesses pay a corporate income tax. So,
the broad breadth of resources is now related through the net
income tax system towards the community revenue sharing.
Eliminating progressivity takes away the money that was
designated directly to community revenue sharing. The
importance of the principle is the commitment to community
revenue sharing, the degree to which is subject to ultimate
budgets and appropriations, but the bill makes a commitment to
putting money into that fund.
2:28:51 PM
REPRESENTATIVE TARR inquired whether there could be a [future]
situation where, for example, tough times for oil revenue would
create increased pressure on the other industries to help put
[money] into that fund.
MR. PAWLOWSKI answered he would have to think about that with
the department and talk about projections to corporate income
tax receipts. Regarding the number of $60 million, he said he
is not sure the circumstance of which corporate income taxes on
a diversified basis would drop below that.
2:29:35 PM
JOE BALASH, Deputy Commissioner, Office of the Commissioner,
Department of Natural Resources (DNR) followed up on the points
made relative to progressivity and revenue sharing. He pointed
out that in forecasts for the very near term, expected revenues
are projected to be below expected expenses. The state will be
in a deficit in the near time with plenty of progressivity
coming in the door. Thus, progressivity by itself is not a
demonstration of the state having itself in good fiscal health.
CO-CHAIR FEIGE interjected it is still up to the legislature to
appropriate the money as appropriate.
2:30:16 PM
MR. PAWLOWSKI, continuing his presentation, said [Section 1]
moves away from the core of the bill, which is reform of the oil
and gas fiscal system. However, given the importance of the
community revenue sharing fund, he thought it important to spend
a few minutes talking about the mechanism. Returning to
discussion of the way HB 72 relates to oil and gas taxes, Mr.
Pawlowski stated that Section 2, on page 2, lines 8-18, is a
further reform necessary to the statute because of the repeal of
AS 43.55.011(g). The annual production tax before credits, as
it currently exists under AS 43.55.011(e), is the combination of
the 25 percent [base rate] plus the progressivity, which is "the
sum, over all months of the calendar year, of the tax amounts
determined under [AS 43.55.011(g)]". In that the progressivity
is eliminated, the sum language needs to go away. The 25
percent base rate is maintained.
2:31:36 PM
MR. PAWLOWSKI next addressed the conforming sections related to
the elimination of progressivity [Sections 5, 6, 22, and 23].
Drawing attention to Section 5, beginning on page 5, line 27, he
explained that there are monthly installment payments for Cook
Inlet and Middle Earth that exist for one year until
progressivity is repealed. Section 5 amends Section 4 of the
Act which had to be amended to preserve the current tax ceilings
and treatments there, but Section 5 is when the monthly
progressivity installment payments go away and the language
needs to be changed to reflect that. Throughout Section 5 it
can be seen that Cook Inlet and Middle Earth are broken out; for
example, page 6, line 11, takes out "the sum of" because it is
no longer the sum of 25 percent plus a progressivity, it is just
the 25 percent. The important difference there is on page 7,
lines 3-5, which is an adjustment for the gross revenue
exclusion that occurs later in the bill. The section being
dealt with is the calculation of the monthly installment
payments which are currently the sum of 25 percent plus the
taxpayer's progressivity as adjusted by the tax ceilings. In
that the progressivity is going away, the monthly installment
payment section must be adjusted.
2:33:59 PM
CO-CHAIR FEIGE understood that Section 5 is basically amending a
previous change in the law that was put in Section 4.
MR. PAWLOWSKI replied yes.
CO-CHAIR FEIGE requested clarification for why it is being done
this way.
MR. PAWLOWSKI explained Section 4 makes amendments to reflect
the different tax ceilings and preferential tax treatment put in
place over the years for: the Cook Inlet basin, the area south
of 68 degrees North latitude [known as] Middle Earth, and gas
produced and used in-state. In adjusting progressivity,
sections of law are referenced that are all interrelated. For
example, Section 4, page 3, line 4, adds the language "not
subject to AS 43.55.011(o) or (p)"; AS 43.55.011(o)-(p) includes
the different treatments such as tax ceiling and special tax
rate for gas produced and used in-state. If passed, the
effective date of the bill and repeal of progressivity is
January 1, 2014. Since it is currently the calendar year 2013,
there will be a one-year period in which these monthly
installment payments will still be made. So this is a cleanup
of the [tax ceiling and preferential tax treatment] language for
that one-year time period and then an amendment to the cleanup
in the immediate next year.
2:36:40 PM
MR. PAWLOWSKI returned to his presentation, explaining that
Section 22, page 21, line 10, deals with the different ceilings.
What remains after progressivity goes away are separate buckets
of different types of oil and gas that under current law are
treated and taxed differently. While progressivity does not
apply to them now, cleaning up the statute makes it easier for
the future. So Section 22 attempts to organize the statute in a
way that is clearer to people trying to do business in the state
and to companies that are investing. He reminded members that
the price of oil minus transportation cost is the gross value at
the point of production, minus the lease expenditures is the
production tax value, which can be thought of as the cash flow
to which taxes are applied. Section 22 addresses the different
ways that taxes are applied to the different types of oil and
gas that have been given preferential treatment in different
pieces of law throughout time.
2:38:35 PM
MR. PAWLOWSKI read paragraph (1) of Section 22, page 21, lines
21-23, which states, "oil and gas produced from leases or
properties in the state that include land north of 68 degrees
North latitude, other than gas produced before 2022 and used in
the state;". He said that is by and large North Slope oil and
gas and the main target of HB 72 is the North Slope. He then
drew attention to paragraph (2) of Section 22, page 21, lines
24-30, which states, "oil and gas produced from leases or
properties in the state outside of the Cook Inlet sedimentary
basin, no part of which is north of 68 degrees North latitude
..." and said this is the Middle Earth section that is not the
North Slope and not Cook Inlet. He next read subparagraph (A)
which states, "gas produced before 2022 and used in the state;
or" and subparagraph (B) which states, "oil and gas subject to
AS 43.55.011(p);" and explained that AS 43.55.011(p) is the
language included in legislation last year that provided a 4
percent gross tax ceiling for oil and gas produced from the
Middle Earth area.
2:39:53 PM
MR. PAWLOWSKI continued reading the remaining paragraphs of
Section 22, which state:
(3) oil produced before 2022 from each lease or
property in the Cook Inlet sedimentary basin;
(4) gas produced before 2022 from each lease or
property in the Cook Inlet sedimentary basin;
(5) gas produced before 2022 from each lease or
property in the state outside the Cook Inlet
sedimentary basin and used in the state, other than
gas subject to AS 43.55.011(p);
(6) oil and gas subject to AS 43.55.011(0)
produced from leases or properties in the state;
(7) oil and gas produced from leases or
properties in the state no part of which is north of
68 degrees North latitude, other than oil or gas
described in (2), (3), (4), (5), or (6) of this
subsection.
MR. PAWLOWSKI said paragraph (7) is looking to the future
because paragraphs (1)-(6) all have expiration dates of 2022.
After all of those exclusions expire in 2022, a section in law
had to be created where they could all fall back into. After
those 2022 dates go away, all of the oil and gas produced in the
state will default into the general 25 percent flat taxes.
2:41:14 PM
CO-CHAIR SADDLER understood the 4 percent gross tax ceiling for
oil and gas produced from the Middle Earth area was a provision
of Senate Bill 23 enacted into law in [September ] 2012.
MR. PAWLOWSKI replied correct. Responding further to Co-Chair
Saddler, he expounded on the process that would happen after
2022. He drew attention to page 21, line 29, which states, "gas
produced before 2022 ...", and said that is the way the law was
drafted and adopted. Page 21, line 31, is "oil produced before
2022 ..." and that language is also in paragraphs (4) and (5).
He read from AS 43.55.011(p), which states:
(p) For the seven years immediately following the
commencement of commercial production of oil or gas
produced from leases or properties in the state that
are outside the Cook Inlet sedimentary basin and that
do not include land located north of 68 degrees North
latitude, where that commercial production began after
December 31, 2012, and before January 1, 2022, the
levy of tax under (e) of this section for oil and gas
may not exceed four percent of the gross value at the
point of production.
That is for seven years before 2022, he continued. In statute
it must be looked forward to the fact that 2022 might happen and
the legislature or the public might not actually change the law
to address Cook Inlet or Middle Earth before then. So, a
statutory construction needed to be made to allow clearly what
actually happens once those expire. In the current law these
statutes kind of spread throughout the statute. Section 22 is
an orderly clarification of the different oil or gas tax
treatments that have been passed by the legislature set out in a
very deliberative fashion.
2:43:25 PM
MR. PAWLOWSKI explained that Section 23 is an amendment to
conform to the changes that were made in Section 22 so that the
production tax value is calculated under [AS 43.55.160] (a)(3),
(4), (5), or (6) rather than (a)(1)(C), (D), (E), or (F).
2:44:06 PM
MR. PAWLOWSKI then reviewed Section 8, a provision in HB 72
related to North Slope qualified capital expenditure (QCE)
credits. Drawing attention to page 10, lines 16-18, he said
that the QCE credit, which is the 20 percent of capital
expenditures, will be allowed for 2013, but an expenditure made
on the North Slope after January 1, 2014, will no longer qualify
for a QCE credit.
2:45:08 PM
REPRESENTATIVE SEATON understood the QCE credits are allowed at
the time the expenditures are made rather than when the work is
done. He said information has been received that some operators
have been paying service companies for well work overwork but
not having the work done. He offered his belief that that is
legal under the law because it is when the expenditure is made
and allowed it would be reasonable if the company was
anticipating that the work would be done in the next year. He
asked if DOR is tracking whether the work is being frontloaded
and not performed at the time and whether DOR has any audits on
that. He further asked whether this [proposed] deadline for the
end of 2013 will result in companies paying for work that will
be done in the future and legitimately claim the capital
expenditures this year.
MR. PAWLOWSKI responded "in that expenditures are made legally
and qualify in 2013, the bill does not change the treatment of
those credits for expenditures in 2013." As to the department's
internal controls for the credit, he said the deputy
commissioner and auditors are on line and may be able to provide
the detail about what and how the department tracks the concern
about frontloading expenditures. He said it is up to the
committee as to the detail it would like.
REPRESENTATIVE SEATON said it would be fine for DOR to get back
to the committee with the details.
2:47:46 PM
CO-CHAIR FEIGE suggested the companies themselves be asked this
question. He concluded from Representative Seaton's description
that the companies are making the expenditure early to get the
tax benefit, but said he did not think they would put too much
money out there without getting the work done because that would
not make much business sense.
MR. BALASH interjected that some vendors have had challenges
getting payment after the work was done, so there may be some
commercial value to having payment up front in certain cases.
REPRESENTATIVE SEATON recounted that when these credits were
being talked about it was discussed that investment could be
stimulated during high prices by allowing payment for something
like a total pipeline replacement and getting a lot more state
participation in that pipeline at those high tax rates. So, it
is not necessarily a nefarious thing, but this proposed change
could stimulate something that has been marginal up to this
point.
2:49:37 PM
MR. PAWLOWSKI returned to his presentation and discussed the
conforming sections for the North Slope QCE credit provision.
He explained that under current law, a capital expenditure
credit, which is based on 20 percent of that expenditure, is
divided into two certificates for the North Slope - half the
credit may be used in the year it is earned and the other half
must be carried forward. Under conforming Section 7, page 9,
lines 21-22, the requirement that not more than half of the tax
credit may be applied for in a single year is deleted. Credits
earned for expenditures in 2013, therefore, would be used in one
certificate instead of two. The impact of using the credits in
one year instead of over two is reflected in the fiscal note for
fiscal year 2014. Because [Section 8] shuts down the QCE
program for the North Slope after calendar year 2013, this
provision is intended to take care of the liability in one year
and finish the program.
2:51:24 PM
MR. PAWLOWSKI pointed out that Section 7 does not include AS
43.55.023(m), that portion of statute for QCE credits earned
south of 68 degrees [North latitude] and which are not required
to be divided into two years. Therefore, since the credit would
be taken in one year, conforming Section 11, page 11, line 8,
replaces the word "certificates" with "certificate". Also, page
11, line 20, replaces the word "two" with "a" to reflect the
current practice [under AS 43.55.023(m)] of one certificate for
south of the North Slope. Given there would no longer be any
qualified capital expenditure credits for the North Slope, this
change goes back to the simple principle - making it clear in
every section of the law that it is one certificate, not two.
2:53:16 PM
CO-CHAIR SADDLER understood that because the qualified capital
expenditure credit would be phased out, Section 7 bumps up the
taking of the credits to one year; other credits will remain,
but instead of two years it will be one year.
MR. PAWLOWSKI replied that the remaining credits are currently
one-year credits. The only credit that would be eliminated is
the current two-year credit. So, moving forward, why leave
other sections of statute conflicting?
2:54:04 PM
MR. PAWLOWSKI, continuing his discussion of conforming sections
for the proposed elimination of North Slope QCE credits, drew
attention to Section 12, beginning on page 11, line 29. He said
the conforming language in this section is just being clear that
"except for a tax credit based on lease expenditures incurred
after December 31, 2013 ... north of 68 degrees [North]
latitude", a person may take a tax credit.
2:54:32 PM
MR. PAWLOWSKI moved to the other major proposals included within
HB 72 [slide 5], noting that another primary credit related to
qualified capital expenditures is the net operating loss carry
forward credit under AS 43.55.023(b), which is 25 percent of a
company's loss. The bill would maintain that credit, but it
would be carried forward to when there is production. Sections
9 and 15 are the changes to the way that credit is treated.
Since this net operating loss credit is being eliminated only
for the North Slope and not for other regions, Section 9, lines
21-24, makes this credit subject to the new subsections (p)-(u)
that are added under Section 15 of the bill. Section 15,
beginning on page 13, line 15, adds new subsections (p)-(u) [to
AS 43.55.023] to govern how that 25 percent net operating loss
carry forward credit for North Slope expenditures is treated.
Subsection (p), beginning on page 13, line 16, states that the
tax credit for lease expenditures located north of 68 degrees
North latitude, i.e. the North Slope, may not be applied until
two calendar years after the expenditure is made, which is
basically under current law when a company would be getting the
credit. So, a company can make the expenditure and then use the
credit the next year, but does not have to bring it to the state
for a credit certificate until the second year. This is just
recognizing the natural flow through DOR of the way these
credits are earned and processed.
2:57:03 PM
MR. PAWLOWSKI said the important limitation is that each of
these credits is only good for a time period of 10 years, after
which each one of these credit certificates expires (page 13,
line 23). The importance of the time limit for when this credit
can be used to offset production taxes can be seen in subsection
(r), page 14, line 2. Under current law, a company receives a
cash payment from the state for the credit. Recognizing that
there is a time value to money, the value of the credit being
carried forward increases at a rate of 15 percent per year,
starting in the second year after the money is expended. The
goal was to provide an increase that is comparable to the other
opportunity the company may have to invest that capital
somewhere else and earn a rate of return. So, the way the net
operating loss carry forward credit works is the expenditure is
made, 25 percent of the value of that expenditure is turned into
a credit and carried forward. Under the governor's plan, rather
than cash being paid out, the value of that 25 percent increases
at 15 percent a year starting in the second year after the
credit has been issued and ends at year 10. If the credit has
not been earned by year 10 it is not useable at all.
2:58:43 PM
CO-CHAIR SADDLER understood that credits used sooner are more
valuable than credits used later. He asked whether any
consideration was given to losing a percent per year over the 10
years, or was the consideration that just having a two-year wait
period was enough value to encourage things upfront.
MR. PAWLOWSKI replied that when the administration's consultants
come forward it will be seen just how important the carry
forward credit rate is to improving the net present value of the
project in a way that is fair to the producers but also does not
put a burden on the treasury. The credit is being deferred so
the state is not paying it out until there is production to
charge the credit against.
2:59:46 PM
MR. PAWLOWSKI, returning to his presentation, explained that to
protect the state, new subsection (q), page 13, beginning on
line 25, would implement the "first earned, first used" rule.
Since credits are being earned every year and each is increasing
at a rate, in time the first credit earned is the one that must
be used first and then the second credit earned is the second
credit used.
3:01:01 PM
REPRESENTATIVE TUCK understood that the net operating loss carry
forward credit for the North Slope would grow 15 percent each
year. He asked whether after 10 years the credit would stop
growing but still be a valid credit or would the credit become
null and void altogether.
MR. PAWLOWSKI responded that the credit is null and void.
3:01:25 PM
REPRESENTATIVE SEATON said it seems to him that the current
system for net operating loss credits has been greatly
successful for Alaska, given all the new players on the North
Slope and almost half of the credits coming back. Previous
testimony by the people out drilling the holes and building
pipelines has been that it is important to get the credit back
as quick as possible for reinvestment. Changing the system so
that the credits cannot be received for two years and so they
are lost if it takes a company longer than 10 years to get the
oil into the pipeline seems to eliminate the value that has
produced the investment the state has been looking for. He
requested that when there is time he would like to be apprised
of the basic structural philosophy as to how this is going to
stimulate the investment that the current credit has achieved.
3:03:24 PM
MR. PAWLOWSKI allowed that is an important question and said it
will be seen in Econ One's presentation that the credits offered
up front were intended to stimulate that new activity in that
new development. There is a difference between the exploration
stage and the development stage and that is why HB 72 does not
change the exploration credits, but rather the credits that work
in the development stage. Because of progressivity and because
of the lifecycle economics, the ability to get to development is
not working with the credits, which will be seen in the Econ One
models. The bill, in context, is attempting to dramatically
improve the overall economics which will drive the development
decision.
3:04:16 PM
CO-CHAIR FEIGE held over HB 72.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB0072A.PDF |
HRES 2/11/2013 1:00:00 PM |
HB 72 |
| 0647-DNR-DOG-1-14-13.pdf |
HRES 2/11/2013 1:00:00 PM |
|
| 0647-DOR-TAX-01-15-13.pdf |
HRES 2/11/2013 1:00:00 PM |
|
| 01.15.13 Chenault Oil Tax Transmittal Letter.pdf |
HRES 2/11/2013 1:00:00 PM |
|
| Butcher to Feige & Saddler 1-17-2013.pdf |
HRES 2/11/2013 1:00:00 PM |
|
| Econ One Presentation TAPS Throughput 1-24-2013.pdf |
HRES 2/11/2013 1:00:00 PM |
|
| OTR Sectional Analysis HB 72 2-11-2013.pdf |
HRES 2/11/2013 1:00:00 PM |
HB 72 |
| Sectional LL0647-DOR-TAX-01-14-13 House.pdf |
HRES 2/11/2013 1:00:00 PM |
|
| Sullivan_Butcher_House Resources HB 72 Overview_2-11-13 FINAL.pdf |
HRES 2/11/2013 1:00:00 PM |
HB 72 |
| HRES HB72 Corrected Slide #18 Comm. Presentation 2.11.13.pdf |
HRES 2/11/2013 1:00:00 PM |
HB 72 |