Legislature(2013 - 2014)BARNES 124
03/28/2013 06:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB21 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 21 | TELECONFERENCED | |
| + | TELECONFERENCED |
SB 21-OIL AND GAS PRODUCTION TAX
6:07:29 PM
CO-CHAIR FEIGE announced that the only order of business is CS
FOR SENATE BILL NO. 21(FIN) am(efd fld), "An Act relating to the
interest rate applicable to certain amounts due for fees, taxes,
and payments made and property delivered to the Department of
Revenue; providing a tax credit against the corporation income
tax for qualified oil and gas service industry expenditures;
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; establishing the Oil and
Gas Competitiveness Review Board; and making conforming
amendments."
6:07:55 PM
DAN SULLIVAN, Commissioner, Department of Natural Resources
(DNR), began the administration's PowerPoint presentation
entitled, "Oil Tax Reform - Arresting TAPS Throughput Decline".
He said an argument being heard in debates on the tax reform
proposal is that Alaska does not have much of a problem,
business is booming, the tax system is working, and employment
and capital expenditures are up [slide 3]. He and Department of
Revenue Commissioner Bryan Butcher have been relentlessly trying
to get new investment and new production in Alaska and he would
like to believe that "business is booming and all is well" in
the state. Unfortunately, he and Commissioner Butcher do not
believe that is the case, particularly when focusing on the
metrics of production and what is happening throughout the
United States and the world. When those comparisons are made,
it is very clear Alaska has a system that needs to be fixed.
6:10:40 PM
COMMISSIONER SULLIVAN declared the unequivocal good news is that
Alaska still has a massive resource base that is well recognized
around the world [slide 4]. The state is also one of the most
relatively unexplored and is on the cusp, he believes, of big
potential for unconventional resources. Alaska has a resource
base that can keep the state's economy, government revenue, and
citizens with good jobs healthy and strong for decades to come.
COMMISSIONER SULLIVAN recounted that a question asked during
work on the governor's bill was whether other declining basins
have been turned around. The answer is pretty much that
everybody, at these high sustained prices in the U.S. and other
countries, is turning around their declines, with the very
depressing exception of the state of Alaska. Drawing attention
to slide 5, he pointed out that as prices start to spike and
stay at sustained high levels, basins like North Dakota, Texas,
and Alberta have flattened out their declines and then turned
around to increased production. The one exception is Alaska and
[the administration] believes the reason is because Alaska's tax
system does not provide incentive for companies to invest at the
higher prices in terms of profits, but it does everywhere else.
6:13:21 PM
BRYAN BUTCHER, Commissioner, Department of Revenue (DOR),
addressed the argument that it is all about shale and not really
Alaska's tax system. He allowed that, currently, shale is
certainly contributing to a tremendous increase in North Dakota
and Texas. However, he pointed out, Texas flattened out and
began to turn around with just conventional crude oil. Slide 5
makes sense in that it shows prices rising, production rising,
because things became more economic at oil prices of $80-$100
than they were at prices of $40-$50. What does not make sense
is that over the last few years the Alaska North Slope (ANS)
price has been $5-$20 more per barrel than West Texas
Intermediate (WTI) prices. However, one would think the last of
the jurisdictions to continue to see a decline would be Alaska
since the other jurisdictions are tied to the WTI.
6:14:22 PM
COMMISSIONER SULLIVAN stressed slide 5 is not good news. People
claiming that things are going well and business is booming are
not focused on this slide, which [the administration] thinks is
the most important metric to focus on - production. He said
slides 6-10 provide a snapshot of what is happening in other
states by year at different prices. They depict a positive
story in that they show older basins can be turned around, but
they are negative when looking at Alaska. In the year 2007-
2008, [five states were in decline], but by year 2011-2012 and
prices having gone up [Alaska is the only state still in
decline]. Every basin in the country has turned around its
production decline, except Alaska.
COMMISSIONER BUTCHER interjected that what makes slide 10 odder
is that Alaska has more resources than any of the other states.
Between 2011 and 2012, the one state out of all of the oil
producing states that did not see an increase in production was
the state with the most resources.
6:16:11 PM
COMMISSIONER SULLIVAN noted slide 11 is from Econ One Research,
Inc., and it tells the same story regarding production declines.
He explained that 2003 is the base year in the slide, equalizing
the different levels of production. [From 2003 to 2012], U.S.
production dips a little bit, flattens out, and then increases
significantly, and a similar production pattern occurs for
countries in the Organisation for Economic Co-operation and
Development (OECD). Alaska, however, is producing at nearly
half of what it was producing just 10 years ago. Alaska has the
resources to turn it around and [the administration] believes
that the people who think business is booming in the state are
very misguided.
COMMISSIONER SULLIVAN said claims are heard that investment [in
Alaska] is at an all-time high [slide 12]. But of importance is
investment relative to what? The world, and the U.S. in
particular, are going through probably the biggest investment
boom ever seen. There is capital that wants to be deployed in
hydrocarbon-producing basins. The International Energy Agency
(IEA) has predicted that by 2020 the U.S. will be the biggest
producer of oil and gas in the world. That is great news for
the U.S., it should be great news for Alaska. Global investment
in oil and gas in 2012 was $600 billion and for 2013 it is
projected to be $650 billion. In 2012, Alaska got about one-
half of 1 percent of that, despite being one of the world's
great hydrocarbon basins. That is bad news for Alaska. Slide
13 is another way of telling the investment story [for the years
2003-2012], he continued. Dramatic increases in investment
occurred in the U.S. and globally during this time period, but
investment in Alaska increased a little bit and then flattened
out. Alaska is on the sidelines with the global investment
boom. Alaska is the anchor in the U.S. energy renaissance.
6:19:30 PM
COMMISSIONER SULLIVAN posited that all of the aforementioned
begs the question of whether the current tax system is working
for Alaskans [slide 14]. He emphasized "for Alaskans," given
there is a lot of talk about "big oil." From the perspective of
[the administration] this whole debate is about the future of
Alaskans, he said. Slide 15, prepared by the legislature's
consultant, [PFC Energy], answers the questions in an important
way. At an oil price of $100, Alaska's government take is one
of the highest in the world. This is combined with the high
cost of doing business in Alaska due to remoteness, extreme
arctic climate, and limited exploration seasons. Between high
government take and high costs, Alaska has been uncompetitive
relative to other areas despite a global economic boom in
investment and production.
6:21:23 PM
COMMISSIONER SULLIVAN maintained the current system is not
working for Alaskans in another way [slide 16]. He said a term
used during the debates is "giveaway," and it is usually
mentioned in regard to what might happen in the future relative
to prices, production, or investment. He argued the real
giveaways have already happened - money that is already not
circulating in terms of tax revenue collected or economic
activity circulating through the economy. Between fiscal years
2008 and 2014, the production tax collected under Alaska's Clear
and Equitable Share (ACES) will decline by an estimated $3
billion despite the dramatic increase in oil prices; that is $3
billion in unrestricted general fund revenue that will be gone.
Today, about 14.6 million barrels a year fewer are flowing
through the Trans-Alaska Pipeline System (TAPS) than a year ago.
At $100 per barrel, that is about $1.5 billion that is not
circulating through the economy this year. That is a very clear
giveaway, he asserted, because it is gone.
6:23:33 PM
COMMISSIONER SULLIVAN said much of the focus has been on current
producers and current production, but another issue is companies
that might be considering investing in Alaska [slide 17]. Part
IV of the administration's comprehensive strategy to reverse the
TAPS throughput decline is to pitch to companies of all sizes,
including private equity companies and investment banks. Over
the last few years the administration has been trying to recruit
as many companies as possible to come, invest, and produce in
Alaska. In addition to the high cost of doing business in
Alaska, a concern heard almost every time a pitch is made is the
tax rates, particularly progressivity. He recalled testimony
before the committee by Brooks Range Petroleum Corporation [on
3/27/13] about the many investors the company approached and how
hard it was to get investment dollars. While it is unknown who
has been looking at Alaska and is not here because of the
current tax system, the system is very well known because the
administration is asked about it all the time.
6:25:26 PM
COMMISSIONER SULLIVAN stated Alaska's ultimate new entrant is
Repsol E & P USA Inc. [slide 18]. Regarding people who are not
interested in tax reform and who say there is no problem because
Repsol came to Alaska under the current ACES regime, he reported
that what the administration hears from Repsol is similar to
what it is hearing from other companies: great resource base;
very interested; high costs, particularly the tax regime.
[Citing Repsol's 3/6/13 letter to the Senate Finance Committee],
he said Repsol came to Alaska after it saw that the state was
serious about tax reform. Thus, Repsol has a different view
about ACES than the people who think there is no problem with
ACES. Repsol is the exact kind of company [the administration]
wants in Alaska - big, can provide more competition on the North
Slope, and very interested in finding and producing new fields.
Repsol sees tax reform as critical and if Repsol finds oil, the
action on tax reform is going to be very important as to whether
Repsol moves into production.
COMMISSIONER SULLIVAN pointed out that production is the focus
of the governor's bill and what elements need to be fixed, while
ACES incentivizes spending [slide 19]. Production is the
correct place for this bill to be focused, not just spending,
but on what is needed - production and rigs [slide 20].
6:28:09 PM
COMMISSIONER BUTCHER drew attention to slide 21, saying it shows
what a company currently producing in Alaska would have to do to
qualify for $100 million in credits from the state. Under ACES,
the company would need to spend $500 million in capital to
qualify for $100 million in qualified capital expenditure
credits. Under CSSB 21(FIN) am(efd fld), that same company
would have to produce 20 million barrels to qualify for $100
million in credit from the $5 per barrel credit. From the
state's perspective, it is much better to pay out $100 million
in credits for 20 million barrels of oil produced than to pay
out $100 million in credits for $500 million spent on anything
that qualifies as capital spending, not just specifically for
new development and new production of oil. He further specified
that the gross value reduction is limited to new participating
areas either inside or outside a legacy unit; thus, it is for
oil that is not currently being produced.
6:29:33 PM
COMMISSIONER SULLIVAN concluded the presentation by stressing
that Alaska's status quo of continued decline, when everybody
else is turning around their declines, is an unacceptable path
for the state. With tax reform that is focused on incentivizing
production, Alaska can do the same thing as the others. He
noted the Alaska Native Claims Settlement Act Regional
Association is calling for increased production as a way of
benefitting all Alaskans. This bill is about the future of
Alaska's citizens.
6:30:59 PM
REPRESENTATIVE SEATON, regarding the prospect of a gas sales
agreement and fiscal certainty, noted the three producers have
insisted they want 35 years. He inquired whether the
administration is ready to do a gas sales agreement with fiscal
certainty so that the fiscal system would be locked in for both
oil and gas for 20 or 25 years.
COMMISSIONER BUTCHER replied the administration is not at this
time looking at an extended period of locking something in. On
the oil side, it needs to be seen whether it works and if it
does not he thinks pretty much everybody is in agreement that it
will be changed. Gas is something that will occur down the road
and [the administration] has not gotten to the point in the
process that those conversations will occur. Determining what
can be done constitutionally in terms of giving fiscal certainty
over a long time period is a very complicated issue.
6:32:41 PM
REPRESENTATIVE SEATON commented there would be no need to worry
if that was the case. However, since the Alaska Stranded Gas
Development Act, and every time there has been talk about a gas
sales agreement, the three producers have been very specific
that that is only going to take place if there is fiscal
certainty over a long period of time. He said he wants to make
sure the administration is not looking at this the same way he
thinks the producers are, which is that it is going to be locked
in for a very long period of time. While it is nice to say the
state will change it if it is not working, fiscal certainty by
itself says that if the tax rate is changed there is a guarantee
that money will be taken out of the treasury to reimburse them
for any increase in tax costs. It would give much more security
if it was known "that the administration was going to oppose
fiscal certainty in a gas sales agreement and not lock in a tax
regime that is not automatically compensating in itself."
COMMISSIONER BUTCHER responded "that is certainly not anything
that has been discussed by the administration" that he is aware
of. At the moment it is premature and is not something that a
tremendous amount of time is being spent on.
COMMISSIONER SULLIVAN added durability is one of the governor's
four principles in terms of oil production. If the state
changes its tax regime every couple years it is not good for the
investment climate in Alaska. The other regimes discussed
today, like Texas and the Gulf of Mexico, have been durable and
[the administration] thinks that helps incentivize investment.
6:35:26 PM
COMMISSIONER SULLIVAN, responding to Co-Chair Saddler about
slide 4, explained that the broadest definition for hydrocarbons
is the U.S. Geological Survey's estimates of what is technically
recoverable but undiscovered, which is estimated at 40 billion
barrels [of conventional oil for Alaska's North Slope]. The
figure of 3.7 billion barrels is for known reserves [remaining
on the North Slope], which is the most narrow definition and
most exact.
CO-CHAIR FEIGE asked whether it is the difference between "P1"
and "P3" reserves. [P1 = proved, P2 = probable, P3 = possible]
COMMISSIONER SULLIVAN answered it is beyond "P3."
6:37:07 PM
REPRESENTATIVE SEATON, regarding a durable system that may get
locked in for a long period of time, related it is projected
that the in-field producing areas are where quick turnaround
could come from when people talk about three years. He inquired
whether it would be advisable to have some criteria built in
around production. For example, if a company were to cut its
specific rate of decline by 50 percent it would receive a per
barrel credit of $7 instead of $5, or if a company did not meet
that requirement its per-barrel credit would be reduced from $5
to $2. He said it seems there needs to be some hook in the tax
system that gives more advantage or disadvantage for actual
production. He further asked whether the administration has
thought about doing anything that actually requires production.
COMMISSIONER BUTCHER replied it was looked at, but did not make
sense for two reasons. First, a simple tax structure that is
easier to understand has value. Second, many different
variables play roles in what a decline has been for a company,
what a decline has been for a field. For example, in Field A it
makes sense economically for the company to spend a lot to stem
the decline to, say, 2 percent over a period of time, but in
Field B a company has a 7 percent decline and does not spend as
much. By incentivizing the rate of decline you would be
rewarding the company in Field B that might not have been
putting the work into stemming the decline that the company in
Field A would be. Issues like that are what play into variables
that result in unintended consequences.
6:39:38 PM
REPRESENTATIVE SEATON posited it sounds like it is being said
the state is not going to reward production because the tax base
is company-wide, not field-wide. It is not hard for the three
big producers on the North Slope to figure out their company-
wide decline rate. If it does not matter whether the companies
stem their declines, then it is exactly the opposite of the
administration saying that it wants to focus on production. He
encouraged the administration to think more about building in
some lever for the producing companies so there is focus on
production and not just on a tax decrease. If a tax decrease
does not yield additional production, he said, the state has not
accomplished its goal.
COMMISSIONER SULLIVAN responded the administration has been very
focused on the current system that has paid out enormous tax
credits and cash payments and does not require any commitment to
production at all, which is one of the flaws of ACES. The
governor's bill and CSSB 21(FIN) am(efd fld) make that nexus
between tax benefits and production much tighter. A nexus does
not exist under ACES and is one of the problems with ACES. The
administration is addressing Representative Seaton's concern, he
said. Right now, companies that have received hundreds of
millions in cash from the state could pack up and walk away
without having produced one drop of oil. The well-intentioned,
but flawed system under ACES is one reason why the
administration is focusing on production in this bill and
companies get the benefits of tax credits when they are
producing, unlike the current system.
6:43:11 PM
CO-CHAIR FEIGE clarified the gross value reduction is for new
participating areas and new units, so it is for oil that is not
being produced now.
COMMISSIONER SULLIVAN concurred the reduction is received when
new oil is produced.
REPRESENTATIVE SEATON argued the $5 per barrel would go on
whether it is old or new production; if a company stays where it
is and keeps declining, it gets $5 a barrel. If the purpose of
the bill is to ensure the state gets new production, it seems
that building in a single lever that if a company slows its
decline by over 50 percent within three years, it will get a
bump. If a company does not accelerate its production, then it
would get a penalty. That is simple and gives a goal. He urged
the administration to look at that idea more carefully because
he agrees the state wants to incentivize production, but the
worry is about the state not getting to that point.
CO-CHAIR FEIGE said he does not know why the administration is
being blamed, given the bill is in its third committee of
referral and is the now the legislature's bill.
6:44:50 PM
REPRESENTATIVE TARR recalled that yesterday the small explorers
testified the credits were essential to their coming to Alaska.
Had those credits not been in place, the Mustang project would
probably still have gone forward, but would have been delayed by
a few years. Thus, the next project that is going to bring new
oil is because of the tax credit system in ACES. Two of the
producers testifying yesterday said they scratch their heads
whenever they hear that the [ACES] credits are not leading to
new oil because new exploration and drilling is exactly what
these credits are being used for. She asked why these companies
are saying something that completely contradicts what the
administration is saying.
COMMISSIONER SULLIVAN answered the companies are not lying to
the committee, but if they packed up today they would walk out
with a lot of cash in their hands that they got from tax credits
from the State of Alaska that did not relate to any production.
6:46:02 PM
REPRESENTATIVE TARR asked whether Commissioner Sullivan is
suggesting the state might encounter a situation where companies
come to Alaska, spend hundreds of millions of dollars, and then
just pack up and leave.
COMMISSIONER SULLIVAN replied he is suggesting it is strongly in
the state's interest to make the nexus between tax benefits,
whether they are reductions or credits, strongly tied to actual
production. That is what the administration is trying to do in
this bill and that is what ACES does not do.
COMMISSIONER BUTCHER added nothing is being done with most of
the credits in the state's tax code. There is no suggestion
that the small producer tax credit or the explorer tax credit be
eliminated. This bill speaks specifically to eliminating the
qualified capital expenditures, which is the 20 percent credit
that currently-producing companies receive. This is the credit
that the administration is saying has no data showing that it
has led to new production.
6:47:06 PM
REPRESENTATIVE TARR understood the small producer credit and
exploration credit will be eliminated in 2016 under CSSB 21(FIN)
am(efd fld). She said she is concerned about what the small
explorers said regarding the need for legacy field development
and new exploration and drilling work happening simultaneously
because this bill seems to seriously disadvantage that kind of
work, as explained by the companies doing that work. She
posited the state will miss a big part of the opportunity to get
new oil if that is not considered.
COMMISSIONER BUTCHER responded 2016 is in current law; it is not
being made shorter. If it is not extended further, it will
remain 2016. Previous versions of the bill had it extended to
2022, which is something [the administration] would be
interested in discussing with the committee if the committee
wants to go in that direction.
CO-CHAIR FEIGE told Representative Tarr he would entertain an
amendment to that effect.
6:48:13 PM
CO-CHAIR SADDLER asked what Alaska's other options are for
revenue from natural resources or other sources, if no action is
taken and this production decline continues.
COMMISSIONER BUTCHER answered as has been seen in the last few
years, and what has made this such a critical issue to deal with
today, is that the state is losing tens of thousands of barrels
a day, so the price of oil must keep going up to keep the
state's level of revenue up. Fortunately for the state, the
price has gone up over the last few years, but that is not going
to continue. If the decline continues at its current rate and
Alaska continues losing barrels of oil, the gap would have to be
made up by many of the things that were discussed at the [March
2001] Fiscal Policy Caucus, which includes statewide income tax,
statewide sales tax, and the Permanent Fund. Currently, the
state has ample reserves to bridge the gap between where it is
today and when new production will occur, assuming this bill
passes and new production does in fact happen. In further
response, Commissioner Butcher said it is the administration's
view that decline in Alaska is continuing to occur at these high
prices while not appearing to be happening anywhere else. If
Alaska does not become more competitive, there no reason why the
decline would turn around since it has yet to happen [at these
high prices].
6:50:17 PM
CO-CHAIR FEIGE qualified he is not advocating this, but asked
how much oil revenue could be replaced by implementing a state
sales tax and state income tax.
COMMISSIONER BUTCHER replied he does not have those numbers off
the top of his head, but said it is absolutely the case if the
point being made is that it is a relatively small amount of
money compared to the oil revenue. He said if Alaska had no oil
revenue, like most of the lower 48 states, there would be no way
the state's small population of residents could be taxed to the
level needed to pay for the current budget.
6:51:08 PM
CO-CHAIR SADDLER inquired what the risk would be if the state
let ACES ride for another couple of years to see if it turns
around and is going to work.
COMMISSIONER BUTCHER responded decline would continue to be
seen, which is troubling because the North Slope is a much more
severe climate and much more expensive place to do business.
Places like Texas and Louisiana can explore for oil, find it,
and get to a point of production in 18 months, while the
historical average in Alaska is about 10 years. It is not a
situation where the state can sit around for a couple of years,
realize things are not getting any better, and then start
turning the wheels. These wheels need to start as soon as
possible because it is going to take a while to get on line,
particularly for the newer fields outside the legacy areas.
COMMISSIONER SULLIVAN said another issue is that as throughput
declines, TAPS tariff rates increase, which becomes an inhibitor
to new entrants. Getting new entrants is critical and the
administration has been working hard on this. New explorers and
new plays are needed, such as shale oil plays. If Alaska is
made more competitive, the resource base and the interest from
companies of all sizes is high, as far as getting that
production turnaround that is needed so badly.
6:53:28 PM
REPRESENTATIVE TUCK expressed his concern about the statement
that the credits do not lead to production. The small companies
testified last night that they are scratching their heads as to
why this statement was made. He said he is also concerned about
the statement that these explorers are profiting off Alaska's
tax credits and will cut loose and take their money out of the
state. The administration just showed a slide indicating the
state is giving these companies 20 percent in capital credit,
meaning they have to invest quite a bit, and he does think they
are investing to try to get that 20 percent from the State of
Alaska so they can cut loose and leave. He has problems with
these statements because these small companies are serious and
want to get to production on the North Slope; the state has
invested in them and partnered with them. In December 2011,
Pedro van Meurs compared Alaska with 120 other places that also
have shallow water oil and concluded that Alaska is in the
ballpark. Alaska has a lot of frontend loading which is so
attractive that the Department of Natural Resources is even
placing advertisements about it. It takes 7-15 years to make
new oil happen, so it is a combination of trying to maximize
what the state has right now with its current production and
partnering with industry to ensure long-term oil. North
Dakota's new production is unconventional production, and this
new production is applying new technologies due to high oil
prices. They are able to quickly get into the shale and
fracture it to start bringing wells, a luxury Alaska does not
have. Alaska recognizes the high cost of exploration and
development and the limited facilities in the state. Much of
the current investment is in facilities because the facilities
are needed to be able to drill. He maintained the state is on a
hope and a prayer if it relies on the type of economic policies
that just lower taxes and do nothing more than that.
6:57:34 PM
COMMISSIONER BUTCHER said the administration is not suggesting
that the small producer credit or exploration credit be reduced
or eliminated. The 20 percent being looked at for elimination
is for companies that are currently producing. The folks being
heard from are not benefitting from the credit that would be
eliminated because they are not currently producing. The
percentage received in state credits is considerably higher for
the exploration companies referenced by Commissioner Sullivan.
Depending on what they are doing, what they take advantage of,
and where they are, the State of Alaska reimburses a company
anywhere from 40 to 60 percent of what it spends.
6:58:40 PM
COMMISSIONER SULLIVAN added he does not think he said the
administration wants the small producers and new explorers to
leave the state. To the contrary, the administration has been
working very hard recruiting some and helping some of the ones
that have testified before the committee. The focus has been to
get them and more of them up to Alaska. The advertisement is
part of the recruiting effort; it was highlighting what is
currently in the law that is attractive; it did not include that
at $120 the government take in Alaska is close to 80 percent.
Based on his talks with different companies, he allowed they do
have different views depending on where they are in their
finances and strategies, but the general view is that there
needs to be a balance of having some limitations on credits up
front and a reduction in the progressivity, which the companies
clearly see as the most uncompetitive long-term capital return
element of investing in Alaska, particularly at high prices.
7:00:27 PM
CO-CHAIR FEIGE asked whether the ad mentioned by Representative
Tuck has generated any interest.
COMMISSIONER SULLIVAN answered it is always hard to tell. The
administration sees companies and goes back to see them after
being told to "take a hike," so the administration is relentless
on this. It is a long-term horizon with this industry as far as
things becoming positive from one year to the next.
CO-CHAIR FEIGE surmised that even though the 40 percent support
for exploration wells is being advertised, it is not necessarily
generating a lot of exploration.
COMMISSIONER SULLIVAN replied he would say the state needs more
exploration.
7:01:37 PM
REPRESENTATIVE P. WILSON observed from slide 20 that Alaska only
has 8 [active] rigs compared to 830 in Texas, 183 in Oklahoma,
and 174 in North Dakota. That tells her Alaska is in trouble
and she is concerned about it. The Fiscal Policy Committee she
was on looked at income tax, sales tax, even a school tax, to
try to bring in income. A 3 percent sales tax was nothing given
the number of people in the state, and the cost of setting up
the bureaucracy to put the tax in place made it pathetic.
Alaska is in a mess and something different must be done.
7:03:30 PM
REPRESENTATIVE JOHNSON noted production is increasing in the
U.S. and understood the current ANS West Coast price is $109 and
the West Texas Intermediate (WTI) price is $90.
COMMISSIONER BUTCHER responded the WTI is a little higher, about
a $12 difference the two prices.
7:04:05 PM
REPRESENTATIVE JOHNSON opined Alaska has been saved by high
prices; if prices were at $80 per barrel Alaska would be in very
bad shape. He inquired how much longer the ANS price premium
can be expected.
COMMISSIONER BUTCHER answered this has been looked at with great
interest because it used to be the WTI was $1 to a barrel
premium to ANS and that has flipped. Experts brought in for
[DOR's] forecasting session had thought that as more pipeline
capacity came on line in the Lower 48 near the gulf the WTI
would come up a lot more than the ANS would drop, eventually
shrinking the ANS premium of $20 to more or less what it used to
be. The experts thought this because ANS and Brent are both
within a dollar or two of each other and the real outlier is
WTI. Over the calendar year of 2011 into 2012 the difference
did shrink from $20 to $4 or $5 and it appeared to be doing what
everyone thought it was going to do, but then it turned around,
going back up into the high teens and now back down to $12. The
U.S. is starting to outperform Saudi Arabia and there is concern
that it is going to affect the price of oil because a lot of
states, such as North Dakota, filled the pipelines, then they
filled the railcars, and now they are trucking to the West Coast
where they get more for their oil; the added expense of trucking
is made up by this premium. Canada is looking at the same
thing. The price per barrel in Canada is in the fifties because
the first oil in is getting sold in the gulf. The further away
from the gulf, such as North Dakota, the price is $10 or so
under WTI, and once into Alberta it is dire straits. Alberta is
looking at whether to build a pipeline to the East Coast or to
the West Coast. Many factors are in play largely due to the low
price of WTI compared to ANS.
7:07:07 PM
REPRESENTATIVE JOHNSON said Alaska is blessed to have that
premium because the state would be in severe deficit spending
with the continued decline in production. The WTI and ANS could
become comparable very quickly - that does not mean the WTI is
coming up, the ANS could go down in a matter of months. If
today's price was $90 a barrel, Alaska's revenue picture would
look considerably different than what DOR forecasted. Alaska
cannot forever depend on price to save itself, Alaska must
depend on volume.
COMMISSIONER BUTCHER replied it is a frightening exercise when
playing with the production and the price. There have only been
a handful of years in history in which the price has been higher
than $90 a barrel. If the price of oil over a fiscal year were
to drop to $85, Alaska would be in billions of dollars deficit
for its current budget. That is how precarious Alaska's budget
situation is given its declining production.
7:08:38 PM
REPRESENTATIVE JOHNSON inquired how many millions less to the
treasury for each $1 drop in oil price.
COMMISSIONER BUTCHER responded he will get back to the committee
because the figure changes each year. Responding further, he
confirmed the dollar amount less depends on the oil volume.
7:09:18 PM
REPRESENTATIVE TUCK, regarding slide 20 and the low number of
drilling rigs in Alaska, said much of that has to do with being
unable to park the rigs on the back of a truck as is done in
many places. Having worked on modules on the North Slope, he
knows the drilling rigs are extensive rather than small ones
that can be moved around. It would be nice to have additional
active rigs - Repsol has had an aggressive drilling schedule but
there are not enough drilling rigs or drillers on the North
Slope due to the amount of activity that is taking place.
7:09:54 PM
REPRESENTATIVE TUCK, moving to slide 15, posited that if there
is a direct correlation between tax regimes and investments, it
could be said that Syria, Pakistan, and Bolivia probably have
very low investments [due to high government take], while
Ireland, Peru, and New Zealand [with low government take] would
probably have more investment.
CO-CHAIR FEIGE asked whether there is any oil in Ireland.
REPRESENTATIVE TARR said that is the point.
COMMISSIONER BUTCHER answered slide 15 was prepared by the
legislature's consultant, so the administration had no input as
to what countries or states were included in the slide.
COMMISSIONER SULLIVAN added that slide 15 is a snapshot of one
critical element of competitiveness, others being infrastructure
and climate. A positive for Alaska, however, is its small
resource risk - most companies think that when they come up to
Alaska to look for oil they will find it. When the
administration talks to companies, [government take] is
something heard from them almost across the board.
7:11:53 PM
REPRESENTATIVE TUCK asked whether at $85 per barrel Alaska would
be better off under SB 21 because it would not be losing so many
billions.
COMMISSIONER BUTCHER replied he cannot speak to CSSB 21(FIN)
am(efd fld), but he said Alaska would be better off under the
original SB 21. Would the state be better off billions more?
No, but the point he was trying to make is that as production
declines by tens of thousands of barrels a year, no bill or tax
structure is going to save that. It must be more development
and ultimately more production because that one factor that will
turn it around and be of more benefit to the treasury. Alaska's
reliance on high prices really gives the administration pause.
7:13:10 PM
REPRESENTATIVE TARR related that according to a slide prepared
by the administration's consultant, Econ One, more people are
working on the North Slope now than in 1990. She inquired why
so many people would be working if nothing is happening.
COMMISSIONER BUTCHER responded it can be seen on the slide that
the increase in employment began before ACES, which shows it is
an aging infrastructure. The increase continued the year after
ACES passed and then flattened out. If looking at Alaska in and
of itself, it looks like the state gained a little bit and then
flattened out. But in other oil producing jurisdictions, such
as North Dakota and Alberta, labor numbers are going through the
roof - tens of thousands of jobs - and those places are having
trouble keeping people in high school and college. A flat labor
force in a world of tremendous growth is not a positive piece of
the state puzzle from the administration's perspective.
COMMISSIONER SULLIVAN added it goes to the administration's
original comments that the statistics being cited as indicating
things are going great are not being looked at in the overall
picture of the industry in the U.S. and the world. Comparing it
to other jurisdictions is critical and keeping an emphasis on
production is what most of the administration's focus has been.
7:16:06 PM
REPRESENTATIVE TARR conceded Alaska's marginal rate ranks at the
bottom, but said Alaska's various credits are in the top ten
rankings and those credits are considered to have high or
moderate-to-high economic impacts. Alaska is more attractive
when looking at the whole package; progressivity and the credits
were a balance in putting the package together and incentivizing
the behavior that was wanted. Similarly, she posited, the bill
being contemplated now needs to be considered as a package in
regard to attractiveness.
COMMISSIONER BUTCHER concurred there are things that make ACES
attractive; for example, no other state pays for 40-60 percent
of a company's costs. However, things are breaking down when
the transition is made from the work on the front end to the
work on the production end because those companies are looking
at the tax rates. Alaska is the only oil-producing jurisdiction
still in decline. He agreed that that is what was trying to be
achieved with ACES, but said it is obvious to the administration
that it has not been achieved and is not working.
7:18:17 PM
REPRESENTATIVE SEATON drew attention to slide 21, noting
Commissioner Butcher had said the 20 percent capital expenditure
credit did not apply to small oil fields. He surmised the
commissioner wants to correct that to ensure there is not
misrepresentation. He understood from slide 21 that the gross
value reduction (GVR) is limited to new participating areas
whether inside or outside a legacy unit. He said he is pleased
if that is the administration's position because it is something
that can be determined fairly clearly.
COMMISSIONER BUTCHER deferred to Michael Pawlowski to answer the
question, but said everything is looked at in terms of having a
balance. He explained slide 21 is not a listing of what the
administration supports but is merely pointing out what is in
CSSB 21(FIN) am(efd fld) compared to ACES. He concurred he
misspoke if he said the capital expenditure credit did not
qualify for smaller fields with smaller companies. He said the
credit can be used against a company's tax liability regardless
of the size of the field.
REPRESENTATIVE SEATON stated the [gross value reduction]/gross
revenue exclusion (GVR/GRE) makes it simple and clear and he
hopes the administration will be supporting that as the standard
instead of using something that is unclear and subject to
administrative determination, which will be challenged.
7:21:13 PM
CO-CHAIR SADDLER related it has been heard that Alaska should
demand guaranteed production before adjusting its current tax
rate. He asked what elements are in current state laws that
guarantee current levels of any level of production.
COMMISSIONER BUTCHER answered those do not exist and said his
opinion is that the state is never going to get any kind of a
guarantee from a company, given all the variables that go on,
such as an oil spill that costs the company billions of dollars
or a better opportunity someplace else. To ask for a guarantee
is almost to say the state does not want to change the law so it
is going to set up a hurdle that is probably not going to be
attained. Does it need to be heard from companies that [the
bill] is material and do legislators need to be convinced by
what they say? Sure. However, he cannot imagine a board of
directors that would agree to expect a guarantee that if the
company does this the state will do that when the companies are
looking worldwide at opportunities at today's high oil prices.
COMMISSIONER SULLIVAN interjected that the status quo is not
working and it is going to be more [of what is seen on slide
10], and that should be a very big concern for everyone.
7:24:02 PM
REPRESENTATIVE TARR noted a concern is how the third element of
the GVR/GRE would be defined. As the bill is currently written,
the GVR/GRE is at the discretion of the DNR commissioner. She
asked how the department would meter and measure the production
and what areas might qualify. She paraphrased from the
provision on page 21 of the bill, beginning on line 25, which
reads as follows:
(3) the oil or gas is produced from a well that has
been accurately metered and measured by the operator
to the satisfaction of the commissioner, and the
producer demonstrates to the department that the
metered well drains a reservoir or portion of a
reservoir that the Department of Natural Resources has
certified was not contributing to production before
January 1, 2013, and the producer demonstrates to the
department that the volume of oil or gas produced from
the well was subject to certification by the
Department of Natural Resources.
7:25:38 PM
WILLIAM C. BARRON, Director, Division of Oil & Gas, Department
of Natural Resources (DNR), responded to Representative Tarr by
displaying slide 13 from DNR Deputy Commissioner Joe Balash's
3/22/13 PowerPoint presentation to the committee. He explained
the slide depicts a "bubble map" of the Kuparuk River Unit, in
which the oil that has been produced is represented on the map
in one color and the size of each bubble represents the volumes
of oil produced from each well. This simplified type of map is
used as an aid in reservoir management in terms of where oil has
been produced. The blue bubbles are water injection. As water
is injected and sweeps the oil from the injector to the
producer, a defined pattern can be seen, which is a very classic
water flow pattern and is actually a world class pattern. In
the southwest and southcentral-east edges are areas that
currently exist within the participating area (PA) that clearly
do not have wells and, where there are wells, the magnitude of
the bubbles indicate that those are very low producing wells.
The same exists in the gap between the PA boundary and the unit
boundary. Those are the areas that, under the current proposal,
the companies could bring to the division and demonstrate to the
division's satisfaction that they are not currently contributing
even though they are part of the PA. Demonstration is through
three dimensional reservoir modeling, such as streamline models,
pressure waves, water fronts, and oil migration patterns. When
a PA is originally created, the boundaries are established as
generously as possible, given these are giant fields and
protection must be provided to all parties so those parties on
the fringe of a field will not be harmed by not being in the
center part - so, trying to establish areas and establish tract
factors that allow smaller players or players on the fringe to
also participate in the production and the cost. The companies
would have to prove that those areas are not contributing.
Those would be areas that the division would say is really an
acceleration of existing proven reserves. Is it new oil? Yes,
it is new production. But it is not new oil that would be
necessarily bookable because it is already booked in the U.S.
Securities and Exchange Commission (SEC) definitions. The
division struggles a bit with that because that would be the
hardest form of the oil or the area to prove definitively that
it is not contributing. In theory and in spirit the companies
should be moving forward toward that development in the natural
course of development of field.
7:29:11 PM
MR. BARRON moved to slide 14 from Mr. Balash's 3/22/13
presentation, saying that in 2012 ConocoPhillips Alaska, Inc.
drilled the Sharks Tooth Well. Even though the company
classified it through the Alaska Oil and Gas Conservation
Commission (AOGCC) as an exploratory well and had a discovery
according to the benchmarks, it is actually discovery within a
PA, so it is kind of an oxymoron. That being said, that really
kind of showed that, yes, the PA was of the appropriate size.
In the proposed statute, that specific area would be an area
that the company could carve out, show that it was not currently
contributing, and then proceed with drilling operations,
facility installations, hookup, and modules to bring those
facilities on as new oil or accelerated oil through a PA - much
more difficult for the company to definitively prove than a PA
expansion or a new PA. In the hierarchy of new oil or expansion
of product, clearly the simple one is new units and within those
new units clearly new PAs. The stepwise procedure is to form a
unit and then build out the PAs in strata. The next step would
be expansion of PAs, where the size of the PA is looked at or
what can be proven geologically or through engineering with the
exploration and delineation wells. There are many times that
wells can actually be drilled side-by-side that really do not
communicate, especially when it is thin or lenticular or sands
that are part of a braided stream that meander through the area.
Those could be either new PAs or a new PA expansion, since it
could be said that they are in close participation areas and are
contributing with each other. As a company fills out its
drilling program it can begin to expand its PAs and a PA can be
expanded in a couple of ways. The division's preference is that
a PA be expanded by drilling rather than geologic modeling.
Geologic models are good, but they are fraught with error and
uncertainty that can only be proven by drilling.
7:31:44 PM
MR. BARRON continued, explaining that a company has its original
units, PAs within those new units, as well as new PAs within old
units, which happens quite often. How PAs come in over time was
shown in the 3/22/13 presentation, he noted. There are still
potential PAs within Kuparuk, between Kuparuk and Coleville, and
maybe within Prudhoe. So, there are the PAs, and the PA
expansions are off of that. This is really the next hybrid and
it will be more difficult to show that this production is
already in a PA but not contributing. It is doable
mathematically and scientifically, but the division's preference
is for the companies to come in and absolutely convince the
division that it is not contributing, a high hurdle to jump.
MR. BARRON addressed metering, noting industry's conventional
standard is to meter wells on a monthly basis and the aggregate
of their production at that drill site is based on an allocation
process that is approved by AOGCC. It is doable to install
multi-phase meters on every well, but it is expensive. It is
doable to install new facilities, and have a test separator for
every well, but probably not very efficient and not very
operationally friendly, so companies would probably shy away
from that. Multi-flow, multi-phase meters are fairly common
these days and reasonably accurate, plus or minus 8-9 percent on
total fluid. Those vary with difference of water cut and vary
with difference of gas to oil ratios and liquid ratios. The
more gas, typically the less accurate they are. The metering
could be individually by well or in aggregate. In Sharks Tooth,
for example, if a new pad was set and drilling went out from
that pad, then that area could be isolated off and metered and
monitored independently of the rest of the Kuparuk fields.
7:34:37 PM
REPRESENTATIVE JOHNSON inquired about the cost of a meter.
MR. BARRON estimated at least $10,000 and maybe $100,000 for the
facilities themselves. In further response, he said he is sure
his estimate is not low and said a multi-phase meter is probably
in the ballpark of $10,000. He offered to find out exactly.
REPRESENTATIVE JOHNSON asked how many people know the technology
for repairing these meters.
MR. BARRON replied the University of Alaska Anchorage (UAA) and
University of Alaska Fairbanks (UAF) have good programs for
training the state's high school graduates and college kids as
technical people for the oil field. Instrument technicians are
capable of doing this kind of calibration every day. Responding
further, he said it is one thing if it is only Alaskans that are
being looked at for doing this work, but in the greater world of
the oil industry instrument technicians is an up and coming part
of the business. Years ago instrument technicians worked solely
with pneumatics, gas and air pressure equipment, but now they
have gone to small wires. It is basically a migration of
technologies, and small wire personnel are now regularly
available. Many companies have very good training programs to
support that and many are building from the ground up.
7:37:11 PM
CO-CHAIR FEIGE inquired how oil is typically measured as it is
transacted between the companies and the state.
MR. BARRON posed a scenario of a drill site with a group of 20
wells, explaining every well must have its own individual test.
Each well goes through a test separator or has a multi-phase
meter on it, depending upon what is needed for reservoir
management purposes. Currently, AOGCC requires a monthly well
test, which can be certified and corroborated through the
company. Once that well is out of test it is put into a bulk or
group separator, which is where everything goes if it is not in
test. It is a simple system - just valves on a header to move
the oil around. That oil is then shipped from that drill site
to a flow station or gathering center for further processing.
That is typically where most of the gas is knocked off and water
extracted, and that is metered at every step of the way - not
for allocation purposes, but for leak detection. As the oil and
fluids migrate from a drill site to a gathering center and then
from a gathering center to Pump 1, all of that is metered so the
oil companies can look for leaks. Discrepancy of the incoming
and outgoing meters is what sends the alarm for leaks. At that
point is where the transaction occurs between the industry and
to the pipeline. For the state, the well test is the earmark
that [the division] works from through AOGCC for reservoir
management, production allocations, and royalties.
MR. BARRON, responding further to Co-Chair Feige, said a revenue
transaction is a rollup based on production from the well itself
from that well test. The companies have to identify from the
well test what each well has contributed to that drill site and
then that is where the royalties and revenues come from,
corroborated by all the meters along the way.
7:40:14 PM
REPRESENTATIVE SEATON commented he was pleased when he saw slide
21 and it appeared that the administration was favoring new
participating areas. He asked about the number of personnel
that would be required by the division or whether it would be in
conjunction with AOGCC for handling the acceleration within a
participating area, the claims, the data, and appeals.
MR. BARRON responded that it is a hard question to answer. The
burden of proof still needs to be on the industry/companies for
all of that, even the PA expansions. The division has the staff
that can look at the information and make the determination as
to whether it is in fact contributing based upon the technical
presentation. If the division is inadequately staffed, it can
gather consultants. The AOGCC is more involved with well
metering, well allocation processes, and well inspection. The
AOGCC is also involved with any federal, Native, or private
leases; the division is blind to those because it has no
jurisdictional claim over anything other than state lands. He
would say, at this point, that the division would not need any
additional staff to do this piece, but might have to reach out
periodically for consultant services, which would be budgeted
for. It is hard to say right now, he continued, given how the
PAs are built and how many of them would have the kind of
demonstration that is had at Sharks Tooth.
7:42:52 PM
REPRESENTATIVE SEATON posited that with the 20 percent GVR/GRE
there will be a real impetus to forward every possible well for
consideration and proof. Another consideration is shale oil, he
said. He asked whether every shale oil well is going to be
considered a new PA for the purposes of this determination.
MR. BARRON, regarding every well for the GVR/GRE, noted that
wells clearly within the pattern would be very difficult for a
company to say is new oil. Regarding shale, he said it is a bit
of a conundrum that everyone is trying to get their arms around.
The division does not currently see overall justification for
forming broad units for shale because part of the definition of
the reason for having a unit is for the correlative rights of
players. A single well can only really contribute unto itself
and not have any interference or contribution from outside of
its drainage area because of the tightness of shales, so every
one of those would be maybe its own unit. He said he does not
know that he would call it a PA. Under this definition every
shale well would arguably be new oil.
7:44:47 PM
REPRESENTATIVE SEATON related that on a recent [legislative]
field trip, ConocoPhillips had a coiled tube drilling unit and
was using seismic to look at fault blocks. He posited the
company will propose that each fault block and well - and there
are going to be eight wells - is new oil. The company is
drilling in existing well bores, but it is going out to other
areas beyond to accelerate the flow and that is his concern when
talking about within existing participating areas. A company
would be presuming every one of those as being an acceleration
of a PA or accessing something that was not being produced and
he sees a lot of proposals coming to the division on that basis.
He inquired whether, instead of doing an enhanced oil project in
a well, a company might do something else so that 20 percent of
the revenue can be excluded.
7:46:24 PM
MR. BARRON answered that, typically, the company is using multi-
lateral and coiled tube drilling to look at its current
reservoir model and the bubble map and trying do augment its
current enhanced oil recovery (EOR) projects. Through infill
drilling, increasing sweep efficiencies, modeling, and pressure
results, the company is finding areas that are not currently
being swept. It is infield work. Each one of those would
clearly not be new oil. If the proposed program was put in
place, the company would have to come to the division and
originally prove it through reservoir modeling. He proffered
the division would also ask as part of the stipulation that once
drilling is commenced a series of very extensive tests be
conducted to show to the division that it had not previously
been contributing. For example, if an area was drilled into
that was said not to be contributing and the pressure was found
depleted, the division would say it is obviously in
communication and has been contributing in some degree. So,
there would probably have to be a two-stage test associated with
reservoirs or new oil within existing PAs. This is the piece
that is the most difficult to get one's arms around.
7:48:38 PM
MR. BARRON, continuing his answer, said he does not know that he
would support the idea that there would be a lot coming in.
When looking at a field like Kuparuk or Prudhoe that has been
extensively delineated and developed, he would not expect to see
many isolated fault blocks that are not in some form currently
producing or contributing to production - it would be unique.
Areas that are on the fringe, the fringe oil, the PA expansions,
he would offer, would be quite likely. Originally some of the
PAs were designed and established with 20 and 30 foot pay
cutoffs, today the limit would probably be a 10 foot or 5 foot
cutoff. Some of these PAs could easily be expanded by lateral
drilling into thinner and thinner zones. Those would be clearly
new oil and the company would have to show the division what it
was going to do and how the company is going to do it.
7:49:53 PM
CO-CHAIR SADDLER requested clarification about whether most
fault blocks are currently contributing production.
MR. BARRON replied it is a generalized statement. Each field in
each area would have to be looked at to make that determination,
which is why it is so critical the burden of proof be placed on
the oil company itself. The areas that Pioneer and ENI are
developing are uniquely different than the areas of Coleville
River, or Kuparuk, or Prudhoe, or Badami. Each is a unique
reservoir system and reservoir management system, which is why a
blanket statement that all fault blocks are contributing is not
fair or reasonable. When answering Representative Seaton's
question, he was trying to discuss fields that are extensively
developed, like Kuparuk or Prudhoe. In his opinion, the
likelihood of such fields having new areas that are not
currently contributing, with the exception of the fringe, would
be on the lower side rather than the higher side.
7:51:08 PM
CO-CHAIR SADDLER understood Mr. Barron to be saying that the
third category of GVR/GRE determination is unlikely to produce
much oil qualified as new oil under this current definition.
MR. BARRON responded that would be a reasonable way to phrase
it, but qualified his comment is speculative and he put it out
there just as a speculative comment. Much of it will depend on
how aggressive the companies are. The conundrum needing to be
solved here is that this is oil that is already within the PA.
The first hurdle to get past in the division's dialogue with the
industry is that this is oil the company has already established
within the PA and should already be in the company's development
scheme. The company would have to explain to the division why
this oil is not in the development scheme and where it was in
the company's original planning; for example, whether there were
geologic or engineering factors that precluded doing this
originally.
7:52:24 PM
CO-CHAIR SADDLER surmised a company making an investment
decision would not know whether the oil would qualify as new oil
under the GVR/GRE definition when running its economic modeling.
He inquired whether the GVR/GRE would be easy to factor.
MR. BARRON said the answer is "probably yes." When a company
looks at the natural step out from the center to the edge of a
field, it will have a reasonable idea of what that timing is
going to look like. The further away from infrastructure the
higher is the cost, which is why the fringe areas tend to be the
last to be developed. It is his experience that most companies
will run a series of economics with tax credits, or with the
GVR/GRE, included and excluded and will find that balance of how
and when and what the difference between the two are - this
series of economics is run anyway. The real question is if the
company runs it and it is not economic and yet it is not
contributing. His question to the company would then be, If it
is not contributing and not going to be done, why not collapse
the PA? If the end result is collapsing the PA to where the
company is going to have its producing boundaries, then that is
a business call that the company should make.
7:54:20 PM
CO-CHAIR SADDLER asked whether there is any benefit to a company
to collapse its PA.
MR. BARRON answered "not necessarily."
CO-CHAIR SADDLER inquired whether there are any costs associated
with that.
MR. BARRON replied the only cost is making sure the interests of
all parties are protected in terms of another player and that
that player is in tune with what is being done and come back
through with tract allocation factors and rejig financials.
Again, it is a burden on the industry.
7:54:55 PM
CO-CHAIR FEIGE invited the DNR deputy commissioner to comment.
JOE BALASH, Deputy Commissioner, Office of the Commissioner,
Department of Natural Resources (DNR), added the awkward part of
this is going to be when companies come in the door looking to
have part of an existing PA qualify for the GVR/GRE because it
is not contributing to production. Probably one of the first
questions the department will ask is, "Well, why is it in the
PA?" The likelihood is that the company thought it was going to
contribute at one point or another and it turned out that it did
not because of something unforeseen. In looking at the broader
boundaries of a PA and where the wells are and which ones are
producing and contributing, the question is, "At what point is
there too much of a cushion there?" At what point should those
PAs be a little more actively managed and trimmed back so that
if through an expansion of the PA, there is a really clear
delineation and understanding of what will be done, what would
be contributing to production. He said the previous iteration
of this language had something that the department was quite
comfortable with in terms of the cascade that Mr. Barron
referenced earlier - units, new PAs, expansions of PAs, and then
this, which could be nicknamed a sub-PA.
7:56:54 PM
REPRESENTATIVE SEATON read from [slide 13] of AOGA's [3/27/13]
presentation which states: "CSSB 21 attempts to expand GRE to
80-90 [percent] of the potential development on North Slope in
legacy fields." Thus, he said, AOGA's perception of what is
going to qualify for the GVR/GRE is much broader than what DNR
seems to be talking about and seems to be at odds with DNR's
perception. He also recalled AOGA talking about the companies
not knowing if something qualifies for the GVR/GRE until after
the investment is made so they will be unable to use the GVR/GRE
as a factor for determining investment. He further commented
that 80-90 percent is quite a bit in any accelerated production
out of the legacy fields.
MR. BARRON responded he did not see AOGA's presentation, but in
looking at the slide he clearly cannot identify where 80 percent
of Kuparuk would satisfy the GVR/GRE of not currently
contributing to production. There is a disconnect if 80 percent
is AOGA's understanding, he said. The entire intent that DNR
would be presenting is that if a company thinks an area is not
currently contributing, then prove it, and that is the threshold
that the company would have to climb.
CO-CHAIR FEIGE pointed out ConocoPhillips Alaska, Inc. is not a
member of AOGA.
REPRESENTATIVE SEATON said he is just talking about AOGA's
presentation on the legacy fields.
7:59:43 PM
CO-CHAIR FEIGE asked whether it is technically possible for the
state to give a company assurance before it makes its investment
decision that that "shape in the ground" will actually fall
within this particular GVR/GRE.
MR. BARRON answered "not definitively" and said that is why as
part of the process, probably through regulations, DNR would
stipulate a multi-step process: 1) identify the sub-PA area and
prove it as best as possible, and then 2) drilling and testing
to confirm the company's reservoir modeling or justification.
The threshold the state would take is if at step 2 it was proven
that it was previously contributing it would be excluded from
the GVR/GRE. Thus, a company would not know definitively before
it makes the investment, but the company would probably be
running dual economics to determine whether it is economic.
CO-CHAIR FEIGE, assuming that that "shape in the ground" falls
in a GVR/GRE, inquired whether the oil coming out of the ground
could be accurately measured in an economical and practical way
to sufficiently satisfy DOR.
MR. BARRON confirmed it would be to the standards of DOR for
that department's purposes, but in conjunction with AOGCC.
Through interaction between AOGCC, DNR, and DOR, programs and
protocols could be established that would satisfy all parties in
terms of accurate measurement of those areas.
8:02:25 PM
REPRESENTATIVE TARR, noting the fiscal note was prepared quickly
after CSSB 21(FIN) am(efd fld) passed the Senate, asked whether
the bill's estimated fiscal impact is accurate, given the
uncertainty and evaluation that has taken place since that time.
For example, the fiscal impact for fiscal year 2015 is estimated
at $25-$175 million.
MR. BALASH replied that today Oooguruk and Nikaitchuq would
qualify for this category within the GVR/GRE, and hopefully a
couple more units would as time goes on. He offered his
understanding that DOR took a conservative approach when
estimating the potential applicability of the third category.
He posited DNR would push that estimate to the lower end if it
was making the estimate, but said DOR wants to provide a broad,
but reasonable, estimate for the legislature as it considers the
impact of the provision.
8:04:11 PM
REPRESENTATIVE SEATON requested Mr. Balash to provide an
estimate of the fiscal impact should 80-90 percent of new oil
produced from the legacy fields qualify for that provision of
the GVR/GRE, as anticipated by the industry. Legislators need
to know what it would be using industry's numbers as well as the
state's conservative numbers, he said.
MR. BALASH deferred to DOR to put that together. He said he
thinks the 80-90 percent figure is just in reference to the
percent of oil that is out there in the fields, not necessarily
inferring that 80-90 percent of the production is going to
qualify for the GVR/GRE.
CO-CHAIR FEIGE reread the AOGA statement cited by Representative
Seaton, emphasizing 80-90 percent of "potential" development.
8:05:59 PM
REPRESENTATIVE TARR inquired how DNR is incorporating the
natural decline curve of 10-12 percent into the overall picture
of decline. For example, ConocoPhillips has said it can get the
decline curve to 3 percent.
MR. BALASH responded a substantial amount of work on declines
and decline curves has been done by the Division of Oil & Gas in
conjunction with DOR for purposes of revising the production
forecast methodology. He offered that, rather than slog through
another presentation, DNR prepare materials for forwarding
through the co-chairs' offices. Because natural decline is a
term of art, he urged that thought be given to what the decline
would be if no additional work was done. A tremendous amount of
work continues to be done in legacy fields - new wells are
continually drilled to bring on additional rate or reserves and
DNR thinks much more could and should be done. In the whole
scheme of things, what is trying to be done is get the state's
base tax system to a point where those things will happen, that
a GVR/GRE is not needed for doing the normal course of business
and activity in those legacy fields. Fundamentally, the base
system needs to drive the investment behavior, not the bells and
whistles. The bells and whistles - the GVR/GRE - is really
something that is intended to help bring on new reserves in new
units in outlying areas or reserves that are not currently in a
participating area (PA). Since PAs should be booked, it is
known that Alaska has approximately 3.3 billion barrels in
proven reserves and it is estimated that in just the onshore
central North Slope area there is over 3 billion barrels in
undiscovered economically recoverable oil at today's prices.
Finding those accumulations will start to add to Alaska's
reserve base because one of the most important things in the oil
business is the bottom line number of how many reserves. If
that number is going down it means going out of business and
Alaska's number is going down. The GVR/GRE is a mechanism to
encourage companies to put more reserves on the books, more of
Alaskans' reserves, on Alaska's books.
8:10:44 PM
CO-CHAIR FEIGE observed the third category of GVR/GRE uses the
term "accurately measured and metered". He asked whether it is
possible to satisfy DOR's requirements for accurately metering
that oil to determine how much is new oil.
COMMISSIONER BUTCHER replied the short answer is yes, DOR
believes it would be able to do that. He deferred to Mr.
Pawlowski for providing more detail in this regard.
8:11:52 PM
REPRESENTATIVE SEATON inquired whether oil coming from an
existing well bore that is tapping new areas through coiled
tubing can be accurately metered to determine how much of the
production is new oil.
MICHAEL PAWLOWSKI, Oil & Gas Development Project Manager, Office
of the Commissioner, Department of Revenue (DOR), answered it
certainly poses a challenge and will require collaboration by
the three departments to develop the standards for that
particular measurement. The other body's intent in developing
the provision was to expand the realm of possible application of
the GVR/GRE to target as much potential new production as
possible. It is certainly difficult and there is a higher level
of threshold that needs to be met for the commissioner.
Individual wells could pose a problem, while aggregating the
wells into a multi-well development is much easier. Those
things would be defined by the departmental collaboration and
regulatory process.
8:13:30 PM
CO-CHAIR SADDLER asked whether the determinations through
collaboration of the departments would be on a de novo basis
every time there was an application or would there be, over
time, the development of a precedent.
MR. PAWLOWSKI replied the intent of the departments in working
with the other body in developing this language was that the
maximum of clarity be put before industry so that the processes
and procedures are known at the time. The intent is to put as
much clarity up front as possible, while retaining the
flexibility as described by DNR to make those determinations in
the state's interests.
CO-CHAIR SADDLER, while understanding that every circumstance
cannot be foreseen, inquired whether that standard would evolve
as applied and the back and forth happened.
MR. PAWLOWSKI responded DOR's understanding is that development
of the metering and measuring, the basic counting, would be a
standard that would be reached and be fairly fixed. He said
DOR's teams are concerned with how many barrels are coming out
of a particular development and once the standard is developed,
it is the standard.
CO-CHAIR SADDLER asked whether this system is used in other tax
regimes to identify new oil.
MR. PAWLOWSKI answered he does not know and suggested asking
DNR. It is known that other jurisdictions look at things on a
well-by-well basis, he said. In Alaska's system, royalty is
allocated back to the wells on a lease basis. To provide that
type of clarity will require development of an appropriate
standard through a collaborative process with industry.
8:15:52 PM
REPRESENTATIVE TARR observed this provision would become
effective 1/1/14 and posited that, due to the elimination of
progressivity, this would be done on an annual basis, so the
state would not know if it had missed the ballpark in its
estimates for the GVR/GRE.
MR. PAWLOWSKI clarified the elimination of progressivity is not
affecting the monthly payment of tax or the annual true-up of
tax at the end of the year. The repeal of progressivity affects
Alaska's tax rate such that under the proposed bill Alaska's tax
rate would remain at the fixed rate of 35 percent, while under
the current regime of ACES it varies wildly from month to month.
REPRESENTATIVE TARR inquired when the state will be able to
audit how the GVR/GRE is applied.
MR. PAWLOWSKI replied it would be in the normal course of the
auditing process.
8:17:06 PM
REPRESENTATIVE TARR understood that currently the auditing
process is still looking at 2007.
MR. PAWLOWSKI confirmed DOR is still looking at 2007. Part of
that continuation is that changes in the system have an effect.
He pointed out changes have also been made at the federal level
that have re-opened some portions of some of those returns.
Returns get amended as retroactive changes apply, he explained.
In addition, the state has changed regulations in a retroactive
manner, interest penalties being an example. Going back to the
question of audits, he allowed it will certainly take time, but
should accelerate a little once DOR's [new] tax revenue
management system is implemented, and the process of going
through the production profits tax (PPT) to ACES is completed.
REPRESENTATIVE TARR requested DOR to provide the committee with
a walk through on the timing of that.
8:19:25 PM
The committee took an at-ease from 8:19 p.m. to 8:26 p.m.
8:26:23 PM
REPRESENTATIVE SEATON recounted how [last week] he asked the
consultants whether a system could be designed where there is a
trust account under which tax is calculated as it is and also
calculated in the new amount and then there is a revolving
amount that would be held over and if the producer did not meet
benchmarks of production within so many years that portion would
be lost and revert to the state. The consultants answered that
they could not figure out a way to do that without having a lot
of interferences. Earlier tonight with Commissioner Sullivan
and Commissioner Butcher he put forth the idea that if Alaska's
tax regime is changed there is a way for ensuring that the state
gets the increased production it is looking for. Now, he said,
he is wondering whether the consultants can look at the $5 per
barrel credit and suggest some benchmarks such that if in three
years, given it is the legacy producers being talked about here,
an individual company does not cut its decline rate by 50
percent the credit would be reduced to $2, but if a company
meets or exceeds that 50 percent reduction in the decline the
credit would rise to $7. This way there would actually be a tie
to increasing production. He requested the consultants to
discuss having the credit on this type of basis.
8:29:43 PM
REPRESENTATIVE SEATON, at the request of Co-Chair Saddler,
restated his question. The bill includes a $5 per barrel credit
for every barrel that is produced, he said. The intention in
this tax regime is to incentivize increased production, yet the
$5 credit will still be given even if production is declining.
He asked whether benchmarks could be built into the system such
that if the production benchmarks are exceeded the credit would
be more than $5 per barrel and if a reasonable benchmark is not
met within three years, given this would apply to the legacy
fields, then the credit would be reduced by $3 per barrel.
8:30:55 PM
ROGER MARKS, Economist, Logsdon & Associates, consultant to
Legislative Budget and Audit Committee, responded by first
noting that the reason everyone is here is the perception that
Alaska's tax system is not competitive and, because of that,
people are dissatisfied with the amount of production and
investment. The goal is to make the tax system competitive.
Producers are not investing in Alaska simply because they can
make more money putting money in other places where they do not
have to pay as much tax. Producers will perceive a risk if
benchmarks are put out, he advised. The future is uncertain,
there are many things over which producers have no control, and
there is the risk that if they invest and then do not make the
benchmarks then the oil produced is penalized by high tax just
like it is today. Uncertainties include external events, such
as a drop in oil prices or the situation like ConocoPhillips
where it took more than five years to get a permit from the
Environmental Protection Agency (EPA) to put a bridge across the
Coleville River. There are situations where investments are
very lumpy - a company could go along for a while not doing much
and then suddenly a big investment raises its production, but
then it has the same decline but from a higher rate. At Prudhoe
Bay there are three major working interest owners; their other
interests in different fields vary and investment for one
producer may help that producer's overall decline rate for one
field but not another. Working interest owners in a given field
might have vastly different interests in where they put their
investments. For these reasons, when the question was put to
him last week, he could not see a meaningful way to come up with
any benchmarks that would not scare producers into doing no more
investing than what they are now just because of the uncertainty
that they might be left with what they have now. He deferred to
the other consultants for their opinions.
8:34:07 PM
REPRESENTATIVE SEATON said he wants to make sure it is not his
question about a trust account that is being talked about by Mr.
Marks. He said he has set that question aside and is now
talking about having benchmarks on that $5 per barrel credit.
He chose three years because that is the time period stated by
producers for the legacy fields.
MR. MARKS replied he sees coming up with a benchmark for that
sort of mechanism no less challenging. He suggested the other
two consultants, Mr. Mayer and Mr. Pulliam, be asked for their
perspectives on the question.
8:35:48 PM
JANAK MAYER, Manager, Upstream and Gas, PFC Energy, consultant
to the legislature, stated there is a carrot aspect and stick
aspect to what is being posited by Representative Seaton - if a
producer meets its benchmark it gets an improved dollar per
barrel credit and if it fails the dollar per credit is reduced.
He said he is less concerned about the carrot aspect than he is
about the stick aspect. How a producer sees it will vary
depending upon cost assumptions and whether it is one year that
is being looked at or across the project lifecycle. The bill's
current structure of a 35 percent rate and a $5 per barrel
credit is a tax increase. The 35 percent rate and a $2 per
barrel credit would be a fairly substantial tax increase at lots
of prices. Therefore, he advised, the idea that if a producer
fails to meet a benchmark and the state's response to that is to
raise the producer's taxes even further at most price levels, is
probably not going to be a strong move to build confidence in
future investment in the North Slope.
8:37:21 PM
BARRY PULLIAM, Economist & Managing Director, Econ One Research,
Inc., consultant to the administration, concurred with Mr. Marks
and Mr. Mayer. Mechanically, such a thing could be designed, he
said, but the challenge would be to get those carrots and sticks
at the right place. Designing a good, competitive system at the
base level is what is being sought; the bells and whistles are
not what should be had as the main feature of the system. The
bill's current rate and per barrel credit operate in conjunction
with each other, both to provide a credit that is tied to
barrels and as an important way to get the right tax rate over
the price range. Should the committee go down the road that is
being posited, he would urge there be nothing punitive, such as
lowering the credit to $2 if a benchmark is not met, because
going punitive does not send a good signal at all. The 35
percent rate and $5 credit is designed to get Alaska to a point
that is competitive and that should attract. If the committee
is going to do something, although he does not know he would
encourage that, he would suggest looking at the carrot side,
such as offering a higher incentive to get to a certain level;
for example, raise the $5 credit to $7, provided the state can
do that fiscally.
8:40:05 PM
REPRESENTATIVE JOHNSON asked whether a company would, should
such a system be adopted, do its modeling using the stick,
possibly taking away the attractiveness of the project.
MR. PULLIAM responded that that would become their stress test,
the project would have to meet the worst case scenario.
8:40:42 PM
REPRESENTATIVE TUCK understood Representative Seaton's proposal
to be that the credit is $5 per barrel and if the benchmark is
exceeded the credit would be more and if the benchmark is not
met then the credit would be less. He posited that this is less
of a carrot rather than being a stick.
MR. MAYER answered the problem is that concurrent with this the
base rate is increased from 25 percent to 35 percent, and 35
percent with a $2 credit is a substantial tax increase at quite
a wide range of prices compared to the current tax under ACES.
So, what is essentially being said is that if a producer fails
to meet the state's performance benchmark the producer's taxes
will be raised even further above where they are today.
8:41:34 PM
CO-CHAIR FEIGE understood the problem with a performance
benchmark in a field with shared ownership is that a producer
would have to depend on its partners to come through to make all
that happen.
MR. MARKS replied correct. Each company will have different
working interests in each field and will therefore have
different incentives to put investment in different fields,
which would create a misalignment within the units.
MR. PULLIAM added that, while not the mechanism described by
Representative Seaton, there is a carrot to add barrels, which
comes in the form of the GVR/GRE. The GVR/GRE is an additional
benefit over and above the [$5 credit]. If producers can find
new barrels to add, they will have the benefit of the GVR/GRE,
which is, basically, an additional credit.
8:42:56 PM
REPRESENTATIVE JOHNSON, tying the aforementioned question and
the GVR/GRE together, noted producers will do their base case on
"the stick" and will not know about the GVR/GRE until they drill
the well, jump through hoops, and prove it. He therefore asked
what value is it when it comes to project economics.
MR. PULLIAM responded it is known with respect to the new unit
and new participating area (PA). For the others, he concurred
there is more of a hurdle. As described by Mr. Barron, the
intent would be to have to have those barrels proved up and the
ultimate proof would involve at least making some investment
because the producer would have to drill and do some appraisal
to satisfy DNR that this does indeed meet the requirements. He
said his sense is that the majority of the investment for the
full development would probably then take place after that.
8:44:26 PM
REPRESENTATIVE JOHNSON posed a scenario of a producer doing
project economics for oil that may or may not be there, and if
the project qualifies it is a good project. But, if it does not
qualify it is not a good project, so why drill that first hole.
MR. MAYER explained that that same circumstance of decision
making uncertainty applies to almost any risk-taking activity in
the upstream sector. An initial exploration well is drilled
with a strong chance of drilling a dry hole, an appraisal well
is drilled to delineate a field with the possibility the result
will not be as big as was thought. He allowed there could be
further work to do in defining this aspect of the GVR/GRE, and
trying to create better certainty as to how exactly it applies
and what that process would be. As described by DNR, there may
be some investment required in terms of drilling a well in the
same way as when drilling a well to delineate and appraise a
known prospect; that is not the same as an ultimate final
investment decision on an entire development of that area.
8:45:45 PM
REPRESENTATIVE JOHNSON said attracting new development is what
is being looked at and he is one of those people who believe the
next Prudhoe Bay is Prudhoe Bay and that drilling must be done
in the legacy fields. The GVR/GRE may or may not make certain
areas profitable within an existing PA, and while clarification
of the GVR/GRE is needed, he is wondering the value of it. He
agreed with Representative Seaton that putting new oil in the
pipeline should be able to be done within three years and that
that oil will come from the legacy fields. He wants Alaska to
be real attractive, not in the middle of attractive. He said he
thinks any oil from a new hole in the ground should qualify,
although he recognizes he is probably alone in that thought. He
said he would like to work on cleaning up the GVR/GRE so that it
is a more attractive investment matrix on paper before the
producer has to go through the investment process. He requested
the opinion of Mr. Marks in this regard.
MR. MARKS replied it is what the committee wants. He said his
understanding of the existing North Slope reservoirs is that
there are hundreds of isolated fault blocks or stratigraphic
traps that have weak communication with the rest of the
reservoir that really need to be drilled directly to produce.
His impression from Mr. Barron's comments this evening is that
very few of those would qualify for the GVR/GRE or there is the
possibility that very few would qualify, as the bill is
currently written. Doing reconnaissance work means drilling the
well, which is the main cost. If indeed these targets may be
contributing to existing production, but not in a material way,
maybe it would be possible to re-craft the language to address
those kinds of targets, if that is what the committee wants.
8:49:02 PM
REPRESENTATIVE JOHNSON expressed his concern that the weak
connection mentioned by Mr. Marks would disqualify that well.
He further argued that while weak pressure means the oil is
going somewhere, it may not be going to the well that is being
drilled. He would like to explore [re-crafting the language]
because increased production needs to happen in three years, not
seven, and will need to come from the legacy fields which may be
excluded under the current language. He said he will be looking
to the consultants and the co-chairs for help in this regard.
8:50:20 PM
CO-CHAIR SADDLER said he would be open to suggestions for
clarifying the GVR/GRE if it is determined to be the best tool.
He, like industry, would feel more comfortable with more clarity
as to how the language before the committee would actually be
applied. He inquired whether the GVR/GRE is the best tool, or
should there be something else, if the goal is to have an
element of Alaska's tax encourage development of new oil.
MR. MARKS responded the whole point is to be competitive with
other jurisdictions that have the same general risk/reward
balance. The first step is to figure out the jurisdictions
Alaska is competing with, what the government take is in those
jurisdictions, and where does Alaska want to land as a target.
A number of tools can then be used to get to that target. When
he was looking at the competition while the bill was being
developed, his judgment was that a government take of about 62
percent across a broad spectrum of prices would be competitive
with Alaska's peer group. The consensus was to have as flat a
rate as possible through a spectrum of prices because the
international landscape is fairly flat. The question is how to
achieve that take. The main thing is the target of 62 or 64
percent, regardless of the method used for getting there. A
challenge with Alaska's tax system is that it has high tax rates
at low prices due to the royalty, which is regressive. This
needs to be offset, especially when costs are high. The $5 per
barrel credit and the GVR/GRE are used to get as flat a rate as
possible at low prices and across the spectrum.
8:54:06 PM
MR. MARKS, continuing his answer, noted that targeted tax
credits are a tool not being used [in this bill], but that could
be. Targeted tax credits have advantages and disadvantages, and
the disadvantages were discussed today by the administration.
At low prices credits provide a lot of cash, and he has no doubt
[that under ACES] they have incentivized development, especially
at the new small fields. However, there is some concern that
they have been used for maintenance items rather than getting
new oil and that is why tax credits could be used for targeted
things that are conducive to producing oil rather than
maintenance; for example, air fields and dining halls are needed
to produce oil but they are not directly involved in producing.
An advantage of credits is that they provide an incentive,
especially since they are received on the front end and provide
a net present value boost as well; a company can actually
decrease its tax rate by investing. If concerned about cash
flow or cash flow at low prices, something could be set up where
credits cannot exceed "X percent" of gross value or "X percent"
of production tax value.
MR. MARKS said another advantage of a credit is that it
recognizes a company's actual economics and provides an
automatic offsetting mechanism, whereas the GVR/GRE and $5 per
barrel credit are one-size-fits-all. There is a broad spectrum
of costs on the North Slope - one development might be $10 a
barrel in capital cost and another might be upwards of $30. A
$5 per barrel credit means much different for a $10 cost than
for a $30 cost, and anything based on gross does not recognize
actual costs at all. Because a credit recognizes a company's
actual economics, a development having higher costs will receive
a higher credit and, automatically, the higher costs with the
higher credit will bring the company's taxes down more at a time
when more help is needed. With lower costs and a lower credit,
a company's tax will be brought down less at a time when not as
much help is needed. Thus, credits are a tool other than a
GVR/GRE. The main thing is to figure out what take to get and
get there; regardless of which mechanism is used for getting
there, it is the same amount of money.
8:57:40 PM
REPRESENTATIVE TARR noted a government take of 62 percent has
been suggested by the other two consultants as well Mr. Marks.
MR. MARKS referred to his [3/4/13] presentation to the Senate
Finance Committee to provide an answer. He explained Alaska is
not competing with every other jurisdiction in the world, and
slides 5-7 are his assessment of the jurisdictions comprising
Alaska's peer group because they have a risk/reward balance
similar to Alaska. He said it has been demonstrated that
producers will pay more where the reward is greater and less
where the reward is less. The peer group must be ascribed to
figure out what the competition is and the group he came up with
is similar to the one that Mr. Mayer came up with. In comparing
Alaska to its peer group at per barrel prices of $110, $70, and
$160, his judgment is that [a government take] of about 62
percent across all prices would be competitive. At current
prices of $110, the United Kingdom and North Dakota are at 62
percent. Other people could look at these numbers and land at a
different target, he allowed, but this is his judgment for what
would be a reasonable target.
8:59:55 PM
REPRESENTATIVE TARR surmised a big problem in the development of
ACES was that modeling was not done above the price of $90. In
regard to a government take of 62 percent, she asked whether
adjusting progressivity at higher prices, along with the
credits, could be a system that would work as a package.
MR. MARKS answered there are pros and cons to progressivity. A
pro is that progressivity means low take at low prices, not just
getting high take at high prices. So, a progressive system
protects the producer's interest at low prices and protects the
state's interest at high prices. The challenge is that it must
be balanced and not too aggressive. Because of the royalty it
is very hard to design something that protects the producer's
interest at low prices in a balanced way that gets upside
potential with progressivity. In looking at the competition,
only one or two other jurisdictions have progressivity. At a
price of $200, the state would be making lots of money whether
under progressivity or the proposed Senate bill. Progressivity
creates the impression that there may be some fiscal
instability. In many countries in the world where investors
perceive fiscal instability, they will actually prefer a
progressive system so they know what the deal is if prices go
up. "One could picture investors looking at their economics and
looking at what happens in the high price world and they say in
Alaska if it gets to $200 a barrel we do not think this will
hold so we do not know what the situation is, which is not
good." Progressivity only works if it is balanced on both the
high and low ends. It would be difficult to design something
that is truly balanced on the low side given how much the
royalty takes as a percentage of net at low prices.
9:03:27 PM
REPRESENTATIVE TARR posited that on the low price end it could
be controlled by not having the progressive feature apply until
a certain price.
MR. MARKS drew attention to slide 13 of his 3/4/13 presentation
to the Senate Finance Committee and explained that the royalty
is based on gross value. Because royalty is based on the gross,
it is the same whether the field's costs are high or low. For
example, at a price of $70, the royalty itself takes 100 percent
of the net value of the oil. This challenge at low price is why
designing a balanced progressive system may be difficult.
9:04:57 PM
CO-CHAIR SADDLER, returning to slide 5 of the aforementioned
presentation, inquired how static the government takes are for
Alaska's peer group.
MR. MARKS replied most of the jurisdictions are tax and royalty
systems; so, because of royalty, they are slightly regressive
like Alaska is. They have higher takes at lower prices and
lower takes at higher prices.
9:05:55 PM
CO-CHAIR SADDLER qualified that his question is not just about
royalty and re-stated the question by asking whether, in
general, the trend globally has been toward higher government
takes or has oscillated over the decades.
MR. MARKS responded that, generally, some jurisdictions will try
raising rates when prices spike. For example, Alberta, which is
mostly a royalty jurisdiction, raised its royalty significantly
in 2007. As opposed to Alaska where producers cannot move their
investments very much, many of the producers in Alberta reacted
by putting their rigs on their pickup trucks and driving to
British Columbia and Saskatchewan, so production plummeted in
Alberta. In 2010 Alberta dropped the royalty and it all came
back. In general, when prices go higher there is a slight
movement for higher takes, but the take seen now for many of
these jurisdictions is what was seen when oil was $60 a barrel.
9:07:30 PM
MR. MAYER added it varies enormously by the timeframe being
considered and the sorts of countries being considered. The
1960s had a period of substantial increases in government take
over a wide range of countries when a number of recently post-
colonial countries found themselves with low levels of royalty.
A number of particularly big national resource holders looked to
production sharing contracts that would give them a much bigger
share of the upside, rather than having regressive royalty
systems. A second price shock was the Arab oil embargo. If
this conversation were taking place five years ago, a number of
regimes could have been identified that in the previous decade
had raised government take, particularly as prices were starting
to rise. Probably the biggest thing in the last five years, as
a strong counter to that trend, is that high oil prices have
brought renewed production from a range of sources in the
Organisation for Economic Co-operation and Development (OECD)
that all have relatively speaking low levels of government take.
The logical competition for Alaska is no longer as it might have
been five to ten years ago - major producers with production
sharing contracts. It is now the Lower 48 and other places with
substantially lower levels of government take, and that has been
a very strong moderating influence in the opposite direction.
9:09:14 PM
CO-CHAIR SADDLER recalled DNR's earlier suggestion that it was
appropriate for operators on the North Slope to keep shuffling
through their PAs and to discard areas that were not producing
to keep them narrowly defined. He asked whether it is
reasonable to require old companies to go through their
participating agreements and filter out the areas they are not
actually producing from.
MR. MARKS answered he thinks it would be prudent administrative
practice on the part of DNR to weed out areas of PAs that are
not being produced. In further response, he said it would be
possible that DNR would want to offer those for lease to someone
else who might see something different there, given the state
makes money from lease sales.
CO-CHAIR SADDLER inquired whether there is a mechanism for the
state to offer area inside a unit that is a putative
participating area to lease to somebody else.
MR. MARKS replied the leases are surface acreage so he cannot
see how that would work.
CO-CHAIR SADDLER understood Mr. Marks to have said it would be
appropriate to release the non-producing area so it could be
leased to somebody else.
MR. MARKS responded correct, if the area was not being used. In
further response, he said the state will not be able to release
it around the land area so he cannot see how it could be done
within a unit because the same land would be involved.
9:11:33 PM
REPRESENTATIVE SEATON returned to slide 13 of Mr. Mark's 3/4/13
presentation to the Senate Finance Committee and addressed the
point made by Mr. Marks that at the price of $70 per barrel the
royalty would eat up all the profit. He inquired whether
producers were losing money during the years prior to 2005 when
prices were below $65 a barrel.
MR. MARKS answered the high operating and capital cost that he
used [for the slide] was on the order of $50 a barrel and he
doubts that back in those years anyone would have pursued
production at those costs. In further response, he said that,
today, $50 is the end spectrum with what might be possible with
viscous oil and other oil that is in remote areas. A producer
would not want to develop that oil if the price was $70, but
would need to be aware of what happens if it is.
9:13:07 PM
[CSSB 21(FIN) am(efd fld) was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES SB21 DNR & DOR Presentation 3.28.13.pdf |
HRES 3/28/2013 6:00:00 PM |
SB 21 |