Legislature(2001 - 2002)
03/18/2002 03:38 PM Senate RES
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HB 307-OIL/GAS EXPLORATION INCENTIVE CREDIT
CHAIRMAN TORGERSON announced HB 307 to be up for consideration.
4:20 p.m.
REPRESENTATIVE FATE, sponsor of HB 307, said it extends the
sunset provision of exploration incentive from 2004 to 2007 and
expands the incentive to other basins outside of Cook Inlet,
which the original bill provided. One reason this bill was
brought forward is because there is renewed interest in the
Nenana Basin, which has now been identified as a basin of high
potential for the exploration of gas. He explained that the
geological data goes to the Division of Oil and Gas to use for
future programs, either leasing or licensing.
CHAIRMAN TORGERSON asked where the expanding language was.
REPRESENTATIVE FATE explained that AS 41.09.010 defines Cook
Inlet specifically. This bill has no definition as to where this
takes place, meaning it could be throughout the entire state.
MR. MARK MYERS, Director, Division of Oil and Gas, DNR, said DNR
has taken a neutral position on this bill. The purpose of the
bill was to allow the state to acquire information or data in
areas where it had very little data. It allows the state to pay a
portion of that data to share risk. The concept was based on what
used to be called a cost well where companies would go out in an
area prior to a lease sale, drill a well strictly to get geologic
information (not necessarily where they think oil would be).
Companies would go together and share the cost. In 1994 that kind
of activity wasn't occurring very often, particularly in the
interior basins.
I think the thought process behind the original bill
was to have the state have incentive to pay for part of
the cost should a third party go out there and want to
drill a well and was extended also for geophysical
data, particularly seismic data. The credit was from a
pot of money of $30 million for the maximum extent of
the program up to $5 million per project. That project,
again, would have presumably to consist of wells or
seismic data. For seismic data it was line miles or so
many dollars per square mile. The program has never
been utilized. There have been two applications under
the program. One was for geochemical data or sampling
of surface rock data to try to figure out what the
source potential underneath the area was. That was on
the North Slope in an area where the state had a lot of
seismic data just south of Kuparuk. The director
determined at the time that the information really
wasn't that critical to the state since we had what we
thought was superior seismic data in the area. So, we
did not grant that application.
The second case was in the National Petroleum Reserve
Alaska where the state does not get the seismic data.
In that case the case granted 18% of the cost of
seismics to Anadarko. Anadarko, then, decided to
decline accepting that because of the state's ability
under this program to show that it had third parties.
So, they were convinced the confidentiality of the data
for the upcoming lease sales was so important they
didn't want to use the credit. So, twice it's been
applied for. Once it's been granted. It's never been
used.
Again, primarily the data could be from state lands,
but regulations require it to be from unleased state
acreage. So, if you own a lease in the area and it's on
state land and you want to apply for it, you're not
eligible to receive this credit.
The second area where it's on private or federally
owned lands, they can keep 25%. That credit is against
either royalties, taxes, bonus bids for rentals and is
transferable. So, it's real dollars for the credit. It
doesn't have to be that company's credit. They can sell
to a third party.
So, again, just to summarize. The program is designed
to encourage acquisition of data and it's stated that
the state either would receive, as in the case of wells
potentially drilled on Native lands and certainly the
seismic data of wells on private or privately owned
land, the state does not receive that data.
The second part of it, the state receives the data.
There are some cases where it encourages a lease sale
or exploration in an area or competition in an area,
but the state wants to have the ability to show that
confidential data. On wells that data is generally
limited to 25 months when the confidentiality is
released, but there is extended confidentiality that in
some cases can extend that confidentiality beyond that
primary term.
On seismic data that is shot on private lands, the
state is not entitled to give that data and, of course,
couldn't show that data under normal circumstances. So,
to summarize again, there are some very clear
advantages in certain conditions for the state I think
to contribute to the cost of exploration activities.
The other important element is discretionary by the
Commissioner of Natural Resources' decision prior to
the drilling of that well or shooting the seismic, the
commissioner can determine the value of the information
to the state and offer an appropriate amount not to
exceed $5 million, then, of the 50% on state owned
lands and 25% on privately owned lands. Thank you Mr.
Chairman.
CHAIRMAN TORGERSON asked Mr. MYERS to stay on line while he
talked to Mr. Dodson who was waiting to testify.
MR. JIM DODSON, Andex Resources, L.L.C., said Andex would like to
have the exploration incentive credits extended to seismic and
drilling. If they were available, they might shoot a much larger
program as it allows their dollars to go further and get more
data. "It eases the burden, those high risk exploratory dollars,
if the state could grant some exploratory credits to basically
help us to push the envelope…"
He supported extending the bill for three years to help encourage
exploration in areas that are not explored or underexplored at
this point.
CHAIRMAN TORGERSON asked if Andex has land under exploration that
is not state land.
MR. DODSON answered yes, it has lands under option 2.
CHAIRMAN TORGERSON informed him that no credits are available for
leases on state land.
MR. DODSON replied that Andex is seeking an exploration license,
not a lease on state lands.
CHAIRMAN TORGERSON asked if Andex would participate in the
shallow gas leasing sale.
MR. DODSON replied that it's not shallow gas leasing. Andex has
applied under the exploration license program for an all depth
license in the Nenana Basin.
CHAIRMAN TORGERSON asked if it's their interpretation that they
are eligible because it's not a lease.
MR. DODSON replied that is correct. He said that licensing
usually takes place in under-explored areas and so the
exploration incentive credit would be more applicable there than
in an area like Cook Inlet where leasing takes place.
SENATOR HALFORD said the existing statute has been on the books
for seven or eight years and no one has used it. He asked Mr.
Dodson if Andex Resources intends to make application within the
next year.
MR. DODSON answered, "Absolutely. We have sent a preliminary
letter to the Division of Oil and Gas, Department of Natural
Resources, outlining what our plans are.... We'd like to be
shooting seismic data in winter '03 - '04 in the Nenana Basin."
TAPE 02-10, SIDE B
CHAIRMAN TORGERSON asked Mr. Myers to brief the committee on the
number of potential companies that would qualify under the
exploration licensing part of this instead of the leasing part.
He asked if shallow gas leasing would get an exemption as well.
MR. MYERS replied that there are four exploration licenses - one
is issued at Copper River where Forrest is the primary operator.
They might apply if they want to go forward with seismic data. In
addition, there are two companies in the Susitna Basin that are
in the application process for about 500,000 acres each. DNR also
has the Andex proposal for an exploration license in the Nenana
Basin. On private lands, there's nothing to say that an applicant
couldn't apply for this program on any Native or federally owned
land. It's not geographically restricted.
Since the shallow gas lease program is noncompetitive because
companies buy leases, he didn't think a company would apply to
explore since another company could come in and file a lease.
Shallow gas or coal bed methane wells are relatively shallow and
cheap to drill. He pointed out, "They're quicker to actually
drill than an exploration well with the intent of production."
Realistically with the shallow gas leasing program,
there is no way the program could be used because
basically you acquire that non-competitive lease first
and then go ahead and drill your well. If not, you're
proving up potentially someone else's play.
MR. MYERS thought that many companies could use this bill, but
the state would be getting the information anyway. He thought the
intent in the end was to get enough interest for a competitive
sale when legislation was initially passed. The idea was that
exploration would be done and the state would follow through with
a conventional lease sale. The commissioner would have to look at
the value of the information in licensed areas to promote the
development of oil and gas.
CHAIRMAN TORGERSON asked if there had been any application for an
EIC under the exploration license program.
MR. MYERS said they had only granted one and are in the process
of granting three, "So, it's a relatively new program."
He explained under the licensing program they are required to do
a work commitment - so many dollars for a work commitment. The
work commitment doesn't necessarily include drilling wells or
shooting seismic. He remarked, "It's reasonable to say at this
point in time the program is early enough in its life that you
would not expect to have many applications under a license
scenario."
4:42 p.m.
CHAIRMAN TORGERSON said he was trying to understand why the state
would want to give this credit on state land. He said he can
understand it for off state land and the purpose for the state to
get data but he didn't understand why they would give the credit
on state land just because it has a different license
arrangement. He stated, "It seems like we're going backwards."
MR. MYERS responded:
I think you bring up a good point. Again, the program
was intended so the state could acquire the information
under a license agreement that it's going to get the
information anyway. We're not going to get the
information any sooner if a well or seismic data is
shot on state land. What we do do is give the ability
to show that well data before it's publicly released,
which is typically 25 months to show the seismic data.
The main reasons you would want to do that is to get
competition in an area. So if there is a competitive
lease sale in the area, you would bring more bidders to
the table or get more parties interested in the
exploration.
The question is what is the advantage in terms of
showing that data earlier on. As Mr. Dodson points out
the other advantage is to make the exploration dollars
go further. I think in some ways that's not the intent
of the original legislation, however. That puts the
commissioner in the position where he's going to have
to weigh all those factors in determining whether or
not they grant an exploration incentive credit as well
as your determination of intent with the legislature.
CHAIRMAN TORGERSON said there was no doubt that they needed to
work on that. He asked if the maximum credit was $5 million per
well.
MR. MYERS replied that the credit is $5 million per eligible
project and "project" is not defined. It could be wells or a
series of wells and it could certainly be seismic data.
CHAIRMAN TORGERSON asked if that was offset against corporate
taxes.
MR. MYERS replied, "Taxes, royalties, rentals or bonuses and
basically severance tax."
CHAIRMAN TORGERSON asked if that could be carried forward.
MR. MYERS replied that it can.
In reality what we've found - this is the second EIC
program. There was another program that involved the
competitive leasing instead of the lease term that an
EIC of so many dollars per foot is granted for an
exploration well. What we've found with that program,
companies either used it immediately or they sold it to
a third party who used it immediately, the North Slope
production typically. I believe the state granted about
$54 million or so in these credits in the other
program.
CHAIRMAN TORGERSON asked if he had a position on whether they
should extend this to land that the state already owns.
MR. MYERS replied that they are neutral on it.
Again, I think there are cases where you look at other
basins, areas not under license where the state wants
to get that information acquired. The only way to get
that information would be to contribute significantly
to it. This does provide a vehicle under the original
scenarios that were envisioned. I think that original
intent is good, certainly the ability to do that. But
it hasn't been used. We certainly want to do it. In an
area where it might for example is the NPRA where there
may be critical seismic data that because we have no
random understanding of whether that be [indisc.] that
the state badly needs to see that seismic data and is
willing to pay for it. Although companies are under no
condition to let us see it.
MR. MYERS said there may be cases on the North Slope where it
could be used, for instance a well being drilled on Native land
with adjoining state land in an upcoming lease sale.
One of Phillips' wells this winter, for example, in
Heavenly is being drilled on Arctic Slope Regional
Corporation land, which adjoins state land. I'm not
saying we would, but we might want to offer credit in
those kinds of circumstances. The other kinds of
circumstances are very frontier basins like Kolitna or
some area where there isn't sufficient data where the
state may say if a company is interested in going in
and acquiring baseline data, we're interested in
contributing to that cause, because we want to have
competitive sales and want to see more activity in that
area.
CHAIRMAN TORGERSON asked if Mr. Dodson's company had submitted a
request to them already.
MR. MYERS replied that they had submitted an informal request,
but the department needed very specific information because the
commissioner has to consider the value of that information to the
state and you can't unless you actually see the locations of the
wells, what they've drilled, what it would provide or where the
seismic series are. They can't in good faith do that until they
have a license issued..."
He said that Mr. Dodson is right that the bill might expire
before they can use it because of the timing of issuing the
license and drilling and operational permits. They are optimistic
to get things done by 2004, but there are cases where he might
not be willing to drill at that point.
A formal application will have to have more detail than
his preliminary letter, but he certainly has explored
with us the possibility. I will say one of the things
we are concerned about in the license areas, since the
license is built on a dollar commitment that is the
part of the license you will buy and the winner is the
one that puts in the largest dollar commitment for
work. We want those dollars in the EIC case to not
offset those original dollars that remain from the
commitment or the variable part of a bid. So, it would
be exploration work in addition to, say, a $2 to $3
million commitment to get the license. We don't want to
double dip on the same program. If it is used in a
license scenario and the commissioner deems it
appropriate, we would want to see it as additive, not
layered on as an additional incentive on top of the
exploration license, which is already…
CHAIRMAN TORGERSON said Mr. Myers hit on the two issues he is
concerned with. The first one is that it's already state land and
the state has never given credit to get data back off of state
land. He had heartburn with that. He said, "Even though by the
letter of the law we may be able to do it, I'm not sure that it's
good policy to start setting up." The other issue is if the
incentive bills working their way through the legislature do
pass, the state would end up paying folks to drill. He explained,
"I'd like a better handle on all of the things that we may end up
passing on these incentive bills including what's already on the
books."
4:45 p.m.
SENATOR HALFORD said the fiscal note in 2004 says zero to $30
million, but existing law goes into 2004. He wanted to know if
the fiscal note is accurate.
MR. MYERS explained that DNR made it that way because $30 million
was the maximum amount that could be used. It could be an error
on his part if it's before July 1, 2004. The bill doesn't change
the total amount of credits for the program.
SENATOR HALFORD said he wanted to see exactly how this program
would stack with any other incentive program in the state.
MR. MYERS replied that he would start by explaining the
exploration license itself:
An exploration license - basically the state does not
go into a lease mode until the company is ready to or
until the license expires. So, a typical exploration
license would be a 5 to 10 year period. The state
foregoes what would be a competitive bonus bid it would
get for the acreage. The license could be up to 500,000
acres. It also foregoes a period of license the typical
rentals the state would receive, which in the case of a
500,000 acre license, the max, and the companies
typically go for that or near that number, and you went
ahead and granted for a seven year period, it would be
worth about $10 million differential than if the state
had gotten a minimum bonus bid.
It's substantial value to the party. The party then at
the end of the license has committed a work permit that
is so many dollars. Typically, we're seeing $2 to $3
million for a work permit for a license. That's not
money the state receives. That's money that's spent by
the company on legitimate exploration activity.
SENATOR HALFORD asked if that was covered in this incentive.
MR. MYERS replied that wasn't covered in this incentive. It is
built into the exploration licensing, "So, this incentive has the
potential, if the state were to grant it in a licensed area, of
overlaying on top of that."
He explained if six wells, an extreme case, were drilled and each
determined a project in a given license area, they would be
granted the maximum of $10 million. The state could give in that
licensed area $30 million worth of credits.
In theory, those $30 million could offset some of the
costs that were guaranteed in the exploration license,
because remember, they are guaranteeing a work
commitment. There is the potential for these to
overlay, but again, this program is discretionary and I
don't think the commissioner would take a position that
would allow there to be that overlay. But it is
theoretically possible that the dollars spent in the
exploration license could be offset - at least half of
those dollars offset - by the EIC.
Other incentives, then, you could do royalty reduction,
which of course, if they were to continue on for a
successful exploration program and determine that they
couldn't commercially develop at the current royalty
rate, the state could grant a royalty reduction down to
about 3% under current law.
The severance tax is based of course on the
productivity factor for gas fields and low production
or for oil - low production. That could be severance
tax as low as zero, but it's probably in most
commercial cases around 5 to 7% severance tax on top of
that. In addition, if the licensed area were in the
Cook Inlet area, you could be eligible for a discovery
royalty, which would give you a royalty rate of 5% from
production for the first 10 years from the date of the
discovery. So, those are the main overlays that I am
aware of in our programs.
He didn't have that much concern over this particular incentive
credit, because of the discretionary nature.
CHAIRMAN TORGERSON asked if there is a cap on how many acres one
could get under the exploration license.
MR. MYERS replied that 500,000 acres is the cap per license.
CHAIRMAN TORGERSON asked if a company could hold more than one
license.
MR. MYERS replied yes; a company could have up to 2 million
acres.
CHAIRMAN TORGERSON asked what the rental fee per acre is under
this bill.
MR. MYERS replied that there is no rental fee. He explained:
There is a $1 per acre initial application fee. There
is no other fee other than if they convert if they are
successful at the end of the license period and they
want to convert to leases. They would then convert to a
standard 12.5% lease and then they would pay the normal
rentals, but the rentals will start at $3 per acre,
rather than $1.
CHAIRMAN TORGERSON asked if they can only explore from this
license and not produce.
MR. MYERS said they could theoretically, but they wouldn't get
the royalties for it. But from a practical standpoint to get the
production credit, they would have to convert to a lease prior to
commercial production.
CHAIRMAN TORGERSON asked what will happen if they go to
production under the exploration license.
MR. MYERS explained, "They don't have a right to the oil and gas
under a license until they convert it to a lease."
SENATOR TAYLOR said he didn't mention the ELF and asked if that
only applies to oil.
CHAIRMAN TORGERSON replied that it applies to gas, also.
MR. MYERS explained that it depends on the rate of production,
but they would expect in a commercial scenario, the wells would
have to have high enough rates in this basin to be commercial in
the Fairbanks market. It would probably pay between 5 to 10%
severance tax.
CHAIRMAN TORGERSON asked if it was 10% maximum on gas.
MR. MYERS said that was right.
CHAIRMAN TORGERSON added that the state gives the first 3,000 MCF
for free, so, it's effectively .8%. He said they needed time to
figure out how all this was stacking on top of each other. He
asked Mr. Myers if he could put a flow chart together of how this
works.
4:55 p.m.
MR. DODSON said it was important to point out that exploration
licenses can only be applied for areas outside of the known
producing regions in Alaska.
CHAIRMAN TORGERSON said:
My biggest heartburn is that this program was set up to
pay for data off of state land. I'm not too sure this
isn't oversight that we don't get the data as part of
the license agreement or the lease or something. It's
almost mixing oranges and apples. It's like a loophole
in the law that lets you take credit for us to get the
data. If you want to change the scope of the law,
that's a different subject entirely than what we have
before us. It seems counterproductive for us pay for
our own data off our own land.
REPRESENTATIVE FATE asked if it costs us to get data off our
state land and if we wouldn't be able to get it otherwise.
CHAIRMAN TORGERSON said that right now we get the data off the
state land. "This program was initially credited to get data off
of non state land."
MR. MYERS added, "There are cases where the state, I think, and
the intent when this bill was created, [indisc.] to pay for data
on leased state land where it could show that data physically to
third parties."
He said they also use that data in managing state lands. If they
are trying to evaluate that land for its potential on a lease
sale, for example, it might be valuable to show that data to
other companies and potentially other agencies. He said the
original intent of this program was not to overlap with the
normal areas like Cook Inlet. He said getting the baseline
information in the unleased areas would be important enough to
the state that it might want to contribute part of the cost. The
state can get the data, but it can't show it to third parties.
They might want to promote a lease sale and it would help to get
the data out there right away.
CHAIRMAN TORGERSON said the data would eventually be ours, but
this is just an accelerated time schedule.
MR. MYERS replied that the state gets their data at the same time
either way, but it allows the state to show that data to a third
party prior to its being released.
In all cases on wells drilled on state land there's a
25 month period of confidentiality, which can be
extended under certain confidentiality circumstances
under statute and regulation…For seismic data we get
the right again by permit to get the data. That would
not be accelerated, but we would be allowed to show
that data to a third party. Seismic data is never
released by DNR to third parties.
SENATOR HALFORD said, "But the data we're talking about is not
fully interpreted. That still is proprietary to the industry."
MR. MYERS replied the data would be the geophysical data from the
well. It really depends on what the state is paying for in the
data. The state is not going to give a third party its
interpretation of the data, but it could if it wanted to.
He clarified that an EIC doesn't allow the state to release the
data; it allows them to show the data. "So a company can come
into DNR and look physically at the data, but they can't take it
with them."
There were no further comments and CHAIRMAN TORGERSON adjourned
the meeting at 5:06 p.m.
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