03/15/2005 05:00 PM House OIL & GAS
| Audio | Topic |
|---|---|
| Start | |
| HB197 | |
| HB142 | |
| HB71 | |
| Adjourn |
+ teleconferenced
= bill was previously heard/scheduled
| *+ | HB 197 | TELECONFERENCED | |
| *+ | HB 142 | TELECONFERENCED | |
| += | HB 71 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
March 15, 2005
5:03 p.m.
MEMBERS PRESENT
Representative Vic Kohring, Chair
Representative Nancy Dahlstrom
Representative Norman Rokeberg
Representative Ralph Samuels
Representative Berta Gardner
Representative Beth Kerttula
MEMBERS ABSENT
Representative Lesil McGuire
COMMITTEE CALENDAR
HOUSE BILL NO. 197
"An Act exempting certain natural gas exploration and production
facilities from oil discharge prevention and contingency plans
and proof of financial responsibility, and amending the powers
and duties of the Alaska Oil and Gas Conservation Commission
with respect to those plans; and providing for an effective
date."
- MOVED HB 197 OUT OF COMMITTEE
HOUSE BILL NO. 142
"An Act relating to regulation of underground injection under
the federal Safe Drinking Water Act; and providing for an
effective date."
- MOVED HB 142 OUT OF COMMITTEE
HOUSE BILL NO. 71
"An Act relating to a credit for certain exploration expenses
against oil and gas properties production taxes on oil and gas
produced from a lease or property in the state; relating to the
deadline for certain exploration expenditures used as credits
against production tax on oil and gas produced from a lease or
property in the Alaska Peninsula competitive oil and gas
areawide lease sale area after July 1, 2004; and providing for
an effective date."
- MOVED CSHB 71(O&G) OUT OF COMMITTEE
PREVIOUS COMMITTEE ACTION
BILL: HB 71
SHORT TITLE: AK PENINSULA OIL & GAS LEASE SALE; TAXES
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
01/12/05 (H) READ THE FIRST TIME - REFERRALS
01/12/05 (H) W&M, O&G, RES, FIN
02/11/05 (H) W&M AT 8:30 AM CAPITOL 106
02/11/05 (H) Moved CSHB 71(O&G) Out of Committee
02/11/05 (H) MINUTE(W&M)
02/14/05 (H) W&M RPT CS(W&M) NT 3DP 1AM
02/14/05 (H) DP: MOSES, GRUENBERG, WEYHRAUCH;
02/14/05 (H) AM: WILSON
02/17/05 (H) O&G AT 5:00 PM CAPITOL 124
02/17/05 (H) Heard & Held
02/17/05 (H) MINUTE(O&G)
03/15/05 (H) O&G AT 5:00 PM CAPITOL 124
BILL: HB 142
SHORT TITLE: OIL & GAS: REG. OF UNDERGROUND INJECTION
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
02/14/05 (H) READ THE FIRST TIME - REFERRALS
02/14/05 (H) O&G, RES, FIN
03/15/05 (H) O&G AT 5:00 PM CAPITOL 124
BILL: HB 197
SHORT TITLE: OIL SPILL EXEMPTIONS FOR GAS WELLS
SPONSOR(s): OIL & GAS
03/03/05 (H) READ THE FIRST TIME - REFERRALS
03/03/05 (H) O&G, RES
03/15/05 (H) O&G AT 5:00 PM CAPITOL 124
WITNESS REGISTER
DANIEL SEAMOUNT, Commissioner
Alaska Oil and Gas Conservation Commission
Alaska Department of Administration
Anchorage, Alaska
POSITION STATEMENT: Testified in support of HB 197 and
presented HB 142 to the committee.
LARRY DIETRICK, Director
Division of Spill Prevention and Response
Alaska Department of Environmental Conservation (ADEC)
Juneau, Alaska
POSITION STATEMENT: Testified in support of HB 197.
MARILYN CROCKETT, Deputy Director
Alaska Oil and Gas Association (AOGA)
Anchorage, Alaska
POSITION STATEMENT: Testified in support of HB 197.
BENJAMIN BROWN, Legislative Liaison
Office of the Commissioner
Alaska Department of Environmental Conservation (ADEC)
Juneau, Alaska
POSITION STATEMENT: Testified in support of HB 197.
MARK MYERS, Director
Central Office
Division of Oil and Gas
Alaska Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Presented HB 71 and answered questions.
DAN DICKINSON, Director
Central Office
Tax Division
Department of Revenue
Anchorage, Alaska
POSITION STATEMENT: Answered questions regarding HB 71.
ACTION NARRATIVE
CHAIR VIC KOHRING called the House Special Committee on Oil and
Gas meeting to order at 5:03:18 PM. Representatives Kohring,
Samuels, and Dahlstrom were present at the call to order.
Representatives Rokeberg, Gardner, and Kerttula arrived as the
meeting was in progress.
HB 197-OIL SPILL EXEMPTIONS FOR GAS WELLS
5:04:20 PM
CHAIR KOHRING announced that the first order of business would
be HOUSE BILL NO. 197, "An Act exempting certain natural gas
exploration and production facilities from oil discharge
prevention and contingency plans and proof of financial
responsibility, and amending the powers and duties of the Alaska
Oil and Gas Conservation Commission with respect to those plans;
and providing for an effective date."
5:04:34 PM
CHAIR KOHRING, as chair of the House Special Committee on Oil
and Gas, sponsor of HB 197, explained that the bill addressed an
unintended consequence that resulted from last year's House Bill
531:
[That was the bill regarding] the coal bed methane
issue where we put into place some pretty restrictive
requirements. ... The bill went a little bit too far
in terms of requiring C-Plans, which is the term
referring to oil spill contingency plans, and it also
requires proving financial responsibility for all
kinds of gas wells, whether there are any threats of
oil spills or not. And what we'd like to do is to put
in place an exemption to the existing state law for
gas wells where there is no threat of any ... oil
seepage through the formations when the gas wells are
drilled.... [Alaska Oil and Gas Conservation
Commission (AOGCC)] will determine if the formations
will potentially have oil where the gas is being
drilled, and if they determine that there is oil that
could potentially work its way through the formations
and come out and spill on the ground and cause
environmental problems, then they would not allow the
exemptions. So it's entirely dependant on what their
analysis and evaluation of the formations in the
ground are. So what's we're essentially doing with
this legislation; [HB] 197 is clarifying the authority
that the state has by amending the existing law
dealing with oil discharge prevention.
5:06:16 PM
CHAIR KOHRING continued:
With the current law that we have in place, it
actually is going to make it harder for smaller
companies to operate because, with the C-Plan
requirements, it's going to add to the extra cost ...
associated with gas exploration. So we could actually
see less gas drilling and exploration if they're
subject to these C-Plans and ... proving financial
responsibility.
5:07:31 PM
DANIEL SEAMOUNT, Commissioner, Alaska Oil and Gas Conservation
Commission (AOGCC), Alaska Department of Administration, noted
that the AOGCC had submitted a letter of support for HB 197.
Regarding the bill, he commented:
It mends the laws regarding oil discharge prevention
and contingency plans, and also proof of financial
responsibility, otherwise known as C-Plans. It allows
better use of the geologic information and expertise
that the AOGCC has in understanding the need for such
plans. Under current law, the C-Plan is required for
wells drilled to explore for or produce oil.... The
C-Plan ... was not in the past required for wells
drilled to produce only gas, however ... [House Bill
531] passed in 2004 kind of had an anti-loophole. The
only wells that could be technically exempted were
basically only coal bed methane wells, and other gas
wells that were not nonconventional ... did not
technically have the ability to be exempted from a C-
Plan. So we don't believe that that was the ...
legislators' intent ... last year, and it resulted in
a mismatch between the current scope of the C-Plan
exemption and the facts of Alaska's geology. ... And
those facts are: drilling for gas in many areas,
whether it's nonconventional or not, carries virtually
no risk of an oil spill. There are thick geologic
sections containing both conventional and
nonconventional gas reservoirs, but they have very
little potential for the existence of zones capable of
flowing liquid hydrocarbons. A C-Plan requirement
only adds costs and delay to gas exploration with no
increased protection to the environment. We believe
HB 197 corrects the inadequacies in current law by
providing for a case-by-case geologic evaluation of
wells drilled to explore for gas. ... Wells drilled to
explore for gas would qualify for a C-Plan exemption
only if the AOGCC determines the evidence demonstrates
with reasonable certainty that the well will not
penetrate a formation capable of flowing any kinds of
liquid hydrocarbons to the ground surface. So the
approach of HB 197 is to base C-Plan exemption
decisions on applications of the AOGCC's geologic
expertise....
5:12:54 PM
REPRESENTATIVE GARDNER commented that the Alaska Department of
Environmental Conservation (ADEC) "already has authority to do
this on a case-by-case basis, and this bill simply clarifies the
circumstances under which they can do this."
5:13:19 PM
REPRESENTATIVE KERTTULA asked if the bill would apply to
conventional as well as nonconventional gas.
MR. SEAMOUNT responded that it would,.but noted, "Only in the
case where we have determined that geologically there is ...
virtually no risk of hitting zones that are capable of flowing
oil to the surface."
REPRESENTATIVE KERTTULA asked if currently all conventional
wells are required to have C-Plans.
MR. SEAMOUNT replied that wells drilled before 2004 were
exempted, and then he deferred to ADEC.
5:14:35 PM
LARRY DIETRICK, Director, Division of Spill Prevention and
Response, Alaska Department of Environmental Conservation
(ADEC), stated that the department supports the bill. He
commented that ADEC has historically relied on the AOGCC's
expertise regarding the North Slope.
REPRESENTATIVE KERTTULA asked if ADEC had intended to raise the
financial responsibility level from $25,000 to $1 million.
MR. DIETRICK replied that the intent was that if the
determination was made that there was no oil that would float to
the surface in a particular reservoir, then both the financial
responsibility and the C-Plan requirements would be voided.
5:16:16 PM
REPRESENTATIVE KERTTULA said, "If they're required to do a C-
Plan, then they're under the $1 million level, even if it's
nonconventional. Am I right?"
MR. DIETRICK replied affirmatively.
REPRESENTATIVE KERTTULA continued, "So under the current
situation, current law, which created this glitch, for
nonconventional, they were under the ... $25,000 per incident.
Is that how it was working with financial responsibility?"
MR. DIETRICK answered that this was correct.
REPRESENTATIVE KERTTULA noted, "The only gap now ... is that,
for the wells that are exempted, what happens if ... we turn out
to be wrong, and there actually is an oil spill. Is there any
way to go back, or any financial responsibility required at all?
MR. DIETRICK responded, "We rely on the AOGCC determination then
of whether or not the potential exists. ... And so therefore a
contingency plan and financial responsibility would not be
required up front." He said that he could not think of any case
in the past where AOGCC was wrong in a case like this. He
noted, "I think the likelihood of that occurring [is] very
remote, so there are no specific provisions for that right now."
5:19:04 PM
CHAIR KOHRING asked if there was anyone in Juneau or on
teleconference who wished to testify. There was no one.
REPRESENTATIVE KERTTULA asked if other facilities or pipelines
have to have financial responsibility.
MR. DIETRICK responded that the exemption would not apply to any
other category of facilities that are regulated and required to
have financial responsibility or C-Plan, including nontank
vessels, tank vessels, railroad, pipelines, and oil terminal
facilities. He said, "It's only for the wells."
5:21:14 PM
REPRESENTATIVE DAHLSTROM moved to report HB 197 out of committee
with individual recommendations and the accompanying fiscal
notes. There being no objection, HB 197 was reported from the
House Special Committee on Oil and Gas.
HB 142-OIL & GAS: REG. OF UNDERGROUND INJECTION
5:21:44 PM
CHAIR KOHRING announced that the next order of business would be
HOUSE BILL NO. 142, "An Act relating to regulation of
underground injection under the federal Safe Drinking Water Act;
and providing for an effective date."
5:22:57 PM
DANIEL SEAMOUNT, Commissioner, Alaska Oil and Gas Conservation
Commission (AOGCC), Alaska Department of Administration,
introduced HB 142 on behalf of the Alaska Department of
Administration. He directed attention to "slides" printed in a
handout available in the committee packet. He began by giving a
brief outline of his presentation.
5:26:18 PM
MR. SEAMOUNT turned to slide 3, containing the AOGCC mandate:
AOGCC regulates operations affecting subsurface oil
and gas resources, ensures the reliability of oil and
gas flow measurements, and ensures that underground
sources of drinking water are protected.
MR. SEAMOUNT explained that the AOGCC mainly oversees subsurface
oil and gas activities, but also makes sure that the meters are
accurate.
5:27:03 PM
MR. SEAMOUNT turned to slide 4, which defines the AOGCC
underground injection program. He explained that the AOGCC
regulates Class II wells and has primacy for implementing the
federal Underground Injection Control (UIC) Program for purposes
of enhanced oil recovery and for the most environmentally sound
disposal of oil field waste. He said:
The proper underground injection of material to
enhance oil recovery has resulted in billions of
dollars in revenue to the State of Alaska and
industry. That's the enhanced oil recovery Class II
wells, or Class II-R. Also, there are some Class II-
D, which are disposal wells that dispose of ... oil-
filled waste. ... The best place to put oil-filled
waste is deep underground where it's not going to have
the potential to spill on the surface.
5:28:12 PM
MR. SEAMOUNT continued:
Slide 5 is just a statement of the ... statute as it
is right now that gives us the power to oversee ...
Class II disposal wells, and also the protection of
underground sources of drinking water. The next slide
shows what change [HB 142 would make] to that part of
the statute. And that would be in Section 1, AS
31.05.030(h).... It gives us oversight for the
control of underground injection related to the
recovery and production of oil and gas wells, and ...
it is adding, "and the control of underground
injection in Class I wells as defined in [40 C.F.R.
144.6, as amended]."
5:29:15 PM
MR. SEAMOUNT turned to slide 7 and explained:
What we have now are two agencies performing the same
job; one is protecting a nonexistent resource on the
North Slope, and that is an underground source of
fresh water. It's been determined that there are no
underground sources of fresh water. And that's one of
the things that Class I wells [are] supposed to do.
... [There are] Class I wells up there that are
protecting something that doesn't exist. And this
results in onerous and costly requirements on industry
and the State of Alaska. ... [Through this bill,
AOGCC] would obtain control through primacy or ...
having [the U.S. Environmental Protection Agency
(EPA)] agree that we really don't need Class I wells,
so we would just continue the Class II oversight, and
say that ... everything on the North Slope was oil and
gas waste, so we could do it through putting it down a
Class II well.
5:30:29 PM
MR. SEAMOUNT opined that the five classes of wells under the
Safe Drinking Water Act are very confusing; there are different
interpretations about what waste can go down what kind of well,
and sometimes a Class I well is situated next to a Class II
well. He gave a brief overview of what each of the well types
were for. In Alaska, there are 1,155 Class II wells which are
overseen by the AOGCC, he said. There are only 7 Class I
wells, all on the North Slope, and there are more than 3,000
Class V wells.
5:33:47 PM
MR. SEAMOUNT turned to slide 11 and remarked:
We believe that it's a waste of taxpayer and industry
time and money to have ... two agencies overseeing two
very similar well programs. There's confusion by
operators over what waste is allowed to be disposed in
each class of well.... [But] all wastes on the North
Slope are directly associated with hydrocarbon
production, and there are some regions in the EPA that
say that if it's [a waste] associated with oil and gas
production, ... then it ought to go down a Class II
well, not a Class I. ... Much time and energy is
expended by the two agencies and industry ... in
tracking what waste goes where. There's a huge amount
of time and energy that could be allocated in other
places. ... Often the same fluids are injected into
the same disposal zones in different wells that are
sitting next to each other. The two wells are
constructed virtually the same. And AOGCC works on
these Class I wells anyway by performing a lot of work
advising EPA on their program, and our five inspectors
... inspect the Class I wells....
5:36:03 PM
MR. SEAMOUNT turned to slide 12 and continued:
The Class I program ... protects a nonexisting
resource: fresh water. It's an inefficient ... permit
process. EPA approvals are generally much slower than
AOGCC, though ... in the recent past, they're getting
better at that. ... They tend to have onerous and
costly stipulations considering well integrity. EPA
has no onsite field inspectors. They regulation only
seven out of 1,162 UIC wells and ... it would appear
that it would be costly and remote for EPA to be
running a program out of Seattle for only seven wells.
There is a temptation for industry, from all this
confusion about what to do with these different types
of wastes, ... to transport waste long distance for
surface displacement or disposal in a redundant
disposal well, and that leads to a ... further risk of
surface spills.
5:37:23 PM
MR. SEAMOUNT noted that slide 13 was a cross section that shows
the similarity between Class I wells and Class II wells. Then
he moved to slide 14, which he said highlighted the confusion
about fluids eligible for a Class II well. He said that the
Region 10 EPA position was that only fluids that have been down
hole can go into a Class II well, or the waste has to be
generated by contact with an oil and gas production stream
during the removal of produced water or other contaminants. He
described a few issues that tend to cause confusion regarding
which type of well is appropriate for which type of waste.
5:39:31 PM
REPRESENTATIVE GARDNER asked what "USDW" and "SDWA" stand for.
MR. SEAMOUNT replied that USDW stands for underground source of
drinking water, such as an aquifer. He noted, "Where oil is
produced on the North Slope, there are [no USDWs]. The ground
is frozen and none of that water is moveable." SDWA stands for
Safe Drinking Water Act.
MR. SEAMOUNT turned to slide 15 and said:
One of engineers did an analysis of the differences in
cost between a Class I and a Class II well, and
historically a Class I well cost $2.50 barrel of fluid
disposed as opposed to a Class II well, which is
$1.50.
5:41:10 PM
MR. SEAMOUNT explained that slide 16 is a list of options and
solutions. He said:
We've got three options. The first option, business
as usual, would be if HB 142 is not passed, and the
... silver lining to that is that I wouldn't have to
do very much work ... on this task force; no effort
would be expended to change the status quo. But if we
don't do anything, we're going to continue to have
confusion among industry, cost to the taxpayer and
industry. There's going to be redundancies between
the two agencies. There'll be inefficient approval
processes. And it is not industry's preference
because ... of the costs associated with it.
MR. SEAMOUNT continued:
[Slide 17] shows the two [other] options. The first
option would be probably the easiest and that would be
... somehow for AOGCC to obtain primacy over the EPAs
Class I program. This would lead ... to less industry
confusion; they'd be dealing with one agency, and it
would save everybody money. The second option would
be to just go to having one class of well for all
disposal, and that would be a Class II well, overseen
by the AOGCC. ... That would need HB 142 to be passed
also, and it also [would] need a ruling by the EPA.
It would take a little bit more work, but ... that's
the best option possible. That would result in less
energy used for waste determination and tracking, less
cost, less ... industry confusion ..., and it saves
everybody money.
5:43:22 PM
REPRESENTATIVE SAMUELS asked for clarification about the
mentioned task force.
MR. SEAMOUNT replied, "We have been talking to ... EPA about
building this task force. We're ready to put it in place, and
that would be one of the actions we would take."
REPRESENTATIVE SAMUELS asked if AOGCC would take any other
actions.
MR. SEAMOUNT answered, "We are looking at ... writing some
regulations in the event that we do reach an agreement with
EPA."
5:44:16 PM
REPRESENTATIVE KERTTULA asked if permafrost would be considered
an underground fresh water source, and if so, if this was the
reason that EPA does not consider all North Slope wells to be
Class II.
MR. SEAMOUNT responded that the EPA definition of fresh water is
water that is flowable and in quantities that is usable,
therefore permafrost is not considered fresh water. He said:
The people at EPA that we talked to are in agreement;
they would like us to take the program. Their problem
is they don't see in the Safe Drinking Water Act where
it's allowed. ... Class II primacy is allowed, [but]
they don't see where Class I primacy is allowed. They
have a legally, technical problem with it. ... We have
been talking to other states about whether they have
partial primacy, and we found three states: California
... has partial primacy over a certain set of Class V
disposal wells, which involve geothermal wells. And
then New Mexico and Illinois have stated that they
have some sort of partial primacy.
5:46:47 PM
REPRESENTATIVE GARDNER pointed out that if the bill passed
through the legislature exactly as written, "we're only partway
to where you want to be, and we still then need to get something
worked out with the EPA, and that's not in our hands, is that
correct?"
MR. SEAMOUNT answered affirmatively.
5:47:13 PM
REPRESENTATIVE ROKEBERG asked for further distinction between
Class I and Class II wells.
MR. SEAMOUNT replied:
The whole issue ... is sort of a fight between whether
confinement of the fluid is most important, or legally
the type of fluids, where it's come from, is most
important. And that's a dynamic situation. It's been
changing gradually through the years. ... We tend to
take the position that if we can confine the fluids
underground, the type of fluid doesn't really matter
that much. Whereas EPA tends to think that they have
to go by the letter of the law, and if they interpret
that this fluid came from this location ... then it's
got to go down this kind of well, and another one, it
goes down another type of well. ... They tend to want
to see more of Class I wells.
5:49:09 PM
REPRESENTATIVE ROKEBERG noted that in producing some types of
petroleum, some deadly toxins are produced. He asked,
"Seemingly from this definition, everything that comes out of a
producing well would be a Class II well, even if it was
poisonous, is that correct?"
MR. SEAMOUNT replied that this was probably correct and
commented, "We haven't had to deal with that in Alaska yet,
because we generally have pretty clean oil; very low SO2
concentrations."
REPRESENTATIVE ROKEBERG asked, "But what if you did have an SO2
concentration; would that be a one or a two?"
MR. SEAMOUNT replied, "I believe that would be a Class II
because it came from down hole."
REPRESENTATIVE ROKEBERG asked why it was more expensive for
Class I well.
MR. SEAMOUNT explained that some of the extra cost is due to
reporting, and a lot of it is testing. He added that in the
past there has been a requirement to cement Class I wells all
the way to the surface through its deep casing, which many times
requires extra holes shot in the casing and more attempts to get
the cement to the surface. He said that the AOGCC believes that
there are operational problems and environmental risks
associated with cementing casing all the way to the surface. He
noted that if the cement is too high it will become too heavy
"and you could lose it to the formation." He explained that a
Class I well could be between 2,000-9,000 feet deep on the North
Slope, and the casing depths range to over 20,000 feet. He
said, "A typical Prudhoe Bay well is about 9,800 feet true
vertical depth, but with extended reach well bores, they can go
to 13,000 feet or more. ... They generally case all the way."
5:54:36 PM
MARILYN CROCKETT, Deputy Director, Alaska Oil and Gas
Association (AOGA) explained that AOGA is a private, nonprofit
trade association whose members comprise the majority of the oil
and gas operations that occur in the state. She testified in
support of HB 197. She remarked that the AOGCC is very highly
regarded for its management of the Class II well program. She
continued, "The [AOGCC] is the one state agency that has the
specific technical expertise needed when evaluating issues
related to the subsurface and the structural integrity of
wells."
5:56:51 PM
CHAIR KOHRING asked if the EPA is willing to cede control to
allow the state to have primacy.
MS. CROCKETT replied that the Region 10 EPA administrator had
told the AOGCC that if it is legal for the EPA to transfer this
program to the state, he would support doing so. She noted,
"The rub seems to be in the attorneys reaching the conclusion
that in fact it is possible to carve off this program as they
have done in three other states for three other programs."
5:58:22 PM
REPRESENTATIVE KERTTULA asked Mr. Seamount, "Once you have
primacy, what kind of latitude do you have to go outside the EPA
regulations?"
MR. SEAMOUNT replied that the AOGCC would have to reach a
compromise with the EPA on that issue; the EPA would still be
the overseer.
5:59:04 PM
BENJAMIN BROWN, Legislative Liaison, Office of the Commissioner,
Alaska Department of Environmental Conservation (ADEC) stated
that no concerns about the bill were raised by the commissioner
and the directors of the Division of Spill Prevention and
Response, the Division of Water, and the Division of
Environmental Health. He commented, "We feel at [ADEC] that
[AOGCC is] in a very good position to obtain primacy from the
EPA over this."
REPRESENTATIVE KERTTULA asked if this bill would affect ADEC
operations.
MR. BROWN replied that it would not.
6:00:59 PM
REPRESENTATIVE DAHLSTROM moved to report HB 142 out of committee
with individual recommendations and the accompanying fiscal
notes. There being no objection, HB 142 was reported from the
House Special Committee on Oil and Gas.
HB 71-AK PENINSULA OIL & GAS LEASE SALE; TAXES
6:01:33 PM
CHAIR KOHRING announced that the final order of business would
be HOUSE BILL NO. 71, "An Act relating to a credit for certain
exploration expenses against oil and gas properties production
taxes on oil and gas produced from a lease or property in the
state; relating to the deadline for certain exploration
expenditures used as credits against production tax on oil and
gas produced from a lease or property in the Alaska Peninsula
competitive oil and gas areawide lease sale area after July 1,
2004; and providing for an effective date."
[Before the committee was CSHB 71(W&M).]
6:02:06 PM
MARK MYERS, Director, Central Office, Division of Oil and Gas,
Alaska Department of Natural Resources (DNR), presented HB 71 to
the committee. He explained:
[The bill would] extend a tax credit for exploration
wells that was approved under AS 43.55.025 for a
period of time, specifically to the Alaska Peninsula
area, and it would be the onshore and state waters
portion of the Alaska Peninsula only. So it extends
it from the 2007 sunset of this current tax credit to
2010. And essentially what the bill does is it allows
a 20-40 percent tax credit for exploration wells. If
they're less than 25 miles away from an oil and gas
unit that existed at the time of the bill passage ...
and three miles away from another well or more, they
would get a 20 percent credit against severance taxes.
... If it's three miles away from other wells and more
than 25 miles away from another oil and gas unit, [it
would] get up to a 40 percent credit. Exploration
seismic, shot outside of an existing unit area, would
be eligible for a 40 percent tax credit. So those are
the conditions currently under AS 43.55.025, and the
thought is to extend those specifically for a limited
period of time for the Alaska Peninsula only ... up
through 2010.
MR. MYERS continued:
We believe these credits are important to the Alaska
Peninsula because we're starting out with a basin with
no infrastructure, and basically no modern well data
or seismic data. So this credit would be a
significant encouragement, and [by] having it in place
before the Alaska Peninsula lease sale, we believe,
oil companies would bid increased amount of dollars at
the sale. ... There really is no modern data.... So
it's really important for exploration success out here
to get modern seismic and modern well data shot. So
this credit would greatly encourage that by limiting
it to a five year period after the sale; they would
have to ... do the exploration work early in the
primary terms of the leases, and we believe that would
accelerate the exploration process.
6:05:01 PM
MR. MYERS noted that if the bill were not passed, the credit
would be of very little use; by the time a company acquired a
lease and set a program up, it would basically have one season
before the credit ran out in 2007.
REPRESENTATIVE KERTTULA asked if a company could actually end up
with an 80 percent credit.
MR. MYERS responded that the credits are not additive and would
be limited to a maximum of 40 percent credit.
6:07:21 PM
REPRESENTATIVE GARDNER asked what the mechanism is by which the
state receives data from exploration companies.
MR. MYERS replied:
One of the purposes of the legislation was recognizing
that this particular legislation applied on state,
federal, and Native lands, and there's two components
for getting the data. One is ..., under current law,
the state, for management purposes, only gets the data
on state lands. And, for instance, the data on
[National Petroleum Reserve-Alaska (NPRA)] it doesn't
get until those wells are publicly released, which is
normally after 25 months.... So we would get the data
for internal use. On seismic data, either state or
... federal land, basically it's never released in the
onshore basins. In the federal onshore it can be 25-
50 years before seismic data is released. So two
components: one is the Division of Oil and Gas ...
would receive the data if the credit is accepted. And
so we would have that for internal use. And again,
generally, if it was on state land already, through
our lease rights, we would receive it anyway. But the
second component is then that data has to be publicly
released. And right now seismic data would not be
released under normal purposes. So basically the
applicant would have to provide the data to the state,
and after 10 [years] ... they would have to publicly
be able to release it, similar to [how] well log data
is released now. The seismic data is never released,
but under this program, if you accepted the credit,
you'd have to release it no matter whose land it was
on, whether it be private, state, or federal land.
MR. MYERS continued:
[Regarding] well data: ... under state law almost all
wells are released after 25 months, however there are
exceptions where extended confidentiality is granted.
So even if that extended confidentiality was granted,
it would still require the well to be released after
10 years. So there's additional public benefit. And
so the other benefit is: the state itself, if the well
is on private land or federal land, generally does not
have the right to see the data until that 25 months
would be expended, and then we'd be able to see the
data immediately. And for instance, some of the wells
have been granted credit in the NPRA; ... DNR has
already received that data, and then in 10 years the
well data will be automatically released through
AOGCC.
6:10:27 PM
DAN DICKINSON, Director, Central Office, Tax Division,
Department of Revenue, in response to Representative Kerttula,
stated that the oil companies would be limited to a maximum of a
40 percent credit. He pointed out that the 40 percent credit
still exists in paragraphs 1 and 2 of Section 1(a). He
explained:
If you have an exploration well, there's certain costs
associated with that and you can get a 40 percent
credit for those. If you do seismic work, you can
also get a 40 percent credit for that seismic work.
[But] you'll never have an expense that both qualifies
as a seismic expense and qualifies as well work.
6:13:34 PM
CHAIR KOHRING commented:
One of the concerns we talked about last month ... was
what we thought to be a loophole in legislation from
two years ago: SB 281, [a] tax credit bill. We were
concerned that perhaps that bill had unintended
consequences in the sense that it was comprehensive
extending to private lands and to the NPRA and other
federal lands.
6:14:12 PM
REPRESENTATIVE ROKEBERG moved to adopt Amendment 1, labeled 24-
GH1040\G.2, Chenoweth, 3/16/05, which read:
Page 1, line 10, following "gas only lease,":
Insert "if the oil and gas lease or gas only
lease was entered into by the state under AS 38.05.131
- 38.05.134, 38.05.177, or 38.05.180,"
REPRESENTATIVE SAMUELS objected for discussion purposes.
REPRESENTATIVE ROKEBERG explained that the amendment would
restrict the credits granted in current law and in the HB 71,
and exclude private and federal lands to qualify for the credit.
He commented that he was willing to work on the bill and the
amendment with the administration and with the House Resources
Standing Committee. He noted that AS 38.05.131-38.05.134 are
the provisions for exploration licensing, AS 38.05.177 "is
nonconventional gas leases," and AS 38.05.180 are the oil and
gas leasing statutes. "The way this amendment has been drafted,
it merely states that ... it's only on state lands that these
credits are allowable, thereby excluding ... private and federal
lands," he said.
6:19:41 PM
REPRESENTATIVE ROKEBERG continued:
[The amendment] would have an immediate effective date
but it [would] only come into play for those
applications for credits that occurred after the
effective date. ... So this would not affect any
activities currently underway that would qualify for
the credits on private or federal lands ... so
everything that's done and been committed qualifies.
This would only apply to a two-year window remaining
through July 1, [2007], exclusive of Bristol Bay area
or the Alaska Peninsula, and then apply only then to
the Bristol Bay area. Frankly ... I think it might be
up to the next committee of referral for the
discussion on this; whether we want to even include
that, whether that's appropriate. I'm not sure
exactly how much, for example, privately held
subsurface estate exists in the Alaska Peninsula right
now.
6:20:58 PM
REPRESENTATIVE GARDNER commented:
I'm trying to understand, since we know now that the
previous committee understood that the tax benefit was
going to apply to federal and private lands as well,
... what the benefit would have been, why we would
have done that. Obviously if we get the seismic data,
that's one benefit to the state that they wouldn't
otherwise have. If there's development that results
in jobs, that's another benefit. ... Is there any
other reason?
REPRESENTATIVE SAMUELS answered that the state would still
receive a royalty from development on private land. He removed
his objection to the amendment.
6:22:13 PM
MR. DICKINSON clarified:
I can't speak for the committee, but I can certainly
speak for the reasons why we included state, federal,
and private lands. ... It's incorrect to think that
... automatically we'll get more revenue from state
land than we will from nonstate land. The severance
tax will apply to all production, whether it is from
state land, federal land, or private land. In fact,
if it's on private land, the severance tax will apply
to 100 percent of the production, whereas if it is on
state or federal land, we do not tax either our own
royalty share or the federal royalty share. So the
real determinant on how much a severance tax is going
to be ... is going to be the Economic Limit Factor
[ELF]. ... [If, for example,] we were to be drilling
in [Arctic National Wildlife Refuge (ANWR)] and you
found a very large field there, you would get a lot of
revenue because you might have a very high [ELF].
Compare that to a ... well drilled in the Cook Inlet
where the [ELF] is zero, so you get zero severance
tax, even though it was on state land. Again, on
income tax, we get income tax from the increased
production that flows to the companies that drill, and
again, if it's on private land, we will be taxing both
the landowner and the working interest owners.
Whereas if it's on state land, we don't tax ourselves,
[and] on federal land, we don't tax the federal
government.
MR. DICKSON continued:
[On] private land obviously we don't get no royalty
share. On federal land it can be highly variable....
Significant royalties could be flowing to the state
even though the drilling was on federal land. And
finally, property taxes: ... assets that are employed
in the use of oil and gas, whether they are on state,
federal, or private land, all the property tax will
flow either to the state or to the borough in which
those assets are located. So for the four ... [major
taxes on oil and gas], none of them can you say with
certainty [that the state would] get more if it's on
state land and less if it's on federal or private
land.
6:24:55 PM
REPRESENTATIVE ROKEBERG asked what would happen if the
subsurface estate was owned by a Native corporation or a private
holder.
MR. DICKINSON replied, "The severance tax is on any production
in the state less that owned by the federal or state
governments." He confirmed that a severance tax could be
charged on a private subsurface estate, but there would be no
royalties.
REPRESENTATIVE ROKEBERG asked:
What would be the impact of ... the current
legislation that expires in [2007] if ... the ANWR
resolution were to pass to the Congress this year and
be implemented in the federal [2006] budget, which
would put out the bonus lease sale ... before July 1,
[2007], thereby creating bonuses ... of $2.6 billion
to the state? What would be the impact of ... this
credit if those bonuses were to come before July 1,
2007?
6:26:41 PM
MR. DICKINSON deferred to Mr. Meyers. He commented, "I don't
know, in the current budget bill, whether it's still the 90:10
split and whether that would apply to the bonus bill."
REPRESENTATIVE ROKEBERG replied that it is a 50:50 split.
6:27:23 PM
MR. MYERS responded:
Because the expectations [for ANWR] are high, I'm not
sure that extending this credit one way or the other
would make a lot of difference. [In] an area like the
Alaska Peninsula, where it doesn't have infrastructure
[and] it's gas-prone, certainly the economic
incentives and the bidding levels are going to be
significantly lower. ... So we're looking at basins
with very different prospectivity, and again I don't
think extending this credit into ANWR would
significantly change companies' bidding, because they
would bid a lot of money for it anyway. ... If you
look historically on the North Slope, much of the
revenue stream coming from the royalties is typically
higher than that for the severance tax component. ...
Generally the federal government has offered
incentives where they've need to on their lands as
well.
6:30:18 PM
REPRESENTATIVE SAMUELS commented that to him the point of the
amendment is to "make sure we don't give away the farm at ANWR."
REPRESENTATIVE ROKEBERG noted the importance of making sure that
the intent of the bill is completely clear.
REPRESENTATIVE KERTTULA commented that she would like to go over
the grammar of the bill.
6:33:14 PM
There being no objection, Amendment 1 was adopted.
6:33:22 PM
REPRESENTATIVE DAHLSTROM moved to report CSHB 71(W&M) as amended
out of committee with individual recommendations and the
accompanying fiscal notes. There being no objection, CSHB
71(O&G) was reported from the House Special Committee on Oil and
Gas.
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Oil and Gas meeting was adjourned at
6:34:11 PM.
| Document Name | Date/Time | Subjects |
|---|