Legislature(2005 - 2006)CAPITOL 124
02/15/2005 05:00 PM House OIL & GAS
| Audio | Topic |
|---|---|
| Start | |
| SJR5 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | SJR 5 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
February 15, 2005
5:10 p.m.
MEMBERS PRESENT
Representative Vic Kohring, Chair
Representative Ralph Samuels, Vice Chair
Representative Nancy Dahlstrom
Representative Norman Rokeberg
Representative Berta Gardner
MEMBERS ABSENT
Representative Lesil McGuire
Representative Beth Kerttula
COMMITTEE CALENDAR
SENATE JOINT RESOLUTION NO. 5
Urging the United States Congress to reauthorize the Methane
Hydrate Research and Development Act.
- MOVED HCS SJR 5(O&G) OUT OF COMMITTEE
PREVIOUS COMMITTEE ACTION
No previous action to record.
WITNESS REGISTER
JOE BALASH, Staff
to Senator Gene Therriault
Alaska State Legislature
Juneau, Alaska
POSITION STATEMENT: Presented SJR 5 on behalf of Senator
Therriault, bill sponsor.
MARK MYERS, Director
Division of Oil and Gas
Alaska Department of Natural Resources
POSITION STATEMENT: Testified in support HB 71 and answered
questions regarding gas hydrate research.
ACTION NARRATIVE
CHAIR VIC KOHRING called the House Special Committee on Oil and
Gas meeting to order at 5:10:33 PM. Representatives Dahlstrom,
Gardner, Kohring, Rokeberg, and Samuels were present at the call
to order.
SJR 5 - REAUTHORIZE METHANE HYDRATE RESEARCH ACT
5:11:17 PM
CHAIR KOHRING announced that the only order of business would be
SENATE JOINT RESOLUTION NO. 5, "Urging the United States
Congress to reauthorize the Methane Hydrate Research and
Development Act."
JOE BALASH, Staff to Senator Gene Therriault, Alaska State
Legislature, testified on behalf of Senator Therriault, sponsor
of SJR 5. He explained that the resolution urges the U.S.
Congress to reauthorize the Methane Hydrate Research and
Development Act for another five years, and also asks for
appropriations of $70 million over that time period. He stated
that the potential additional reserves present in the form of
gas hydrates is important to the [gas] pipeline project. He
said, "The sizing of the pipe, access pointes into the pipe as
well as out of the pipe, financing costs, and ultimately the
tariffs could all be positively impacted by the determination of
the commercial viability of additional reserves in the form of
these gas hydrates up on the [North Slope]."
5:12:32 PM
MR. BALASH presented a simple description of gas hydrates:
Methane that's captured in an ice lattice that is
present in cold areas, or areas ... that are under
tremendous pressure. And once freed from that ice
lattice, [the molecules] expand to 180 times their
size, in their crystallized form. ... The industry is
well aware of the presence of the hydrates on the
slope; we know they exist. Whether or not we can put
them into commercial production or not is what needs
to be researched; that's what the original Methane
Hydrate Research Development Act of 2000 sought to
find. There's a lot of work that's been done,
particularly in the lab, in computer models and
simulations that are now ready to be taken to the next
step: field-testing and hopefully a pilot project.
5:13:38 PM
REPRESENTATIVE DAHLSTROM asked if [methane hydrate] is the thing
that she has heard referred to as the "popsicle".
MR. BALASH had not heard of this term. He clarified that his
understanding is that in the North Slope reservoirs, the crude
oil is at the bottom, and above that is the gas cap. Above the
gas cap is where the hydrates exist, close to the permafrost, he
explained. He said that when companies drill on the North
Slope, they have encountered hydrates and have developed the
techniques of putting in casings right away to make sure that
they don't experience any technical hazards such as blowouts.
5:15:32 PM
CHAIR KOHRING asked if this resolution is the first one that the
State of Alaska has sent to Congress to urge them to authorize
something of this nature. He asked, "Did we not do one in
2000?"
MR. BALASH answered that he is not familiar with one.
5:16:12 PM
CHAIR KOHRING commented that research was conducted for five
years as a result of the original authorization in 2000. He
asked what the research results were.
MR. BALASH pointed out that in the committee packet, there was a
letter from Tim Collett, U.S. Geological Survey, to Bonnie
Robson, Consultant to Legislative Budget and Audit Committee.
The letter provided an update on the gas hydrate research that
had been conducted on the North Slope and in the Arctic areas.
He said, "They've developed some techniques for looking at
seismic data to come up with estimates on how much gas hydrate
is present in ... both the onshore portion as well as the
offshore portion of the North Slope and the area around there.
And they've done a little bit to try and define the locations a
little bit better."
MR. BALASH, in response to Chair Kohring, responded that the
original authorization was substantially less than $70 million;
he guessed that it was $50 million. He said that a lot of
modeling has been done on ways to release the methane from the
hydrate form to the gaseous state. He commented that there are
"hundreds if not tens of thousands of tcf [trillion cubic feet]
of this gas hydrate present on the slope, but how much of it can
be recovered [is] obviously an open question at this point.
They can't prove that any of it is, but they suspect that very
much of it is [recoverable]."
5:20:07 PM
MR. BALASH stated that there is an estimated 590 tcf of gas
hydrates onshore in the Arctic Slope region. In comparison, he
remarked that the proposed gas pipeline project is dependent
upon 35 tcf of known reserves on the North Slope, in the Prudhoe
Bay and Point Thompson units. Within the stability zone of the
Beaufort Sea and the Chukchi Sea, he commented, the offshore
reserves are estimated at 32,000 tcf. He said, "We're not
talking about a pipeline anymore; we're talking about
pipelines."
CHAIR KOHRING noted that Representative Samuels traveled to
Congress recently to testify before the U.S. Senate's Energy
Committee, asking that this act be reauthorized.
5:21:30 PM
REPRESENTATIVE SAMUELS stated:
There's interest not just from Alaska, but because of
the formation of the hydrates, there's also interest
in the Gulf of Mexico. One of the prime sponsors was
Senator Daniel Akaka from Hawaii, actually, because
there's thinking that there might be potential there.
And I believe ... most of the work that [has] been
done until now has been mostly academic and ...
modeling, and from here on out, you would like to get
into the field and see what we can actually do. ...
When we went to Washington [D.C.] to try to get
support for this research ..., the point wasn't to get
money to be spent within the state, like we normally
get for things. We just wanted the research to be
done because we know how many hydrates we've got. It
just so happens that we probably also have the easiest
place to do the research, so it's a bit of a side
benefit. Because of the massive amounts of [methane
hydrates] we have up there, I think it's obviously
important for the state, but it's also important for
the country.
5:23:45 PM
MARK MYERS, Director, Division of Oil and Gas, Alaska Department
of Natural Resources (DNR), in response to Chair Kohring,
replied that he thinks the legislature should support this
resolution. He said:
What's important here is to ... put it in perspective,
to go back and look at the original methane hydrate
act of 2000. It was a five-year authorization [for]
... $45.7 million. And the primary goal there was to
understand the hydrates and ... get the hydrates up to
the point that we would understand their potential
commerciality, but it basically fell short of the
operational testing of the hydrates. The money was
spent not only in Alaska but [also] in other areas
like the Gulf of Mexico. In Alaska there were two
major efforts undergone, ... sponsored through DOE
[Department of Energy], and they were joint
industry/government type proposals. One had [Anadarko
Petroleum Corporation] and {Maurer Technology, Inc.];
... they drilled south of Kuparuk, off the arctic
platform. So it not only drilled for hydrates but it
also tested out the technology of the arctic platform.
5:24:41 PM
MR. MYERS continued:
The second proposal was primarily [BP Exploration
(Alaska) Inc.] with Arctic Slope Energy Services ...
with the USGS [U.S. Geological Survey] also ..., and
they looked at the hydrate potential where we knew it
existed in the Milne Point field area. And there they
actually very carefully modeled the hydrates based on
the 3-D seismic that was available to them through BP,
particularly shallow parts of the survey. So they had
high quality seismic data in which they could map out
the actual physical locations of the hydrates. That
was combined with well penetrations so you actually
had penetrations through the hydrates to quantify the
... seismic attributes. And what they found using the
3-D seismic wasn't a surprise to folks in industry
because we've had to map hydrates for years to worry
about them as a geohazard as you drilled through them
[so] that you didn't have an uncontrolled release of
the gas. So one of the things you had to prove to the
Oil and Gas Conservation Commission [was] that ... if
they were likely to be present ... what mitigation
measures you would take. And as [Mr. Balash]
mentioned, you generally case off the wells, the
hydrate zones, the active gas zones to prevent the gas
from flowing into the well bore when you're drilling
for a deeper oil horizon. So we have lots of well
penetrations in the Milne Point field, Prudhoe Bay
field, [and] Kuparuk field, where we knew there [was
a] presence of hydrates. The 3-D seismic allowed us
to calibrate the actual physical location of the
hydrates by not only just locating the structural
elements [and] controlling their distribution, but
also actually mapping out the particular attributes of
the hydrates. As important is the free gas that
exists underneath the hydrates.
5:26:07 PM
MR. MYERS continued:
The DOE money in Alaska was spent on detailed mapping
of the hydrates [using] 3-D seismic, a lot of
sophisticated modeling of that. And then using well
data to recalibrate and look at the reservoir the
hydrates existed in. Then they went to the next step,
and that was detailed reservoir simulations. They
took very complex computer models, inputted all this
data, and looked at what a typical test rate would be
from the hydrates. And particularly in the areas
where they had the ... free gas underneath the frozen
hydrate, ... they got very positive results from the
modeling: up to 50 million cubic feet [mcf] per day
out of wells, sustained rates ... above five to ten
million a day out of a single well. And high recovery
rates: 60 percent of the hydrates in an individual
fault block recovered. So the modeling suggested very
economic rates of flow and huge volumes of recovery.
... The modeling showed about 100 trillion cubic feet
of hydrate in place just underneath our existing
infrastructure alone, [and] ... potentially up to 60
trillion cubic feet of additional gas reserves, in
addition to the 24 tcf in the conventional Prudhoe Bay
reservoir, could be present and could be commercially
produced. Now that was incredibly encouraging because
that means we have a 30 plus year of gas supply for
the pipeline, assuming it's commercial. And that's
sort of where the studies ended in Alaska.
5:27:45 PM
MR. MYERS continued:
Additional work was also done in the area around
Barrow, where we have the Walakpa gas fields, and
[there are] indications that hydrates exist there, so
hydrates also are probably used now, and probably will
be in the future a source of local gas for communities
like Barrow. So we had a real interest in some study
done by BLM [Bureau of Land Management] and others in
the area of the Walakpa gas field there near Barrow.
... A combination of those two places is sort of where
the research in Alaska ended here in year five.
Additional work was done in the Gulf of Mexico [and]
USGS did work in the Mackenzie delta. ... We got to
the tantalizing opinion by the experts ... that we're
looking at something that could be highly commercial
and significant in all aspects with respect to a
commercial gas line. But we never actually tested it.
So we have the geologists and the geophysicists and
the computer modeling saying it should work, but we
never got the holes drilled and the actual long term
production testing. So the "prove it" stage is where
we're at now, and that's actually the more expensive
stage when you think about [it]. ... Doing the
analysis is one thing; physically drilling the wells
and long term testing the wells is the more expensive
part of it. ... This next five years was designed at
$70 million over the five-year period [to be for] ...
hard-core testing. [We're] assuming an operator from
the fields like BP or someone else ... would actually
drill the wells and actually do the testing, and then
would be paid for it out of the grant to get the
research results. And then there would be government-
supported work, University of Alaska-supported work,
and some DNR-supported work along that same line. But
the goal again is this long term, hard-core testing to
verify the models, which again is critical to actually
prove that the models are right and that these
reserves could be commercialized ... in the time frame
that we would hope they could be to add value to a gas
line project.
5:29:36 PM
MR. MYERS continued:
We looked at ... multiple types of tests. The first
test is a relatively simple test where ... you have a
free gas [lake] underneath the hydrates and you just
produce the free gas, lowering the pressure. Hydrates
form under certain pressure/temperature regimes; as
you increase temperature or lower pressure, either one
will bring the hydrates out of solution. So the first
type of testing would be an actual depressurizing [of]
the hydrates using conventional or horizontal well
technology, pretty ... common technology used today.
And then we would have a long-term test to see if you
could sustain the rates that the model suggests. The
next would be tests where you didn't have a free gas
[lake], where you'd have to use a different ...
mechanism to get the hydrates out.
MR. MYERS continued:
There are two other mechanisms proposed. One is you
actually heat the reservoir. By heating the
reservoir, again you've changed the
pressure/temperature regime [and] hydrates come out of
solution. And that happens naturally when you drill
an oil well through the zone. [The drilling bit] is
hot on the surrounding permafrost and sediment, and
what happens then is some of the hydrates get
released. And that's why again you put the casing
around to cool the zone and prevent it from flowing
into the well bore. ... You could circulate glycol or
some other mechanism. Thermal methods for recovering
hydrates need to be tested [and] demonstrated [for]
long-term commercial viability. The third method
that's been suggested is a chemical replacement. ...
Carbon dioxide [CO2] could in fact replace methane
molecules one for one in the crystalline lattice. So
you've got a lot with the gas line and major gas sale.
You've got a lot of CO2 at Prudhoe Bay; about 12
percent of the gas is CO2. You could take that CO2
and sequester it in the hydrate matrix and pull out
methane. Now in a lab that works fairly well, but
again we haven't actually tested in the well bore. So
the $70 million over the long term would be [used] to
do all three types of long term testing, ... [which
is] more expensive than just doing theoretical
modeling or geophysical modeling.
5:31:33 PM
MR. MYERS continued:
Additional work would be done in areas like NPRA
[National Petroleum Reserve, Alaska], where Native
communities ... or village communities could be served
by this as a local energy source. And in the longer
aspect, maybe some commerciality [would develop] in
NPRA or other areas where we know hydrates exist. ...
The numbers onshore on the hydrates that have been
mapped to date ... are over 500 tcf. So [it's a] huge
potential resource that could ultimately deliver to
the United States a lot more energy than we have even
in all of our conventional reserves combined. ... So
$70 million to demonstrate and prove that the gas
hydrates are viable in Alaska is huge leverage to the
country in terms of our gas supply. And that's why we
think it's appropriate again that the Senate and
Congress fund this proposal.
5:32:30 PM
CHAIR KOHRING asked how the estimated gas potential on the North
Slope relates to the current consumption in the U.S.
MR. MYERS replied that [by the time the gas pipeline is proposed
to be in operation] the U.S. consumption is expected to be
between 70-85 tcf/year. Currently he said that it's around 60
tcf/year.
5:33:58 PM
CHAIR KOHRING commented that the oil and gas industry stands to
benefit from this and wondered why the industry doesn't pay for
this. He remarked that he would like to see more industry
involvement and have them pay for part of this since they are
going to benefit from this as well.
MR. BALASH replied:
I'm not sure ... whether or not BP is contributing any
cash to the research project but they certainly have
made their information available. I think they've
been involved in their 3-D seismic technology,
allowing their resources and assets to be used in the
research. ... Generally speaking, ... private
industry, private capital isn't necessarily going to
go out and invest the dollars that we're talking about
in this kind of research until there's an actual need
for it. There's already 35 trillion cubic feet of gas
on the North Slope in conventionally known reserves
that they're trying to get to market. There's not a
market incentive for them to go and validate this
academic [data].
CHAIR KOHRING remarked, "Maybe in the future we could sell them
the data too. When they're ready to take the issue seriously,
we have the data we invested $120 million in; maybe we can sell
them some of that and recoup some of our investment."
5:35:42 PM
CHAIR KOHRING asked Mr. Myers to explain the difference between
the gas hydrates in Alaska and those in the Gulf of Mexico.
MR. MYERS responded:
There's a couple of differences. First of all ours
are onshore. ... The hydrates form the crystalline
lattice under a certain pressure/temperature
relationship, and if you have a higher temperature,
then it requires greater pressure. Lower temperature,
less pressure. So it's the combination of temperature
and pressure that work together. So in Alaska,
because of our cold temperatures, that pressure
gradient occurs at very shallow depths, and in fact it
occurs onshore in the permafrost. And it occurs that
way in Russia and in the Mackenzie delta as well, for
example. So in the Gulf of Mexico ... there are
hydrates but they're usually in deep water, so the
economics of production will never be as good as they
are in Alaska. The second component is [that] ... the
hydrates we have in the Prudhoe Bay area ... are
thermogenic gas, which means they are created in the
same temperature and pressure that generally oil is,
and they're driven off conventional source rocks.
Other types of methane are typically biogenic, which
means they're created by organisms that are basically
digesting material and they produce methane as a
byproduct. So microorganisms will actually produce
methane at the nearest sediment/water interface. So
here we have conventional gas that's migrating up
[depth]; it's being produced at deeper depths in the
same structures that are basically generating oil and
gas for the conventional oil and gas fields in the
Prudhoe area. And that gas is physically up [depth]
and it finds these fault blocks where it's
structurally trapped. So it's not diffuse; it's in
very thick formations, and it's in a conventional
fault block. And underneath the conventional
hydrates, where the right temperature and pressure
exist, is a zone of higher pressure where the gas
actually exists in slightly warmer temperatures, where
the exact gas exists as in the gaseous state. So we
have this hydrate underlain by free gas. And at least
in the modeling, those are going to be the most
economic hydrates because again you don't have to use
exotic technology; you don't have to heat it or
chemically replace. You can simply [depressurize] the
hydrates, which pressurizes the free gas underneath,
using very standard technology, and then the hydrates
will naturally come out of solution. Along with that
the gas will come up by itself and the water won't
come out with it. So you produce basically water-free
methane into an already-producing gas zone. So the
commerciality of that is going to be much better than
using the exotic technologies, and the rates suggested
by the modeling are much higher.
5:38:31 PM
MR. MYERS continued:
So we've got a combination then of onshore [gas that
is] underneath existing infrastructure. When we have
a gasline, we'll have a market for that gas. We'll
have pipelines connecting it up, and again we have
this thermogenic gas ... that can be produced [via]
... conventional technology. That gives us a huge
commercial leg up in areas like the deep water Gulf of
Mexico, where you'd be producing off in very deep-
water platforms. Can it be done commercially at some
point? Sure, but the costs of those development wells
is going to be extremely high. We're talking about
really post hole wells ... that will be 3000 feet at
depth, or shallower. So again we have economic
advantages ... of having infrastructure, and we're
onshore. All that, I think, leads to Alaska [as well
as places like Siberia] as being the leading areas
where you'll see this hydrate developed first.
5:39:18 PM
CHAIR KOHRING asked if there is a potential for gas hydrates in
Cook Inlet, and if so, perhaps the resolution should be modified
to encourage Congress to explore in Cook Inlet as well.
MR. MYERS reiterated that the hydrates exist due to the
combination of the temperature and pressure. There are warmer
temperatures in Cook Inlet, he stated, and he is not aware of
any naturally occurring hydrates in that area. He remarked that
there is a lot of conventional biogenic gas and very little
thermogenic gas [in Cook Inlet]. He commented that perhaps
there are some hydrates in the Aleutian Trench, but that's a
long way from the Cook Inlet infrastructure. He stated that on
the North Slope there is a hydrate stability zone that goes down
into the North Slope foothills and far offshore, but it
generally doesn't occur south of the Brooks Range.
5:41:05 PM
REPRESENTATIVE SAMUELS asked if [the researchers] could use
current well sites to do some of the research since this project
is for research purposes.
MR. MYERS answered that there are advantages to this, since
there are many old, closed off wells that penetrated the hydrate
zone. He said:
There's lots of ability to use the existing wells and
infrastructures, and the gravel pads, for instance,
are all laid. ... The use of the existing
infrastructure dramatically decreases the cost and the
efforts, and would allow long term testing and could
certainly be done in wells that ... are already
existing and are no longer useful in the deeper depths
by just simply plugging them back. And logically
we'll see some of that work when we get a major gas
sale anyway; there'll be modification of oil wells to
gas wells.... The companies will have to be able to
use the gas at the time of long-term testing in some
way in the field. So there are win-wins, particularly
if they're short, as in some of the fields like Milne
Point, generally short of natural gas to use for
running in operations. ... In the long term, testing
the gas could actually be used constructively in the
field to run power plants or to ... use as fuel gas
for compressors....
5:43:13 PM
REPRESENTATIVE SAMUELS commented:
Other than the potential of the [methane] ... melting
into the free gas as you release the pressure, if
there is no gas cap, there's still obviously a lot of
hydrates. That technology would be pretty far off
into the future. ... Even with the research you're not
talking about the development of that in the next
couple of years, but with the cap, and releasing the
pressure, you could possibly do some of that in the
short term. Would that be a true statement?
5:43:52 PM
MR. MYERS answered affirmatively and stated:
Using conventional technology, proving out the long
term testing and then by lowering the pressure, if
you're actually getting a significant contribution
from the hydrates - that would be testable, and you
can monitor that pretty accurately. The other
techniques definitely involve putting a lot of energy
into the well or using chemical substitution, [and]
ought to be tested, but logically, from a commercial
standpoint, we're looking at a North Slope gasline for
example, and you're trying to monetize that gas in the
long term. You're going to take, basically, your
Prudhoe Bay gas and some of the solution gas from
other fields like Milne Point ... and you're going to
start producing that gas off first. And then as you
have additional space in the line, you're going to
backfill it, and you're going to backfill it first
with the most commercial, high rate gas and then go to
... the other gas later. At least the modeling would
suggest ... [that] the high rate's going to come from
the combination of free gas and hydrates. So I think
it's incremental. You certainly want to test it and
develop the technology, because there's a valuable
resource there, but ... the high present value would
be in that first technique. And so we would recommend
the proposed funding would start out very early on
with that initial test of the pressure and then follow
on with testing the later technologies in the off
years, the years three, four, and five.
5:45:12 PM
REPRESENTATIVE ROKEBERG asked:
What would be the status of a lease-hold interest that
would be under production now that may contain the
methane hydrates, if it would be shut in for pre-gas
or oil production now, and it still contains some
potential uses in hydrate development in the future?
What would be the status of the lease and how would
that be handled by your department?
MR. MYERS replied that as long as the lease is producing and
reasonable attempts have been made to produce all the resource,
there's just no conflict and the lease is held by production of
the unit and the unit work commitments. He said that DNR takes
a rational approach on this: if a company is producing oil or
conventional gas and there's no capacity to sell that additional
hydrate resource, the company will keep the lease. He remarked
that he didn't think there was any jeopardy to the existing
leaseholder.
5:46:48 PM
REPRESENTATIVE ROKEBERG clarified:
I'm concerned about the situation where we could have
... a conventional petroleum well being shut in, and
then getting in the situation you described where
there would be a lack of capacity in a gas line and
then there's even the technology to produce the
hydrates, then you'd have gas in place. What would be
the legal status of the lease then if you couldn't
produce it?
MR. MYERS responded:
It would be determined by the unit plan of
development. ... And there are two other caveats; one
is physical and economic waste. And obviously we're
going to want to maximize the production from the
lease in the most efficient way, both from physical
and economic parameters. ... If the hydrates are
waiting in line for capacity in the line, it's not
going to jeopardize anyone's lease. ... There are a
lot of old gas fields that are being held for a long
period of time because of that issue. I think the
operator has to do a diligent plan of development, but
it's an orderly plan of development, so ... I can't
imagine it jeopardizing any leaseholders. Now if the
leaseholder has the opportunity to monetize it, and it
is [demonstrably] commercial, and there is market for
it, and pipeline capacity for it ... DNR typically
will challenge that plan of development.
5:48:42 PM
CHAIR KOHRING, in response to Representative Rokeberg, remarked
that perhaps the topic [of the obligations of the lessee to the
lessor] could be addressed in the House Resource Standing
Committee.
MR. BALASH pointed out that there was a change that the sponsor
wanted the committee to entertain. He turned the committee's
attention to page 3, line 1, and explained, "At the time the
resolution was introduced, and even when it passed the Senate,
Samuel Bodman had not yet been confirmed by the United States
Senate. He has now, and has been sworn in. So the word
'designee' can be removed."
5:50:16 PM
REPRESENTATIVE DAHLSTROM [made a motion] to amend SJR 5 by
deleting "designee" from page 3, line 1. There being no
objection, it was so amended.
REPRESENTATIVE SAMUELS moved to report SJR 5, as amended, from
the committee with individual recommendations and the
accompanying zero fiscal note. There being no objection, HCS
SJR 5(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
5:52:02 PM.
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