Legislature(2023 - 2024)BARNES 124
02/27/2023 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| SB10 | |
| HB50 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 10 | TELECONFERENCED | |
| *+ | HB 49 | TELECONFERENCED | |
| *+ | HB 83 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| += | HB 50 | TELECONFERENCED | |
HB 50-CARBON STORAGE
1:19:06 PM
CHAIR MCKAY announced that the next order of business would be
HOUSE BILL NO. 50, "An Act relating to the geologic storage of
carbon dioxide; and providing for an effective date."
1:19:54 PM
AARON O'QUINN, Leasing Manager, Division of Oil and Gas,
Department of Natural Resources, on behalf of the bill sponsor,
House Rules by request of the governor, co-offered a PowerPoint
presentation titled, "HB 50 - Carbon Storage, CCUS Opportunities
for the State of Alaska" [hardcopy included in the committee
packet]. He said he and Deputy Commissioner Crowther are at
today's meeting to answer questions that were posed at previous
committee hearings of HB 50. While displaying slide 2, he said
he'll be providing global overview statistics on the carbon
market; how Alaska is a container for emissions; revenue
scenarios that may be available to Alaska; and risk scenarios
[and opportunities related to carbon capture and HB 50.
1:20:56 PM
JOHN CROWTHER, Deputy Commissioner, Office of the Commissioner,
Department of Natural Resources, on behalf of the bill sponsor,
House Rules by request of the governor, co-offered a PowerPoint
presentation related to HB 50, stressed that the revenue
scenarios that will be presented are hypothetical, not a
prediction. He explained that there are significant assumptions
made in the scenarios, and said the scenarios are meant to
provide context to the committee.
1:21:16 PM
MR. O'QUINN, in regard to slide 3, stated there are 30-35
gigatons of CO2 emissions generated globally from energy related
activities, like power generation. He said that not all sources
of CO2 emissions are easily captured. A primary target for
carbon capture, utilization, and storage (CCUS) within the power
generating sector is coal-fired generation, which he stated is
the most technological feasible way to capture CO2 from energy
generation. He said Alaska is not a significant contributor to
global emissions, in that, if the world is at 35 billion tons of
CO2, then Alaska is at 14 million tons (.014). In response to a
question from Representative Saddler about global CO2 emissions,
he said 35 gigatons equals 35 billion tons.
1:23:00 PM
CHAIR MCKAY referring to the graphic on slide 3, asked if the
graph's X axis is by year and Y axis is gigatons per year
worldwide. Further, he asked if the .014 gigatons per year
figure on slide 3 accounts for all CO2 production in Alaska.
MR. O'QUINN confirmed that Chair McKay's understanding of the
data is correct.
1:23:47 PM
REPRESENTATIVE RAUSCHER asked Mr. O'Quinn what the dollar figure
would be.
MR. O'QUINN assured Representative Rauscher that his question
will be answered in a future slide.
1:24:06 PM
REPRESENTATIVE SADDLER asked Mr. O'Quinn about the .014 gigatons
per year figure on slide 3, and if that is accounting for actual
emissions or potential emissions from all sources.
MR. O'QUINN answered that the .014 is based on an inventory that
is done in Alaska through the Environmental Protection Agency
(EPA). He confirmed that .014 is the actual number for 2022.
1:24:42 PM
MR. O'QUINN returned to the presentation on slide 4 to elaborate
on Alaska's storage opportunity. He said that Alaska has three
main CO2 storage tanks: unmineable coals, saline aquifers, and
depleted oil and gas fields. On storage capacity, he stated
that unmineable coals store nearly 50 gigatons (49.24) of CO2.
He explained that depleted oil and gas fields, as well as saline
aquifers, do not have a CO2 storage estimate, but store more CO2
than unmineable coals. He said the department has a good idea
about the oil and gas fields, but said quantifying a storage
amount for saline aquifers is hard without drilling a well. He
said the department has not been drilling saline aquifer wells
as it will require additional research, but shared that aquifers
are more prolific than coal seams and could be a larger storage
receptacle. He reiterated that the world is at 30-35 gigatons
of CO2 emissions a year and stressed that Alaska has nearly 50
gigatons of storage in it's unminable coals alone, and so could
store all of the world's CO2 emissions for one year using the
coal seams.
1:26:18 PM
REPRESENTATIVE MCCABE mentioned that there's a coal-fired power
plant preparing to shut down in his district. With the
"extension cord" from Homer to Fairbanks, and natural gas
depleting, he said his district already struggles with
generating electricity. In Healy, Alaska, he stated that a
coal-fired power plant is being shut down for "being a coal
fired power plant." He noted the closure of the Fort Greely
power plant; he said it was closed because the U.S. Air Force
found that it could completely offset carbon emissions and
fulfill federal offset requirements by closing the plant. He
pointed, while on slide 4, to an area on the graphic highlighted
in blue, and suggested that it is possible to sequester the
emissions from a second power plant and save on transportation
costs. He stressed that the need for electricity matters more
than the need for the money that would be generated. He asked
if his understanding is correct, and if the department is
already considering what he explained.
DEPUTY COMMISSIONER CROWTHER answered that what Representative
McCabe described is one of the major drivers of HB 50. He said
what he has been observing internationally is the same in
Alaska, in that there are individuals that advocate against an
energy source because of its carbon emissions. With HB 50, he
said, power plants would have the ability to continue power
generation, but with emissions sequestered. He said the
department sees Alaska coal power plants as a potential
candidate for CCSU projects.
1:29:06 PM
REPRESENTATIVE RAUSCHER commented on Representative McCabe's
remarks on power plants in Alaska. He said the issue, as was
described by John Burns, was keeping the plant running. The
issues included costs associated with repairs, parts, and
maintenance. He stated that he does not think coal is the main
reason for the plant's closure.
1:29:54 PM
REPRESENTATIVE SADDLER asked for clarification regarding CO2
storage in Alaska. He asked about the 50 gigatons of CO2
storage in unminable coals and shared his understanding that the
mining space would need to be emptied before something is put in
it. He asked if Mr. O'Quinn is suggesting that the CO2 is
actually stored in and around the coal.
MR. O'QUINN explained the process of carbon storage in
unmineable coal. He said the carbon is pressurized so that
there would be room for CO2 to occupy pore space within the coal
seams.
1:30:47 PM
MR. O'QUINN moved to slide 5 to talk about hypothetical revenue
opportunities. He echoed Deputy Commissioner Crowther's
comments, in that the scenarios are "very hypothetical," but
said he feels that the scenarios rely on reasonable economic
assumptions. He explained that the scenarios come with a caveat
in that they are designed to illustrate magnitudes, and not
specific numbers, and further, that he and Deputy Commissioner
Crowther are not making promises about revenue. He spoke to the
metrics of a regional power plant, comparable in size to the
Healy power plant, which generated 600,000 metric tons of
emissions a year. The conceptual regional power facility would
generate 250,000 tons a year; have a $2.50 per metric ton
injection fee; a fee of $20 per acre every non-injection year;
and would have a 20-year life. The next hypothetical
opportunity would be an emitting facility on the North Slope,
which would generate 2,000,000 metric tons of CO2 a year. The
facility would use 50 percent of the emissions for enhanced oil
recovery (EOR) and the other 50 percent for pure sequestration.
He noted the last option on the slide, which is a CO2 import and
sequestration facility, and said such a facility would be a
longer term project with a 40-year life. He summed up the three
hypothetical options: a small, medium and large facility.
1:33:10 PM
REPRESENTATIVE ARMSTRONG pointed to a graphic, on slide 5, of a
conceptual waterborne CO2 carrier. She asked how many tons of
CO2 such a vessel could carry.
DEPUTY COMMISSIONER CROWTHER answered that, currently, the
ocean-going transshipment of CO2 is still under assessment. He
said he is unable to answer what volume of CO2 will be stored on
the carriers but said the level of CO2 emissions that is being
talking about today is not being shipped. He stated that the
more CO2 transported on a carrier, the better it will be for the
economics. He said he imagines millions - if not billions - of
tons would be shipped via vessel, if possible.
1:34:03 PM
CHAIR MCKAY relayed his thought that the CO2 carriers would be
similar to liquefied natural gas (LNG) tankers since the CO2 is
being liquefied and is a gas.
MR. O'QUINN shared that, in concepts observed by the department,
the CO2 would be backhaul. He expounded that hydrogen or
ammonia would be exported, and then CO2 would come as backhaul
from the countries that imported hydrogen or ammonia.
1:34:55 PM
MR. O'QUINN returned to the presentation on slide 6. He said a
current caveat is that not all CO2 emissions are feasibly
captured, and that there's developing technology in carbon
capture space. He explained that captured CO2 emissions are
primarily from industrial processes. With government support
through Section 45Q tax credits, as well as research grant
initiatives from the U.S. Department of Energy, he said
technology is continuing to rapidly develop. He stressed that
the capital expenditures for such projects are very high,
especially for retrofitting existing power plants. He stated
that sometimes the benefits of the sequestration project cannot
overcome the initial capital expenditures. He said, however,
that there are a growing number of opportunities for capital
expenditure support, which in turn has made such an expenditure
less of a barrier. He explained that CO2 importing is dependent
on the development of shipping and loading technology.
1:36:22 PM
CHAIR MCKAY noted that, to address Representative Armstrong's
question on how much CO2 could be carried on a waterborne
vessel, current LNG tankers carry 125,000-150,000 cubic meters
of LNG.
1:36:43 PM
MR. O'QUINN moved to slide 7 to outline possible state revenues
from the three hypothetical facilities shown previously on slide
5. For a regional power facility, it would have a 20-year life
with acquisition of property and exploration in the first three
years, and then a ramp up of CO2 injection in the fifth year.
Between the injection fees and annual rental fees, the
department estimates about $11.8 million in revenue. Regarding
the North Slope Facility Standalone CCUS project, he pointed out
additional EOR oil revenue increases and reduced pollution
charges. He said this is to highlight that, in some areas where
carbon is captured, injection could lead to additional oil
production. He explained that the department made some
geological assumptions about the reservoir's impact from CO2
injection and how it would affect oil barrel yield, based on
experience with natural gas injection increasing oil production.
1:38:17 PM
MR. O'QUINN explained the reduced pollution charges; during the
CO2 capture process, there's an opportunity to capture certain
regulated pollutants. Then the operator would be considered not
polluting, since it is capturing the pollutants, and would not
need to be charged for pollution fees by the Department of
Environmental Conservation. He again stressed that the
conversation is hypothetical, and said he is demonstrating to
the committee the possible impact of operators taking pollutants
or CO2 out of the air. He reviewed scenario two on the list of
hypothetical revenue opportunities, which forecasts $210 million
in revenue over a 20-year period. As for scenario three, CO2
import for sequestration, the revenue over 40 years totals over
$1 billion dollars.
1:39:48 PM
REPRESENTATIVE SADDLER queried Mr. O'Quinn about his comments
that, by capturing CO2, other pollutants may be captured. He
asked if HB 50 envisions injecting additional pollutants, and
further, if there is a standard the CO2 needs to qualify for
injection.
MR. O'QUINN answered that HB 50 contains a definition of CO2 and
requires that the CO2 meets a certain level of purity. The bill
does not define purity itself, as the department will rely on
the Alaska Oil and Gas Conservation Commission to make the
regulatory determination. On tax credits, he said there are
purity requirements in the transportation of CO2, but said the
department felt that statute was not the most appropriate place
to define such CO2 standards broadly.
1:41:03 PM
DEPUTY COMMISSIONER CROWTHER added that the captured pollutants
are either being emitted subject to regulation and permits or
managed consistent with existing authority and regulation. He
said there are existing protocols in place for managing other
pollutants in the CO2 streams, like methane, carbon monoxide and
hydrogen sulfide. He said HB 50 acknowledges that, whether
treating flume emissions, natural gas feedstocks, or other
components of the industrial process, the pollutants might
appear and will need to be managed. He said the pollutants can
be disposed of in other ways, but the department is not
proposing that the pollutants be injected into CO2 for
sequestration.
REPRESENTATIVE SADDLER replied that the comments are good to
hear. He said it appears issues, like CO2 by volume compared to
other pollutants, are being addressed upstream.
1:42:23 PM
REPRESENTATIVE MEARS offered clarification that exploration
leases cover a large portion of land, while during development,
focus is narrowed to an area.
MR. O'QUINN confirmed that is correct, in that there is larger
acreage for exploration licensing, and that licensees determine
what they need, which reduces their property rights entitlement.
He said the process can be seen in years two and three on the
chart on slide 7, in that the licenses are paid up until the
year an operator starts injecting.
1:43:16 PM
REPRESENTATIVE MEARS pointed out that the chart projects a best-
case scenario. She asked about slide 8's mention of a newly
updated fiscal note, which said the cost for plastics primacy
was covered. She surmised that the cost would be covered by
federal grants. She further asked about the zero fiscal note
for the AOGCC and DNR to come up with regulations and begin
administering the program.
DEPUTY COMMISSIONER CROWTHER said the next slide will provide a
summary of risk and the costs that would be incurred in a zero-
development scenario. He said Representative Mears'
characterization is correct, in that the fiscal notes have been
reduced, and said DNR does not expect other costs.
1:44:33 PM
REPRESENTATIVE SADDLER asked Deputy Commissioner Crowther about
scenario two, the North Slope CCUS project, which is
hypothesized to generate $210 million in revenue over the course
of 20 years. He asked if that covers the entirety of Alaska's
North Slope, or if it covers a single field in particular. He
said he is asking in order to understand how much of the
emissions in the North Slope the project would be covering.
MR. O'QUINN recalled slide 5 to answer the question, and spoke
on the standalone North Slope emitting facility project. He
mentioned that there are two emissions facilities on the North
Slope: one producing two million tons a year, and the other,
three million. He defined standalone as a facility that is not
part of AKLNG or the gas line, but rather, existing facilities
on the North Slope. To answer Representative Saddler's
question, he said the hypothetical scenario assumes one facility
with one emitter on the North Slope.
1:46:00 PM
CHAIR MCKAY commented that if three million was added to the
other facility, the number could be scaled up.
DEPUTY COMMISSIONER CROWTHER confirmed Chair McKay's comment as
correct. He said there are additional facilities and operations
beyond the corporate facilities, which still have emissions. He
noted that emissions on the entirety of the North Slope are
larger than five million, and said the data was included because
it was concentrated from a single source.
1:46:33 PM
MR. O'QUINN added that Alaska emissions amount to 14 million
tons annually.
1:46:49 PM
REPRESENTATIVE ARMSTRONG pointed out, on slide 7, that it takes
five to six years before revenue from injection fees are
realized. She asked why it takes five to six years.
MR. O'QUINN reminded committee members about DNR's statutory
exploration licensing process. He spoke about what needs to
take place on a site: a characterization report; property rights
acquisition; and a best interest finding report. Once
entitlement is received, land exploration activities take place;
however, injection could occur sooner if the operator knows the
subsurface area well. He said from what DNR has seen in the
Lower 48, and what they expect to see in Alaska, subsurface
review and infrastructure buildouts take time, especially for
retrofits. As examples, a coal-fired power plant takes time to
build, as does a pipeline. He said DNR believes that the five-
year timeline is reasonable for Alaska, but could possibly be
longer depending on the construction season.
1:48:38 PM
REPRESENTATIVE MEARS suggested that scenario two would happen
first, as there are injections happening now. She asked if the
operations are turn-key and would not require exploration and
development.
DEPUTY COMMISSIONER CROWTHER stressed that, while it may be
possible, the timeline DNR has shared is hypothetical. He
explained that one aspect of the project that takes a lot of up-
front time is understanding the geologic space an operator plans
to sequester. In a scenario where an operator has a good
understanding of either the existing production, depleted
reservoirs for EOR, or of other adjacent reservoirs, the
operator may be able to speed up the characterization process.
However, that facility construction and permitting could still
consume a portion of the up-front time. He said it is a fair
statement that the people that carry out the project in scenario
two would likely have a better understanding of their targeted
geology than in scenarios one and three.
REPRESENTATIVE MEARS asked if it is more likely that Alaska
would start with scenario two.
DEPUTY COMMISSIONER CROWTHER answered that it is hard for DNR to
say it is "more likely," but said that a project with more
defined characteristics is naturally ahead in the process. He
said scenario two was included because if the capital,
corporate, and technological capacity is there, it's a good
"ready-made" example that DNR believes could develop quickly.
He said that, in a general sense, it appears more likely for the
project to start, but reiterated that it is not DNR's position
to say when or how the project would come together.
1:51:10 PM
CHAIR MCKAY commented that it would be interesting to see
another scenario where a 42-inch gas pipeline is built, and with
the rate of gas production, how much CO2 would be "scrubbed
out." He suggested that this could be a fourth scenario like
scenario two, but with greater volume.
DEPUTY COMMISSIONER CROWTHER answered that scenario two deals
with existing facilities: the production of power and the
pressurization of produced methane back into the Prudhoe Bay
reservoir, and capturing the emissions. He hypothesized that,
if there was a large gas sale, a much larger volume of gas would
be processed to remove all the CO2, which would be significantly
larger than scenario two.
CHAIR MCKAY explained he had pointed that out because, over the
long term, it could add to the speculated revenue.
1:52:42 PM
MR. O'QUINN added that CO2 processed at the gas treatment plant
most likely would be used for EOR, which would result in
additional barrels of oil, but not necessarily revenues under
carbon capture.
CHAIR MCKAY said he was unsure whether those present knew that
or not.
1:53:14 PM
MR. O'QUINN returned to slide 8 of the presentation. In
addressing Representative Mears' question about the scenario in
which no one comes forward to develop carbon capture, he said
that DNR believes the industry is ready to bring projects to
Alaska. He said that there is no project in hand, and that the
legislation, HB 50, is not being designed around one specific
project. He explained that a worst-case scenario, there being
no development, would pose a low risk to the state. He said DNR
requested over $1 million dollars in the fiscal note for two
full-time positions within AOGCC for Fiscal Year (FY) 24;
however, AOGCC has communicated that it intends to seek out EPA
grant funds under the underground injection control class six
grant program. He said DNR believes that costs could be covered
by the grant for several years so that AOGCC can "stand up" a
regulatory program. He explained that through the work of his
staff, there is a new online bidding system for lease sales that
was set up by, and for, DNR. He said it would be an initial
lift to get a regulatory program set up, but expressed his
belief that it can be done in-house, so the fiscal note was
revised to zero for next year and out years.
1:55:32 PM
MR. O'QUINN said the Division of Oil and Gas has additional
technical needs, like geologists and economists, but said he
would rather like to wait to ask the legislature for those
resources until there is a specific need for them. He
reiterated his belief that the program could be stood up within
DNR's Division of Oil and Gas, without taking on additional
staff, but said it may be something to come back to once the
industry coalesces. He stated that DEC has possible theoretical
reductions in its revenue due to decreased pollution, and would
require that the carbon facilities already be operational.
DEPUTY COMMISSIONER CROWTHER showcased slide 7 to talk about
exploration licenses. He illustrated a hypothetical scenario
where there is little to no business activity, and what activity
there is, is in exploration licenses. He said that licensing
activity still brings thousands of dollars of revenue to the
state, depending on the size of the project. He further made
the point that even if there are just a few exploration
licenses, no injections, and no development, the state could
still at least see revenue from the licensing. He said the
present risks are de minimis costs offset with federal grant
funds. He stated that even the worst-case scenario is
protective and positive for the state.
1:57:51 PM
REPRESENTATIVE MCCABE asked about the presenter's remarks
regarding the zeroing out of a previous $456,000 DNR fiscal
note.
DEPUTY COMMISSIONER CROWTHER answered that upon receiving the
committee substitute, the fiscal note for DNR will reflect zero.
1:58:19 PM
MR. O'QUINN moved to slide 9 to talk about carbon storage
opportunities in Alaska. In a hypothetical scenario where the
carbon storage infrastructure is built out and CO2 injection is
occurring, there are significant opportunities for revenue. In
building a carbon storage industry in Alaska, he said, EOR could
be developed as well as extend the life of existing royalty
revenues by providing decarbonization opportunities. He said
that most of the corporations have emissions targets they have
to meet, and by allowing the companies to reach their emissions
target in Alaska, the lifespan of projects could be extended,
which would make the state more attractive to investment. He
reminded members that carbon storage revenues are split between
the general and permanent fund, per Alaska constitutional and
statutory language relating to mineral revenue. He stated that
the industry builds upon, preserves, and could grow the Alaska
oil and gas technical workforce. He explained that there are
analog aspects of carbon storage work: wells being drilled,
pipelines built, and work that requires engineers and
geologists. Another opportunity under carbon storage is in the
power generating industry, where power facilities can now de-
carbonize, and also diversify in base power generation.
2:00:33 PM
REPRESENTATIVE SADDLER queried Mr. O'Quinn about the revenues
going to the permanent and general funds. He asked if both the
injection and rental fees are subject to the required 25 percent
contribution to the permanent fund, or if it is just rental fees
that are subject to the requirement.
MR. O'QUINN expressed his belief that both fund streams are
subject to the requirement. Further, he said all revenue is
split, per the Alaska Constitution.
2:01:07 PM
CHAIR MCKAY asked the presenters to talk about how the state
would manage long-term liability of storage projects, and if the
state would need to pay insurance. He said he is asking in
order to provide further clarity on the record.
DEPUTY COMMISSIONER CROWTHER answered that, as the project
develops, there would be a fee assessment by the state that
would go into a long-term fund for managing liability. He
clarified this does not mean that while the project was
operating, the state would have liability, rather the liability
would be on the project operator. He explained that liability
would continue to be on the operator, even while operator
reviews, with the AOGCC, the potential closure of the facility.
The closure would be contingent on AOGCC approving of the
closure, and after a period of time following closure, the
liability would go to the state, as well as the title of the
project. When the state subsumes liability for a project, the
long term liability fund could be used to address any issue that
may arise after the regulatory closure process is complete. He
said it is possible that the state may want to procure insurance
for risks outside of the fund. He further suggested that it's
possible that the liabilities would be low while the fund
balance accumulates. He said that, from an actuarial standpoint,
the state would be well covered, and the fund would be the
framework for managing long term liability.
2:03:01 PM
REPRESENTATIVE SADDLER referred to the possible revenues listed
on slide 7. He asked how much of the revenue for the North
Slope emitting facility would need to be kept in a trust fund
and how much would need to be kept in the permanent and general
funds.
MR. O'QUINN reminded committee members that the data around the
hypothetical scenarios do not look at injection fees; those
would instead be accessed by the regulatory agency. He
explained that the fees are analogous to the regulatory cost
charge that AOGCC assesses against industry, or like DEC
assesses against polluters. He said these fees are currently
assessed by AOGCC and are established in the permit, or
regulation. The fees that are paid for the proprietary use of
the property rights on the pore space account for AOGCC's year-
to-year administrative permitting activity, as well as the long-
term closure fund.
2:04:50 PM
CHAIR MCKAY asked the presenters to walk the committee through
how DNR will manage competing land uses when the leases are
issued. An example he shared was public use oil and gas
extraction versus storage, which he said would take precedence
and dominate.
MR. O'QUINN responded that, as far as the surface conflicts, DNR
envisions that carbon storage would work the same as the oil and
gas industry does today. He pointed out that the state does
control access to the surface at Prudhoe Bay, with allowances
made toward subsistence and community uses. He stated that
there would not be exclusivity, except in instances where it is
required for safety reasons. He reminded members of the North
Dakota example where there was one injection well, two
monitoring wells, and a few pipelines, all of which leave a
small surface foot print. He said that notification to mineral
owners of a carbon project would be required by law, as well as
the state and other mineral licensees. He said that DNR has
empowered AOGCC to mitigate conflicts by setting spacing rules
that govern drilling through one horizon over another. He
stated that DNR has laid out that carbon capture would not
interfere with the mineral industry. He further stated that
this plan would not trump oil and gas production.
2:07:15 PM
REPRESENTATIVE SADDLER posed a hypothetical scenario wherein
five to ten years later, when the process is complete, CO2 is
injected into the ground and the liability process is covered,
there is a need in the market for the stored CO2. He asked if
the state could access a closed capped CO2 storage reservoir and
use that gas for commercial purposes, like selling it back to
the operator who injected the gas.
DEPUTY COMMISSIONER CROWTHER answered that the state, once the
title transfers over, would own the stored CO2. He explained
that, in theory, if someone wanted to make good use of the CO2,
it would be a state resource and the state's to manage. He
advised that getting to the stored CO2 would require a
technically and operationally complex piece of equipment to
drill and produce the CO2 safely and responsibly. He said that,
if a storage operator identifies some CO2 they wish to store or
sell, they are able to do that through the course of their
operations; however, the operator cannot manage the CO2 after
their lease is finished as it is then considered the state's.
Though, if the operator wanted to make use of the stored CO2
after the closure and title change is made, it would be the
state's to manage.
REPRESENTATIVE SADDLER asked, if for any reason an operator does
not surrender control of the stored CO2 and wished to keep it
past ten years, whether HB 50 would allow for that.
DEPUTY COMMISSIONER CROWTHER responded that he is hesitant to
speculate all the scenarios, but explained that an existing oil
and gas operation can continue to produce miniscule volumes,
depending on the economic and business decisions of the
operator. He said that there's talk in the west U.S. regarding
stripper wells, which produce one to a dozen barrels a day.
Similarly with carbon storage, an operator may choose to inject
a small amount of CO2 as the project matures, but the injections
are subject to the permit as well as AOGCC regulations on
injections. The carbon operator could not do anything contrary
to the regulations, but it is possible that the operator may
want to maintain a project at a low level for a long time in
case there are other uses for CO2, or until more CO2 comes to be
injected.
2:10:10 PM
REPRESENTATIVE MEARS thanked the presenters. She commented that
she is working to understand air quality implications, and will
have more questions in the future.
2:11:07 PM
CHAIR MCKAY thanked the presenters. He announced that HB 50 was
held over.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 10 Sponsor Statement version A 01.19.2023.pdf |
HRES 2/27/2023 1:00:00 PM |
|
| SB 10 Sectional Analysis version A 01.19.2023.pdf |
HRES 2/27/2023 1:00:00 PM |
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| HB 50 DNR CCUS Development Scenarios Presentation to HRES 02.27.2023.pdf |
HRES 2/27/2023 1:00:00 PM |
HB 50 |
| HB 50 Class VI Grant Letter of Intent AOGCC.pdf |
HRES 2/27/2023 1:00:00 PM |
HB 50 |