Legislature(2023 - 2024)ADAMS 519
04/11/2023 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Adjourn | |
| Start | |
| HB50 |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 50 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE FINANCE COMMITTEE
April 11, 2023
1:39 p.m.
1:39:49 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 1:39 p.m.
MEMBERS PRESENT
Representative Bryce Edgmon, Co-Chair
Representative Neal Foster, Co-Chair
Representative DeLena Johnson, Co-Chair
Representative Julie Coulombe
Representative Mike Cronk
Representative Alyse Galvin
Representative Sara Hannan
Representative Andy Josephson
Representative Will Stapp
Representative Frank Tomaszewski
MEMBERS ABSENT
Representative Dan Ortiz
ALSO PRESENT
John Crowther, Deputy Commissioner, Department of Natural
Resources; Ryan Fitzpatrick, Commercial Analyst, Division
of Oil and Gas.
PRESENT VIA TELECONFERENCE
John Boyle, Commissioner, Department of Natural Resources,
Delta Junction; Haley Paine, Deputy Director, Division of
Oil and Gas, Anchorage.
SUMMARY
HB 50 CARBON STORAGE
HB 50 was HEARD and HELD in committee for further
consideration.
Co-Chair Foster reviewed the agenda for the meeting. He
noted the concept was new and welcomed questions
throughout. He added that there were a number of experts
online available for questions.
HOUSE BILL NO. 50
"An Act relating to the geologic storage of carbon dioxide;
and providing for an effective date."
1:42:30 PM
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, introduced himself and deferred the introduction
of the topic to his colleague.
JOHN BOYLE, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES,
DELTA JUNCTION (via teleconference), thought that HB 50 was
one of the more important pieces of legislation in the
current year. There was an opportunity in the state to
diversify the economy and raise new revenues by monetizing
the empty forest space in the state. The storage potential
in the Cook Inlet in particular was significant. The
resource was immense and there were opportunities to export
energy and create a value change where the state was
exporting carbon to Asia. It could create an enormous
amount of opportunities.
Mr. Boyle explained that the federal government increased
the amount of tax credit opportunities through the
Infrastructure Investment and Jobs Act (IIJA) and he
thought it would be prudent for Alaska to take advantage of
the opportunities. The economic landscape had changed and
projects that had not made economic sense in the past made
economic sense in the present day. The reason the state was
pushing for the legislation to be enacted soon was that the
tax credits for carbon capture, utilization, and storage
had a shelf life. There was a window of time to act, after
which the credits could expire. There were a number of
companies in the state already interested in pursuing
carbon projects and it was important for the state to be
prepared with a regulatory framework in place. He noted
that the Environmental Protection Agency (EPA) had made
funding available for other states to utilize in an effort
to apply for primacy. He hoped to see the process of
gaining primacy move along in a timely manner.
Mr. Boyle continued that the state had processing
facilities and power generating facilities on the North
Slope which emitted a significant amount of carbon. There
were other facilities such as coal plants in the interior
region of the state that would provide opportunities for
carbon sequestration. It was important to understand that a
major element of the Alaska Liquified Natural Gas (AKLNG)
was to have a gas treatment plant on the North Slope that
would remove carbon dioxide (CO2) from natural gas before
it was shipped down the gas pipeline to Nikiski, Alaska.
The framework needed to be in place in order to enable the
project to take advantage of tax credits. The most
surprising element of the carbon capture utilization and
storage portion of the bill was that the Alaska Supreme
Court had ruled that the empty pore space underground was
considered part of the mineral estate for the state. The
ruling meant that 25 percent of the fees that would be
charged for project developers go to growing the Permanent
Fund. He thought it would be an incredible opportunity for
the state to monetize a resource that had never been
monetized before, grown the Permanent Fund in the process,
and create other interesting opportunities.
Co-Chair Foster asked if committee members had questions
for Mr. Boyle.
1:50:11 PM
Representative Hannan understood that there was a window of
opportunity for the state to take advantage of the 45Q tax
credit. It seemed that 2033 was the deadline to start
construction to qualify for the credit. She asked if Mr.
Boyle saw 2033 as being a ten-year window. She recalled
that he expressed that the legislature needed to pass HB 50
in the current year which implied that the window of
opportunity was shorter. She asked how Mr. Boyle viewed the
window of opportunity separate from what was dictated by
the tax code precedent.
Mr. Boyle responded that he did not have the deadline for
qualification in front of him but assumed that
Representative Hannan was correct. He intended to imply
that the sooner the state had the framework in place and
the sooner the Alaska Oil and Gas Conservation Commission
(AOGCC)could apply for primacy, the sooner companies could
access better opportunities to get projects under
development and qualify for tax credits. It would also help
the Alaska Liquified Natural Gas (AKLNG) to engage with the
market if there was a framework in place for carbon
sequestration. There were numerous benefits to the state
being able to pursue the tax credits earlier rather than
later.
Representative Hannan asked about the zero fiscal note from
the Department of Revenue [control code wpuhz}. She
wondered if the expectation was that there would be no
revenue within the next ten years and it therefore would
not show in the fiscal note. She understood that the bill
was described as an economic opportunity to develop revenue
and not just to implement an additional method to process
oil and gas in the state.
Mr. Crowther responded that he would speak to the scope and
timing of revenue in his upcoming presentation. The
department thought that it was possible to see some initial
leasing revenue in the near future; however, due to the
novelty of the concept, a specific revenue amount had not
yet been identified.
1:54:19 PM
Mr. Crowther introduced the PowerPoint presentation titled
"HB 50 Carbon Capture, Utilization, and Storage," dated
April 11, 2023 (copy on file). He advanced to slide 2 and
offered the outline of the presentation. He noted that the
introduction of presentation would be quite significant as
we would outline some basic concepts surrounding Carbon
Capture, Utilization, and Storage (CCUS).
Mr. Crowther moved to slide 3 which showed DNR's
constitutional mandate in Article VIII of the Alaska
Constitution. It was the policy of the state to encourage
the settlement of state land and the development of state
resources by making them available for maximum use
consistent with the public interest. The department thought
that the pore space was an increasingly valuable natural
resource and the intent of the bill was to meet the mandate
and make the resource available.
Mr. Crowther continued to slide 4. The department thought
that HB 50 would satisfy the constitutional directive to
develop resources. It would enable the state to maximize
use of its pore space resource while remaining consistent
with public interest and providing for reasonable
concurrent uses and protection of all parties. He added
that AOGCC would be empowered to utilize (AOGCC) to utilize
existing authorities and expertise on carbon dioxide
geologic storage.
Mr. Crowther advanced to slide 5 which detailed CCUS. He
explained that CCUS was a process intended to capture CO2,
either from industrial sources or directly from the
atmosphere, for the purpose of utilizing it for other
activities or storing it underground in geologic
formations. He relayed that CCUS was driving interest and
activity all across the country and world and the market
was rapidly expanding. The department wanted the state to
participate in the CCUS market and utilize the state's
natural resources. The timeline was a significant driver
for the bill. The deadline of 2033 might seem distant, but
the steps that needed to occur before a project could be
constructed were significant and it was prudent to start
the process as quickly as possible. Individuals making
business decisions in the present day could know that CCUS
projects were coming to Alaska even if there were still
regulatory steps that needed to be taken before a project
could be constructed. There was tremendous potential in
Alaska for CCUS and the state had many geological resources
that made it conducive to carbon storage. Alaska's depleted
oil and gas fields, saline aquifers, and deep coal seams
had significant CO2 storage potential.
1:59:52 PM
Representative Galvin asked Mr. Crowther for more detail on
the expanding CCUS market. There was not much CO2 to
sequester at the current time in Alaska. She wondered if
there had been a precedent set where CO2 had been
transferred from one country to another. She wanted a
broader picture of the process and thought it seemed like
it would be a significant undertaking. She asked if CCUS
was a revenue project or was it a project to assist in the
way that oil and gas was doing its work. She was trying to
discern the difference between the two goals. She was
unsure if the global market was yet developed.
Mr. Crowther responded that her questions would be answered
during the presentation. The pore space was a resource of
the state and could generate revenue, which would then be
partially designated to the Permanent Fund. It was
important to also enable other beneficial resources such as
coal. He thought coal could be a beneficial resource for
Alaskans if there was a way to eliminate the emission of
CO2 into the air. Carbon management was the solution if
carbon emissions were the problem. He thought that the
associated activities were the benefit for the people of
Alaska, but revenue could also be present. The department
saw the future potential for importing carbon into Alaska.
There were ships being built to enable the transportation
of carbon across oceans. There were also test cases going
on and barging of carbon in some cases. The department saw
carbon coming to Alaska from Southeast Asia as a large
possibility. Existing activities such as power and energy
generation or oil and gas generation could also benefit
from the framework being in place. Carbon dioxide was
already being emitted through the existing activities and
allowing the state the ability to manage the emissions
would be advantageous. The activities continuing and
expanding would be valuable to the state. He thought that
there were individuals who would make active use of the
framework both in the present day and in the future.
Representative Hannan asked Mr. Crowther for confirmation
that when saline aquifers were separate from oil and gas.
Mr. Crowther responded that saline aquifers were often
collocated on a basin level with oil and gas fields because
the same geology that formed the aquifers was the same
geology that could collect and trap oil and gas if there
was a petroleum charge in the system that led hydrocarbon
to migrate into the structures. If there was no hydrocarbon
migration, water and other saline minerals would accumulate
in the area. He concluded that the two were often
collocated, but not always collocated.
2:05:44 PM
Mr. Crowther moved to slide 6 and explained the stages of
the CCUS process. He highlighted the capture stage of the
process which involved capturing CO2 from fossil or
biomass-fueled power stations, industrial facilities, or
directly from the air. When the carbon was captured, it
needed to be transferred. Carbon was typically transferred
via pipelines over short distances but the department
endeavored for it to be transferred over long distances in
the future. The carbon would then be used as an input or
feedstock to create products or services. The bill mostly
focused on the storage stage of the CCUS process, which
involved permanently storing CO2 in underground geological
formations, onshore, or offshore.
Mr. Crowther continued to slide 7 which showed a
hypothetical projection of world captured CO2 by source
from 2020 through 2070. It assumed that the world's carbon
emissions were net zero by the year 2070 and all carbon
emissions would be managed, sequestered, and limited. The
scenario was not predicted, but rather depicting a fast-
moving and complete transition to carbon management. The
graph showed how many CCUS facilities the International
Energy Agency (IEA) predicted there would be in 2070 in
order to fully manage the net zero transition and provide
carbon sequestration on the necessary scale. He highlighted
that biomass, natural gas, and coal comprised a large
portion of the energy mix, but the carbon dioxide generated
from it was sequestered underground. Alaska had worldclass
biomass, coal, and natural gas resources and CCUS would
enable the resources to be as valuable or more valuable in
50 years' time. He emphasized that CCUS enabled not only
short-term projects in Alaska, but also encouraged
consistency and growth for the state's other resources.
2:08:59 PM
Mr. Crowther continued on slide 8, which was an excerpt of
all of the oil and gas companies operating in Alaska and
the companies' self-described and self-identified goals for
carbon management. Many companies aimed to reach net zero
carbon emissions and were therefore customers of the state
through the CCUS process. Carbon management was viewed as
an important element to enable projects to be net zero.
Co-Chair Johnson asked if all of the companies on the slide
had investments in Alaska already.
Mr. Crowther responded in the affirmative.
Co-Chair Johnson asked if there was technology that
simultaneously allowed for drilling and removal in addition
to injection.
Mr. Crowther responded in the affirmative. Companies with
hydrocarbon reservoir productions currently had to navigate
through other layers and strategies to access subsurface
oil rights. If there was carbon storage going on in an
area, it was another element that had to be considered in
well designs in the project development. An operator would
have to understand both existing wells and reservoir
dynamics. It was possible that CO2 could be sequestered in
the same geological column as oil and gas if designed
appropriately and regulated carefully by the AOGCC.
2:11:37 PM
RYAN FITZPATRICK, COMMERCIAL ANALYST, DIVISION OF OIL AND
GAS, continued on slide 9 and a map of the potential
storage basins. There was a study conducted by DNR about 10
year prior that examined the potential of carbon storage
throughout the state. The study identified a variety of
geologic basins in the state where carbon could potentially
occur and rated the areas by level of potential. The North
Slope and Cook Inlet both showed up as high potential areas
on the map mainly because the study looked at not only the
geologic elements of the storage, but also the existing
infrastructure. The study also found that there might be up
to 50 gigatons (Gt) of carbon storage in Cook Inlet. The 50
Gt figure referred to coal seam storage. There was an
additional option for saline aquifers in Cook Inlet and
study did not look at oil and gas reservoirs. He cautioned
that the study was high-level and although there was great
potential, the more important component in the success of a
project was ensuring that a particular project was both
supported by the local geography and by the economics
surrounding the project.
Representative Stapp asked Mr. Crowther if the bill were to
pass and a high amount of carbon was sequestered in the
Cook Inlet basin, what would be the potential liability of
the state if there was something like an earthquake and the
stored carbon was released.
Mr. Crowther responded that from a financial liability, if
stored carbon was released due to an event like an
earthquake, there were limited claw back provisions for the
federal tax credits within a three year window. The
framework of the bill established a transfer of liability
in the long term, but there would not be liability
associated with the released of the carbon because the tax
credit claw back period would be closed and there was no
fee for emitting CO2. He noted that there had been induced
seismicity in areas of the country where there was high
pressure injected in geologic formations. For sequestration
purposed, the goal was to inject at a pressure that
maintained the structure of the reservoir and would not
fracture it or overpressure it to ensure that the CO2
successfully migrated. The lower pressure injection would
be required as part of the injection approval by AOGCC and
seismicity was unlikely to be induced. He noted that there
had been significant earthquakes in the Cook Inlet area and
the oil and gas reservoirs were still maintained without
any evidence of migrating to the surface.
Co-Chair Johnson asked Mr. Crowthers if compressed carbon
be backhauled in the same ship as natural gas containers if
the containers were to be shipped out of Alaska.
Mr. Crowther responded that AKLNG had specific requirements
and it was more likely that backhauling would be done on
something like an ammonia container or potentially a
hydrogen ship. He did not think that AKLNG containers could
currently be backfilled, but as the market matured, it
could coevolve with the potential shipping of CO2.
2:18:57 PM
Mr. Fitzpatrick continued on slide 10 and explained that
carbon storage was the focus of HB 50. The slide showed the
potential targets in the geologic strata for carbon
sequestration. The idea was to sequester the carbon deep
underground and the injection targets would be well below
the depth of fresh water and drinking water. There were
technical reasons why carbon injected underground needed to
be at a certain depth, which he would discuss in more
detail in subsequent slides.
Mr. Fitzpatrick moved to slide 11 which summarized several
points about geologic carbon storage. The geologic storage
options included depleted and declining oil and gas fields,
saline formations, and un-mineable coal seams. The
subsurface formations were required to be deeper than about
2,600 feet because the CO2 needed to be kept at a
supercritical liquid phase, which meant that the gas would
behave as a liquid. In the supercritical liquid phase, gas
became highly compressed and was easier to store. In order
to keep the pressure underground, the injection needed to
occur under 2,600 feet. During the closeout period,
monitoring of the CO2 injection was critical.
Mr. Fitzpatrick advanced to slide 12 which summarized
federal incentives. The 45Q tax credit was part of the
federal internal revenue code. The deadline to start
construction was January 1, 2033. In order to be ready to
start construction on time, AOGCC needed to go through the
Class VI primacy phase, which was estimated to take about
two years. In addition, the project development period
needed to be completed prior to construction. There was a
potential desire to move quickly due to the time consuming
stages that were required to be completed before
construction could begin. The credit itself could vary
significantly depending on the operation: credits could be
$60 per ton for utilization of capture CO2 for enhanced oil
recovery (EOR), $85 per ton for CCUS from industrial
facilities and power plants stored in geologic formations,
or $180 per ton for direct air capture (DAC) carbon stored
in geologic formations and $130/ton for DAC carbon used in
EOR.
2:24:06 PM
Representative Josephson referred to the third bullet point
on the slide regarding EOR. He asked Mr. Fitzpatrick if the
state's oil producers would already be entitled to the tax
credit since EOR was already occurring.
Mr. Fitzpatrick replied that EOR could occur presently
under current oil and gas operations. There was a
requirement to measure the amount of CO2 that was injected
in order to qualify as EOR. He understood that there also
needed to be some measurement of the potential CO2 that
could be produced during the process. It was hypothetically
possible for ten tons of CO2 into a formation but one ton
was reproduced as part of the oil and gas operation, only
the nine remaining tons would be qualified for receiving
credits.
Representative Josephson asked whether it was possible for
AOGCC to apply for Class VI primacy without enabling the
tax credit process.
Mr. Crowther responded that it was the department's
understanding that AOGCC could pursue Class VI primacy and
gain the authority granted by primacy. It would
predominantly be applicable to private lands in Alaska
because was presently limited opportunity to make state
resources available. It was important for regulatory
approval through AOGCC to occur as well as to allow for
state land to be made available on clear terms in order to
utilize the Class VI permitting on state land.
2:27:15 PM
Representative Hannan thought that Arizona had pursued
primacy separate from comprehensive legislation. She asked
when states had begun pursuing primacy and why Arizona
would pursue primacy but not other legislation that might
monetize it.
Mr. Crowther moved to slide 14 and responded that the
graphic showed a map of the country indicating the states
that were advancing carbon storage programs. There was a
period in 2009 and 2010 during which many states were
actively adopting the framework of the program. Most states
had not seen significant project investment until
relatively recently with the expansion of the federal
credit. He was uncertain whether Arizona was considering
framework legislation. Many states had much more private
CCUS rights and the program was much more relevant to
private operators and a broader state framework was not
necessarily needed.
Representative Hannan understood that carbon sequestration
was not a topic of conversation in 2009 and 2010. She asked
whether Class VI wells were the same type of wells that
some states were using for fracking.
Mr. Crowther responded that he might defer the question
regarding the exact date the Class VI framework was
initiated. He explained that Class VI was one of six
classes of the Underground Injection Program (UIP) through
the U.S. Safe Drinking Water Act (SDWA) The classes were
part of the US safe drinking water act administered by the
EPA. Each class set standards by which a well had to be
designed. He relayed that Class VI was a relatively new
part of UIP because the framework sometime predated the
pursuit of an actual project. He would follow up with the
committee on when exactly Class VI was initiated.
2:32:01 PM
Representative Coulombe asked Mr. Crowther what accounted
for the larger $180 per ton tax credit for DAC.
Mr. Crowther responded that the credits were tiered in
order to incentivize particular activities and reflected
the costs related to performing the activity. There was
additional revenue associated with EOR. When EOR was not
involved in a process, the cost of capture had to be offset
with the cost of the credit. The DAC process was expensive
because the technology to filter the air was costly. The
credit was therefore set at a higher rate to incentivize
the activity.
Representative Coulombe asked if the injection into the
ground for DAC the same as other processes.
Mr. Crowther responded that the pressurization of the
carbon dioxide was relatively the same, however, there were
relatively different technologies to enable the capture of
carbon dioxide which was the reason for the differing
costs.
Mr. Fitzpatrick continued on slide 13, which gave a general
overview of the way in which HB 50 would enable carbon
storage. He read the objectives of HB 50 as follows:
• Provides for the use of public lands for CCUS
• Accounts for the amalgamation of property interests
and
• protection of correlative rights
• Outlines relationship between other commercial
minerals and
• reservoirs to be used for storage
• Enables permitting for CO2 pipelines
• Defines ownership of carbon dioxide and ascription
of liability
• Addresses authority for Safe Drinking Water Act
(SDWA)
• Class VI well primacy
2:35:54 PM
Representative Josephson asked Mr. Crowther for a
description of what would cause a dispute over liability.
Mr. Crowther responded that there was liability for any
project nearing its operations. Most of the time in the
course of a project operation, there were penalty
provisions from AOGCC. The bill also set up a framework for
an operator to conduct a series of activities to close out
a project and then receive regulatory approval through
AOGCC to shut down a project. The injection would then
cease and the CO2 would be permanently in the ground. The
framework would allow the liability to be released from the
operator after a period of ten years and the state would
then assume the liability for the ownership and liability
for the CO2. The legislation laid out a funding mechanism
for the state to set up a find for the state to avoid any
costs associated with maintaining and holding the
liability. The department thought that the areas of
liability would be limited and would be addressed
thoroughly prior to a project closeout.
Representative Josephson relayed that he had learned that
if HB 49 were to pass, the state would not be able to enter
into an agreement where it would be permitted to reduce its
biomass in a state forest. He asked if the state would have
the obligation after year ten to ensure that the CO2 stayed
where it had been injected as a company might need a
reliable capturer of CO2.
Mr. Crowther responded that it was possible that carbon
projects could be undertaken for a variety of reason. There
may be a certification involved stating that the project
would perform as expected, and part of the expectation
could be that the CO2 would remain underground. The
liability framework was part of enabling commercial
transactions because a party could reliably say that it
would commit to appropriately pursuing a project and
operate under state regulations and eventually close out
the project under the same regulations. The department
foresaw that the series of decisions were negotiable and
financeable for the investments that parties were already
undertaking. He thought that the framework met the need and
the liabilities would ensure that agreed upon obligations
were held up.
2:41:16 PM
Representative Galvin thought that the bill dealt with
numerous complex subjects. She asked Mr. Crowther to
provide a sense of the expertise on which the state relied
to help craft the legislation and who would be guiding the
state in the implementation of the program if it were to
pass.
Mr. Crowther jumped forward to slide 15 to answer the
question. The slide detailed the workgroup committees that
were involved in the crafting of the legislation. The pie
chart showed the composition of the working group, which
was made up of state, university, corporate, and federal
parties. The department retained Stantec Consulting to help
it formalize the state review and assessment and created a
report that would be made available to the committee. The
Institute of Northern Engineering (INE) at the University
of Alaska (UA) Fairbanks was highly involved in the process
and the entity Plains CO2 Reduction (PCOR) was also
consulted. He explained that PCOR was originally funded by
the federal Department of Energy (DOE) to study CO2 in
states like North Dakota that had been pioneers in the
carbon space. Additionally, UA had joined the University of
North Dakota and the University of Wyoming to become acting
chairs of the PCOR Partnership. The annual meeting of the
partnership was hosted in Alaska and the department had
been heavily relying of the partnership to determine what
was going on in the space across the country. The
department thought it had a robust and varied of
consultants.
Representative Galvin understood that PCOR helped with
forming the bill. She wondered if the partnership would
also be guiding the state in the implementation of the bill
if it were to pass.
Mr. Crowther replied that PCOR and the other aforementioned
entities would continue to act as a resource for the state
and the department during the proposed implementation of
the legislation. He suggested that Mr. Fitzpatrick could
speak to the question in more detail.
Mr. Fitzpatrick responded that the work group set up by UA
continued to meet in the present day. There was a CCUS
symposium that was being held earlier in the morning by
some of the members of the work group in preparation for an
upcoming energy summit in Anchorage. The group was formed
initially as a study group around the idea of CCUS but as
the work group developed, it was determined that CCUS might
be a good fit for Alaska. The group evolved into a think
tank on what needed to occur to form legislation in the
state. In August of 2022, the university put on a
regulatory symposium to discuss the steps that would need
to happen to make CCUS a reality in Alaska. Although the
Department of Law (DOL) was integral in crafting the
language in HB 50, most of the concepts behind the bill
were a result of the 2022 summit.
2:47:45 PM
Mr. Fitzpatrick continued on slide 16 which summarized CCUS
opportunities for the state. The development of CCUS could
bolster development of Alaska's oil and gas resources. The
federal incentives in Infrastructure Investment and Jobs
Act (IIJA) in addition to other funding made available by
the federal government were driving investments in other
states that had been pioneers in the carbon space.
Environmental goals were driving capital to projects with
carbon management options. He argued that Alaska should
participate in the global uptick of CCUS projects. There
were over 60 CCUSS facilities currently in the development
phase and it was possible that the number could increase
dramatically in the coming years. The amount of CO2
captured by CCUS facilities had increased by over 44
percent over the last 12 months. It was a small industry
but it rapidly growing. Project timelines required the
state to act promptly because of the deadlines of the
federal incentives. The department also saw CCUS as a way
to potentially bring in additional state revenue and
maximize the value of state resources.
2:50:08 PM
Representative Coulombe understood that the project would
not have a separate carbon account and the revenue from
CCUS would be deposited directly into the unrestricted
general fund (UGF). She asked if her understanding was
correct.
Mr. Crowther responded in the affirmative. The revenue from
the use of the pore space mineral resource would accrue to
state. There was also a liability fund and a small charge
would be put into the account. Additionally, a small charge
would be dedicated to the AOGCC operations for the
regulations. The primary revenue from the use of the pore
space would go to the general fund.
Mr. Fitzpatrick continued on slide 18 which would show
potential timelines and CCUS project phases. The timeline
on the slide looked at projects through the lens of SDWA of
1974 and Act and Class VI for wells specifically for the
purpose of underground storage of CO2. He explained that a
CCUS project would begin in the exploratory phase, at which
point a project would not yet consider Class VI issues and
was mostly a seismic exploration of the land. Once a
project advanced to the permitting phase, a Class VI permit
would need to be attained, which could take several months
to several years. After the permitting phase, a well would
enter the storage phase during which CO2 would be injected
into the formation. Once the storage phase was complete,
there was a closure period, during which the well would
still remain under the Class VI well jurisdiction. During
the closure phase, injections were no longer taking place
but measures were being taken to ensure a site had been
properly abandoned and the surface infrastructure had been
removed. The CO2 underground was being constantly monitored
to ensure that it had stabilized and was no longer moving
underground. The final phase was the post-closure phase
which involved monitoring the CO2 over the course of time
and sometimes up to 50 years.
2:54:20 PM
Representative Stapp understood that successful CO2 storage
underground in perpetuity would likely require
sophisticated monitoring devices and regulatory guidance.
He thought that the bill designated regulatory authority to
DNR and the Department of Environmental Conservation (DEC).
He asked if the legislative body would have input on which
regulatory requirements would be involved in the process.
Mr. Crowther responded that as it related to closure and
monitoring associated with an ongoing project, there were
specific criteria for the approval of a storage permit and
the closure of a storage permit. He thought it was
explicitly required by the bill. There were other methods
of assessing subsurface areas, such as seismic technologies
that could be required at different intervals. The
framework was required in the statutory language itself and
would be administered by AOGCC.
Mr. Fitzpatrick added that one of the other aspects of the
regulatory structure was that if AOGCC pursued Class VI
primacy, the regulations that already existed under the EPA
for Class VI wells would need to be adopted by AOGCC. There
was some leeway in the primacy application to tailor
regulations to a particular jurisdiction. It would cover
elements such as the well design and ensure that CO2 would
not be injected into potential drinking water sources.
Representative Josephson recalled that there could be
monitoring for up for 50 years. He asked if the state was
ten years into the project in the post-closure stage, how
would the committee measure the cost of the other 40 years.
He wondered if the costs would be balanced with an income
stream.
Mr. Fitzpatrick responded that the ten years post-closure
was more of a minimum term. The intention was that AOGCC
would only issue a closure certificate once the agency was
satisfied that the process of dismantling a facility had
occurred properly. If there was an injection well that was
set up for monitoring of the formation, the state could
take over the operation of the well. He emphasized that
AOGCC would be examining whether the CO2 was stabilized and
no longer moving underground. There would be a monitoring
infrastructure during the closure process and occasional
seismic surveys and the potential risks at the post-closure
stage would be minimal.
Mr. Crowther added that on slide 25, he would be more
specific information.
3:00:37 PM
Mr. Fitzpatrick continued on slide 19, which looked at CCUS
wells from a project development standpoint. The screening
period involved analyzing specific data that might already
exist such as geologic surveys of the area. The operators
would select a specific area in the feasibility stage and
might be testing wells, sampling, or conducting seismic
surveys. If a potential project was determined feasible, it
would move into the project design and permit application
stage. The next stage was the regulatory review of the
permit, followed by investment and construction of the
well. The final stage was beginning operations of the
project.
Mr. Fitzpatrick continued to slide 20 which detailed a
project that was already in development. The project was
called the Red Tail Energy Project (RTEP) in North Dakota
and had a single injection well and a monitoring well. The
total area for the project was 3,480 acres and was
sequestering 180,000 metric tons per year of CO2, which was
considered a small scale project. It demonstrated that CCUS
projects could be achieved on a small scale but could also
be scaled up to a larger scale depending on local geology.
Representative Coulombe was surprised to see that the
residential zone on the RTEP map was close to the project
area. She asked if the proximity was concerning.
Mr. Crowther responded that the orange section on the map
was indeed a community in North Dakota. The white area
outline was the subsurface rights that needed to be
secured. From a community proximity perspective, all
industrial sites had to be appropriately operated to avoid
specific incidents. There were no concerns about the
project being close to other land use areas or communities.
Mr. Fitzpatrick added that one of the features of the
project was that once the wells were in place, the amount
of surface facilities was relatively minimal. The well
itself was often relatively small and was unlike oil and
gas surface facilities.
3:06:47 PM
Representative Hannan asked for more detail about RTEP. She
wondered if the carbon was being delivered from another
area or was it a former carbon producing site.
Mr. Fitzpatrick responded that he could speak from his
knowledge base, but there were testifier online that might
be able to provide more information. He understood that the
project was sequestering CO2 and capturing the energy from
coal power plants in North Dakota.
3:07:56 PM
HALEY PAINE, DEPUTY DIRECTOR, DIVISION OIL AND GAS,
ANCHORAGE (via teleconference), responded that the RTEP was
an ethanol facility, which produced a high quality stream
of CO2 as a byproduct of the fermentation process. There
was no distinct transportation process that brought the
materials into the area because the project was situation
on top of a geologically suitable sequestration site. The
carbon went directly from the facility itself and into the
subsurface. There were other projects in development in
North Dakota that would involve transportation efforts
through a pipeline.
Representative Hannan asked whether the corporate partners
involved in the PCOR Partnership were basing projects in
Alaska on projects like RTEP. She assumed that Alaska
companies were looking to states like North Dakota for
guidance.
Mr. Crowther responded that the work group involved a wide
array of companies such as service companies and oil and
gas companies that had existing infrastructure on the North
Slope. The group had seen participation from companies that
had Alaska-specific experience.
Mr. Fitzpatrick advanced to slide 21, which offered
additional information on RTEP. There was a five-year
evaluation and design period for the project and North
Dakota was granted primacy for Class VI wells on April 24,
2018.
3:12:41 PM
Representative Galvin asked for more information about
Class VI wells.
Mr. Fitzpatrick responded that there were no Class VI wells
in Alaska, but there were several in North Dakota and
Wyoming and many others were in the permitting process. He
relayed that AOGCC had permitting authority for Class II
wells, which were the wells associated with enhanced oil
recovery and injection for oil and gas operations. He
explained that AOGCC was required to manage the injection
and ensure that it was not interfering with drinking water
or compromising reservoir integrity. The EPA had different
permitting structures for Class II wells that for Class VI
wells, in part due to the fact that another type of
substance would be injected. When injecting CO2 for
sequestration purposes, it must be injected into an area
where the CO2 would be sequestered for a longer period of
time. The regulatory categories were different, but Class
VI wells were otherwise similar to Class II wells already
permitted by AOGCC.
Representative Galvin shared her understanding that Class
VI was for CO2 purposes and was for a longer period of
time. She thought that Class II wells could work for the
sequestration of CO2 as well.
Mr. Fitzpatrick responded that CO2 could be sequestered in
a Class II well if it was being used for enhanced oil
recovery. The 45Q tax credit might be application in
situations where CO2 was injected in order to get more oil
and gas out of the ground. The state already allowed for
the injection of CO2 for enhanced oil recovery purposes. If
a company proposed a pure sequestration project to the
state, there might be more CO2 than could be accommodated
by enhanced oil recovery. A Class VI well was required for
projects with the purpose of pure sequestration. There was
a period of time that EPA had indicated that it might be
required to switch between a Class II well and a Class VI
well if it appeared that a Class II well was being used for
pure sequestration. He clarified that Class VI wells would
be needed if the state wanted to undertake pure
sequestration projects.
3:17:19 PM
Mr. Fitzpatrick continued on slide 22 which offered
additional information on the CCUS phases and legislation.
The slide matched the different stages of the timeline with
coordinating sections of the bill. For example, Section 16
of the bill coordinated with issuing the exploratory
permits and Section 33 coordinated with issuing the
facility permits, permits to drill wells, and permits to
inject. He relayed that Section 16 and Section 33 were the
most significant elements of the bill.
Co-Chair Foster suggested that the committee take up the
remainder of the presentation at a subsequent meeting. He
asked members if there were any questions.
Representative Tomaszewski understood that there was a
study in existence that showed there was too much CO2 in
the air. He asked if there was a slide that showed such a
study. He asked who was monitoring how much CO2 was in the
atmosphere.
Mr. Crowther responded that the concentration of CO2 in the
atmosphere was being studied. There was an increasing
amount of carbon in the atmosphere because of the emissions
from the consumption of coal and similar substances. The
goal of the CCUS projects was to diminish any new emissions
by sequestering the carbon. He thought that there would
still be plentiful amounts of carbon and the growth of
fruits and vegetables would not suffer. The projects were
focused on preventing new coal emissions that would add to
the carbon in the atmosphere. He would be happy to provide
a chart of the overall trends.
Representative Tomaszewski would like to see the overall
trends.
3:22:57 PM
Representative Coulombe asked what happened to CO2 once it
was injected. She wanted to consider the long term impacts.
She asked if the CO2 would remain in place or move through
the earth over time.
Mr. Crowther responded that the goal was to pressurize the
carbon dioxide and introduce it to the reservoir and let it
migrate throughout the reservoir. The pressure of the
injection balanced the other pressure and the carbon would
migrate until a particular point and was then generally
stable and kept in place. It was high pressure and critical
carbon dioxide gas that was sitting in a reservoir and in a
pressure equilibrium with the existing pressure of the
reservoir. It needed to be injected to 2,600 feet or deeper
in order to have enough existing pressure to maintain a
balance.
Mr. Fitzpatrick added that another aspect was that there
were geologic traps kept oil and gas in place. He explained
that as CO2 migrated, it would migrate towards the
direction of an underground geologic trap and there was an
impermeable column above the CO2 through which it could not
migrate.
3:26:27 PM
Co-Chair Johnson thanked the presenters. She reviewed the
agenda for the following day's meeting.
HB 50 was HEARD and HELD in committee for further
consideration.
ADJOURNMENT
3:27:22 PM
The meeting was adjourned at 3:27 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 59 Public Testimony Rec'd by 041023.pdf |
HFIN 4/11/2023 1:30:00 PM |
HB 59 |
| HFIN DNR HB 50 CCUS Presentation 041123.pdf |
HFIN 4/11/2023 1:30:00 PM |
HB 50 |