Legislature(2023 - 2024)ADAMS 519
01/25/2024 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Adjourn | |
| Start | |
| HB89 | |
| HB50 |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 89 | TELECONFERENCED | |
| += | HB 50 | TELECONFERENCED | |
HOUSE BILL NO. 50
"An Act relating to the geologic storage of carbon
dioxide; and providing for an effective date."
2:55:46 PM
Co-Chair Johnson MOVED to ADOPT the proposed committee
substitute for HB 50, Work Draft 33-GH1567\R (Dunmire,
1/22/24).
Co-Chair Foster OBJECTED for discussion.
2:56:34 PM
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, explained that the proposed committee substitute
would delete a section of HB 50 that had already been
enacted into law in the prior year. The section granted
authority to pursue primacy to the Alaska Oil and Gas
Conservation Commission (AOGCC). He introduced the
PowerPoint Presentation "Recap: HB 50 Carbon Storage" dated
January 25, 2024 (copy on file). He began on slide 2 and
offered an overview of the presentation's agenda.
Mr. Crowther continued to slide 3 and explained that the
intent of HB 50 was to make Alaska's subsurface resources
available for maximum use. The resources were already used
in other ways, but the bill was focused on the
sequestration of carbon dioxide. There were two key
elements that remained in HB 50 that were core to the bill:
enabling the Department of Natural Resources (DNR) to make
state lands available through a leasing program, and to
offer specific regulatory framework to AOGCC as it
administered the program and sought to pursue primacy.
Co-Chair Foster suggested holding questions until the end
of the presentation.
Mr. Crowther advanced to slide 4 and explained that the
bill had nine hearings in the House Resource Committee
(HRC) and five hearings in the House Finance Committee. The
committee substitute passed out by HRC involved the
following changes: several minor drafting style changes, a
modified fund status to ensure that the funds would not be
sweepable, adjusted commercial terms from statute and
directed the terms to be established by regulations,
removed federal 45Q tax credits from AS 43.20.036, and
added carbon dioxide to AS 46.03.022(10)(B) to the
Department of Environmental Conservation's (DEC) pipeline
jurisdiction.
Mr. Crowther continued to slide 5 and offered information
of some developments in the carbon capture utilization and
storage (CCUS) industry. There had been significant
movement in the broad CCUS space in the state as well as
the nation. For example, there were two new facilities in
North Dakota that were actively injecting CO2.
Additionally, Wyoming had issued its first Class VI well
approval in December of 2023 and Louisiana had received
Class VI well primacy from the Environmental Protection
Agency (EPA) in December of 2023. In Alaska, grants had
been issued through the federal Department of Energy (DOE)
to start development on CCUS projects.
3:02:15 PM
BRETT HUBER, COMMISSIONER, ALASKA OIL AND GAS CONSERVATION
COMMISSION, ANCHORAGE (via teleconference), relayed that if
he were to summarize his portion of the presentation, he
would say "we are advancing and things are going well." He
presumed that the committee would like him to go into more
detail.
Co-Chair Foster commented that it was a great summary but
additional detail would be helpful.
Mr. Huber continued to slide 7 and noted that SB 48 had
passed in the prior year, which granted AOGCC the authority
to pursue Class VI primacy from the EPA. The bill included
funds for appropriation for one engineer position and one
assistant position as well as funds for contractual and
legal support.
Mr. Huber continued to slide 8 and explained that for
states that had completed the primacy process, the timeline
ranged from three to six years. The state was presently in
the pre-application phase and AOGCC's goal was to complete
the process in the next two years. He relayed that AOGCC
thought it would be helpful to look to other states to
determine what worked and what did not work in order to
meet the two-year timeline goal. He indicated that AOGCC
only had control over a portion of the process and the
EPA's interaction and approval was at the purview of the
legislature. He added that AOGCC and EPA would collaborate
on the "regulatory crosswalk," which was a comparison
between federal and proposed state regulations. Only once
AOGCC had submitted the complete application package would
it be considered in the application phase with the EPA.
Mr. Huber advanced to slide 9 and gave a brief history of
EPA interactions with AOGCC pertaining to CCUS. Interaction
began with a receipt of a letter of inquiry from EPA
seeking states that were interested in primacy grants and
pursuing Class VI primacy. He had received the letter in
January of 2023 and he had replied on behalf of the state
and submitted a letter of interest. He received notice of
grant availability on November 2, 2023, and AOGCC attended
the grant webinar on November 16, 2023. He relayed that
AOGCC completed its grant application in December of 2023.
He had heard that $1.93 million was allocated for each
interested state and grant awards would follow in the
coming spring or summer. The grant term was five years,
which indicated that a protracted primacy process was still
anticipated by EPA.
3:06:52 PM
Mr. Huber continued to slide 10 and noted that as part of
the primacy process, EPA and AOGCC would engage in a
"crosswalk" process that compared state statute and
regulation with federal code. The intent of the EPA was to
confirm that the proposed state processes were as stringent
as federal requirements. The EPA authority for CCUS was
included in the Clean Drinking Water Act. The primacy
process was meant to ensure that that the state was meeting
or exceeding regulatory standards for the protection of
fresh and clean drinking water. There were three areas of
concern identified by the EPA in its initial review of the
CCUS legislation in August of 2023 as listed on the slide:
1. Exceptions or waivers "for good cause" may lead to
stringency questions vs. federal code
2. Liability transfer process and post-closure trust
fund period could be inconsistent vs. federal code
as the EPA requires liability to remain with the
operator for the full, 50-year post-closure period
3. Penalty provisions AOGCC has since determined
proposed penalties should meet or exceed federal code
Mr. Huber relayed that AOGCC had been working closely with
DNR to recommend a path forward. The approach made by
Louisiana seemed like a good model for Alaska as it
provided scrutiny and safeguards to the state through the
end of the 50-year EPA-required monitoring period. He
explained that AOGCC asked for an early review in order to
avoid needing to return to the legislature year after year
to ask for amendment necessary to achieve primacy; however,
it was still possible that statutory amendments would be
necessary in the future.
Mr. Huber continued to slide 11 and remarked that AOGCC was
well-resourced to pursue the primacy effort and for
implementation of the program once primacy was achieved.
There was a strong team dedicated to the process such as a
legal team including support from DOL and contracted
services with a former DOL regulatory attorney. The legal
team would focus on developing the crosswalk and regulation
package as well as the Memorandum of Agreement (MOA). The
commissioners and staff were leading the regulatory package
development, outreach, and public participation efforts, as
well as providing technical input to the legal team. There
were two new positions that would help in the regulatory
package development and AOGCC was presently recruiting for
the roles.
Mr. Huber moved to slide 12 and explained that AOGCC
released a request for information for consultant services
and received six responses. The potential services included
reservoir analysis, reservoir modelling and simulations,
project management, and environmental justice activities
assessments. Request for proposals would be issued nearer
to the end of the primacy process in anticipation of AOGCC
receiving a Class VI storage facility application. The
anticipated issuance date was September of 2025.
Co-Chair Foster suggested holding questions until the end
of the presentation.
3:10:33 PM
HALEY PAYNE, DEPUTY DIRECTOR, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, continued the presentation
on slide 14. There had been significant development in CCUS
in other states since HB 50 had been introduced. After
analyzing the strategies in other states, it became clear
that there was not one particular leasing mechanism, public
process, or suite of commercial terms that applied in every
situation or in every state. There was significant variance
between approaches. She noted that none of the other states
had issued minimums in statute for commercial terms, which
was also the case for HB 50. The Texas General Land Office
(TGLO) put forward minimums, but the minimums were only in
the lease sale process. An additional difference between
the process in Texas as compared to a state like Wyoming or
Louisiana was that when Texas passed carbon legislation in
2009, the state commenced TGLO into a study for site
characterization for CO2 and the state was only offering
for sale the tracks that were characterized. The site
characterization study took five years from the time the
legislation passed. She relayed that DNR's strategy would
likely look more similar to Wyoming or Louisiana.
Ms. Payne advanced quickly through slide 15 and moved to
slide 16. The purpose of the slide was to bring forward the
various phases of the CCUS process and legislation. The
slide demonstrated the ways in which HB 50 addressed all of
the CCUS phases from start to end. She stated that the
majority of the components of the bill would be found in
Section 16, which impacted DNR, and Section 33, which
governed the AOGCC.
3:13:29 PM
Mr. Crowther added that the section references on the slide
were not updated to reflect the sections in the proposed
committee substitute, but it would be updated if the
committee substitute were to be adopted.
Ms. Payne continued on slide 17, which detailed the four
major authorizations under HB 50 broken out into the two
different regulatory bodies: DNR and AOGCC. She explained
that DNR would be licensing the state's core space which
would begin with the issuance of a carbon storage
exploration license. The license would allow an operator to
delineate the subsurface and understand what could be used
as a suitable reservoir for injection. The department would
then apply to AOGCC for a carbon storage facility permit,
which would involve a rigorous evaluation of the subsurface
container to ensure the protection of other mineral and
property interests. After a licensee could demonstrate to
DNR that the permit was approved, the licensee would then
be issued a carbon storage lease through DNR. The lease
would authorize the injection of CO2 into the core space
and would act as the governing contract for the duration of
the operations into the post-closure period. The final
authorization was the closure certificate, which would be
issued by AOGCC. The certificate would be issued after an
operator had ceased injection operations and had been able
to demonstrate that the site was stabilized and met all
regulatory requirements.
Ms. Payne continued to slide 18, which included the
expected timeline for the four authorizations detailed on
slide 17. She relayed that the process would begin with the
issuance of a carbon storage exploration license which
would transition into a carbon storage lease once the AOGCC
permit had been issued. She highlighted that the timeline
was an estimate and was based on projects in North Dakota.
The comparison was not perfect and it was possible that the
process could take longer in Alaska. The slide also
indicated the outlay of the number of capital expenditures
that would be required prior to operations.
Co-Chair Foster surmised that the major change in the
committee substitute was the deletion of Section 3. He
thanked the testifiers for the update on the CCUS field. He
asked if members had questions.
3:17:19 PM
Representative Josephson understood that the bill referred
to the state taking ownership of the asset after ten years.
The federal government had stated that ten years was an
insufficient amount of time and that the industry should
instead control the asset for 50 years. He asked how the
ten-year timeframe was decided upon.
Mr. Crowther responded that the intent with the bill as
drafted was to induce and promote development by
facilitating a company to plan for a ten-year obligation
with the knowledge that the state would take over at the
end of the obligation period. The department viewed the
timeframe as a way to allow corporate entities to better
plan for projects. He relayed that other states were
looking at similar time frames. The restrictions from the
EPA made projects more challenging but also increased the
direct responsibility of the operator. The department was
looking at potential amendments to ensure that the
framework was consistent with EPA guidelines.
Ms. Payne added that the bill was based upon the model that
was developed by the Interstate Oil and Gas Compact
Commission as the recommended best practices. The model
also served as the basis for North Dakota's legislation.
The ten-year period was more than just a demarcation as it
required that an operator demonstrate the stabilization of
the plume at the end of the time period.
Representative Josephson noted that one issue that had been
raised by a geologist in an HRC meeting was that CO2 could
be used to enhance oil recovery. He remarked that there was
a section of the bill on oil and gas recovery. He was
concerned that credits could be "double dipping" in both
regular oil development and in CCUS. He asked if the
language in the bill was clear enough to ensure that
credits could only be utilized once for purposes of
deduction.
3:21:18 PM
Mr. Crowther responded that the bill set appropriate
clarity for when and how credits could be used. He noted
that one of the categories was created by the underlying
federal tax credit as opposed to the state framework.
Operators could also potentially sequester CO2 in a pure
sequestration method and receive a certain level of the 45Q
tax credit. There were also options to sequester CO2 in
certain manners associated with DOR if the CO2 met the
criteria set out in the federal program, in which case an
operator would receive a lesser tax credit. There were
other pressure management activities that might not qualify
for the tax credit but an operator could choose to pursue
the activities. He thought that HB 50 set the correct
framework amongst the various options. All operators were
looking for federal guidance and clarity on some of the
elements of the federal requirements.
Representative Josephson suggested that it would be
beneficial to include an illustration of the types of
credits for the sake of clarity. He thought that a visual
aid might help him understand the differences better.
Production would impact the state's revenue and he wanted
to ensure that the state was not mistakenly allowing
credits to have a dual purpose.
Co-Chair Foster agreed that the issue was new and complex.
He wanted to ensure that committee members were comfortable
with the topic before taking any action on the bill.
3:24:45 PM
Representative Galvin referred to slide 16 and understood
that the long-term monitoring timeframe had changed from
the 50-year window to the 10-year window to help companies
that needed to make plans within a scope that fit a
business model. She wondered if there were any other
considerations that went into the change. She asked for
more detail on the costs of DNR overseeing the program and
wondered if insurance was necessary. She was unsure of the
types of liabilities that would be involved.
Ms. Payne responded that it was envisioned that over the
lifetime of a project, there would be an injection charge
that would be put into a fund that would be available to
pay for the post-closure period. The funds would be in
addition to all the various levels of bonding that would be
required under the Class VI permit. She noted that the EPA
recommended a timeline of 50 years or until an applicant
could demonstrate stabilization of the plume. The funds
were imagined as another form of insurance. She emphasized
that it would have to be proven that the subsurface was
stabilized and it was important to remain nimble to the
geology as well as recognize some corporate limitations.
Representative Galvin wondered if there was any modeling of
what the fund would look like and how it would function.
She recalled that in the prior year, the committee had been
told that sequestration would be a significant source of
revenue.
Ms. Payne responded that the fund was set on a project-by-
project basis and it would depend on the size of the
facility and the amount of CO2 being injected. The
department had not done any modeling because site-specific
plans were not yet available to evaluate, but there were
examples in North Dakota and Louisiana. She reiterated that
the department was looking closely at Louisiana because it
had recently been granted primacy.
Mr. Crowther noted that the committee substitute included
the ten-year timeframe and the associated fund language,
but it was the department's intent to adjust the timeframe
through amendments in the future.
Co-Chair Foster relayed that the committee was out of time
but suggested that members could ask questions and the
testifiers could respond in a follow up.
Representative Hannan noted that the outline of the
presentation spoke to an appendix with a sectional analysis
but it was not in the presentation. She requested to
receive the information. The comments about plume stability
reminded her of the concern about seismic activity and she
remarked that North Dakota and Wyoming had a different
seismic environment than Alaska. She asked how the seismic
activity might impact plume stability. She requested that
her questions be answered in a follow up.
3:31:01 PM
Co-Chair Foster WITHDREW the OBJECTION to adopting the
committee substitute.
There being NO further OBJECTION, Work Draft 33-GH1567\R
was ADOPTED.
Co-Chair Foster went over the agenda for the following
day's meeting.
HB 50 was HEARD and HELD in committee for further
consideration.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 89 Summary of Changes v.B to V.S 012524.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| HB 89 CS WorkDraft HFIN v.S 010324.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| HB 89 Sectional Analysis v.S 012524.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| HB 89 Sponsor Statement v.S 012524.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| HB 89 Presentation v.S 012424 (2).pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| HB 89 Public Testimony Rec'd by 012425.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| 2024 01 25 HFIN HB 50 DNR CCUS Recap Presentation.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 50 |
| HB 50 CS WorkDraft FIN v.R 012224.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 50 |
| HB 89 TFCC-Recommendations 112023.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| HB 89 Presentation v.S 012424 (3).pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 89 |
| HB050 Summary of Changes version U to R 1.24.24.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 50 |
| HB 50 DNR Responses to HFIN Questions on 012524 2024 02 14.pdf |
HFIN 1/25/2024 1:30:00 PM |
HB 50 |