Legislature(2023 - 2024)BUTROVICH 205
03/10/2023 03:30 PM Senate RESOURCES
Note: the audio ![]()
and video ![]()
recordings are distinct records and are obtained from different sources. As such there may be key differences between the two. The audio recordings are captured by our records offices as the official record of the meeting and will have more accurate timestamps. Use the icons to switch between them.
| Audio | Topic |
|---|---|
| Start | |
| SB49 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | SB 49 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
SB 49-CARBON STORAGE
3:32:37 PM
CO-CHAIR GIESSEL announced the consideration of SENATE BILL NO.
49 "An Act relating to the geologic storage of carbon dioxide;
and providing for an effective date."
3:34:04 PM
JOHN BOYLE, Commissioner-Designee, Department of Natural
Resources, Anchorage, Alaska, stated that his introductory
remarks on SB 49 were based on his recent experience at
CERAWeek. In that venue he was able to speak with
representatives from some of the largest oil and gas companies
that operate in Alaska, private equity groups, financiers, and
infrastructure investment firms. Overall, he said there was
incredible excitement about Alaska's intention to create a
statutory framework to enable carbon capture, utilization, and
storage projects. He characterized hydrogen as critical in
assisting energy transformation and highlighted that a key
component to these activities is managing the CO output from
2
industrial processes.
COMMISSIONER-DESIGNEE BOYLE explained that SB 49 seeks to create
a broad framework for the state to develop a program that allows
leasing, injection, and regulation of carbon dioxide into
underground reservoirs. There is great interest from the broader
investment community and also industry who see the opportunity
to capitalize on the IRS Section 45Q tax credits to help
incentivize new enhanced oil recovery methods utilizing carbon
dioxide while also enabling them to meet the stringent
environmental benchmark of net zero. The administration sees
this as a critical need for the state to address. Having the
framework for this carbon capture, utilization, and storage
program in place will put the state at a competitive advantage
and in prime position to attract capital.
COMMISSIONER DESIGNEE BOYLE stated that the committee will hear
from experts who can talk about Alaska's strategic advantage in
its ownership of broad swaths of state land and the underlying
mineral estate, which makes it simple for companies because it's
a one-stop-shop. It won't be necessary to deal with a myriad of
private landowners, which is often the case in other states and
countries.
COMMISSIONER DESIGNEE BOYLE highlighted the opportunities in
Cook Inlet and on the North Slope for carbon storage in depleted
reservoir space; in the Interior that is very attractive for
carbon capture projects; to extend the life of coal-fired
plants; and for new investors and existing producers and
companies interested in lowering the carbon intensity of their
operations. He also pointed out that because the state's
underground pore space is a mineral asset of the state, 25
percent of the revenue collected from CCUS would be deposited
into the permanent fund. He said this process will take time,
but the administration believes that it is in the state's best
interest to pursue this opportunity.
3:44:06 PM
HALEY PAINE, Deputy Director, Division of Oil and Gas,
Department of Natural Resources, Anchorage, Alaska, reviewed the
outline for the presentation.
1. Introduction
2. CCUS project overview
3. Funding collection and revenue
4. High-level sectional summary
5. Section 14 Detail of DNR/DOG statutes
6. Sections 1531 summary
7. Section 31 Detail of AOGCC statutes
8. Section 3239 summary
MS. PAINE reviewed the constitutional directive under Article
VIII of the Constitution of the State of Alaska.
• It is the policy of the State to encourage the
settlement of its land and the development of its
resources by making them available for maximum use
consistent with the public interest.
• The legislature may provide for the leasing of, and
the issuance of permits for exploration of, any part
of the public domain or interest therein, subject to
reasonable concurrent uses.
3:46:37 PM
MS. PAINE described how SB 49 adheres to the constitutional
directive in art VIII. She spoke to the following:
• Enables the State to maximize use of its pore space
resource consistent with public interest.
• Provides for reasonable concurrent uses and
protection of all parties.
• Empowers the Department of Natural Resources (DNR)
and Alaska Oil and Gas Conservation Commission
(AOGCC) to utilize existing authorities and
expertise on carbon dioxide geologic storage
3:47:50 PM
MS. PAINE displayed the diagram on slide 5 and recapped the
description of carbon capture, use, and storage (CCUS):
Capture
Capturing CO from fossil or biomass-fueled power
2
stations, industrial facilities, or directly from the
air.
Use
Using captured CO as an input or feedstock to create
2
products or services.
Transport
Moving compressed CO by ship or pipeline from the
2
point of capture to the point of use or storage.
Storage
Permanently storing CO in underground geologic
2
formations, onshore or offshore.
She noted that the target reservoirs would be depleted oil
and gas reservoirs, saline aquifers, and potentially
unmineable coal seams.
SENATOR KAWASAKI asked how DNR knows there is enough space for
sequestration in any of those geologic formations.
3:49:37 PM
MS. PAINE answered that it's possible to do predictions and
engineering calculations based on the well data and pressure
logs to determine how much oil and gas the formation held
originally, and extrapolate the size of the container. She
agreed that DNR had not spent much time assessing either saline
aquafers or unmineable coal seams. However, they've learned from
other jurisdictions that saline aquafers tend to be more
expansive than oil and gas reservoirs and have more potential.
She acknowledged that further study and analysis was required.
3:50:41 PM
JOHN CROWTHER, Deputy Commissioner, Department of Natural
Resources, Anchorage, Alaska offered his understanding that
Alaska has the geology and formations to scale that are required
for sequestration and long term storage. He added that any
project would need to move through the characterization stage to
confirm the geology, but Alaska generally has very prospective
and encouraging geology.
3:51:36 PM
MS. PAINE reviewed slide 6 that highlights the reasons to move
forward now with CCUS. It read as follows:
Why Now?
• The CCUS market is rapidly expanding, both within
the U.S. and worldwide
• Federal legislation in the prior 18 months has
included direct grants and tax incentives for CCUS,
increasing industry interest, including outreach to
the Department of Natural Resources (DNR)
• Federal funds are available for states seeking Class
VI well permitting, showing federal support for
state primacy
• Protracted project timelines and milestone
requirements in the tax credit structure necessitate
prompt action
• Sets the stage for continued development of Alaska's
oil resources, and potential major gas development
• Corporations are actively seeking opportunities to
meet their own carbon management goals
3:53:31 PM
MS. PAINE explained that the Safe Drinking Water Act of 1974
established the Underground Injection Control (UIC) Program. To
implement the program, the EPA developed classes of injection
wells based on the characteristics of the injected fluid and the
depth to which it was injected. In 2010 the EPA created Class VI
wells exclusively for the injection of critical CO. She directed
2
attention to the diagram on slide 8 that describes the project
phases of CCUS.
MS. PAINE said the EPA is keen to have states assume primacy and
take charge of permitting for specific wells, especially for
Class II and Class VI wells. AOGCC already has primacy for Class
II wells for oil and gas injection and has experience with more
than 950 injection wells, so the expertise to take on Class VI
wells is already well within their wheelhouse.
3:56:37 PM
SENATOR KAWASAKI asked about the consequence if the legislature
were to decide not to fund 404 primacy.
MS. PAINE answered that a project operator could apply directly
to the EPA for a Class VI well permit if the state doesn't move
forward to assume primacy. The main difference will be that it
takes EPA longer to conduct the review and issue a permit. North
Dakota has primacy and is able to review an application and
issue a permit in about eight months, whereas the timeline for
the EPA is about three years. To date the EPA has only permitted
two Class VI wells. It has about 40 permits pending, but none
are in Region 10.
3:58:15 PM
SENATOR GIESSEL asked whether 404 primacy and Class VI wells
were intertwined, because the question was about the former and
the answer was about the latter.
MR. CROWTHER clarified that 404 primacy and primacy for Class VI
wells were separate authorities, both of which were eligible for
assumption by the state. SB 49 is focused on Class VI wells
under the Safe Drinking Water Act Underground Injection Control
Program.
3:59:02 PM
SENATOR KAUFMAN commented that slides 8 and 9 about the CCUS
project stages and the project timeline were creeping towards a
level one, master control schedule that shows the necessary
tasks. He asked if there was good clarity about what and when
everything needs to occur. He also expressed interest in a more
detailed schedule and knowing about anything that could be done
with existing authorizations.
CO-CHAIR GIESSEL said she'd like Ms. Paine to wait to respond
until all the questions about slide 8 were answered.
4:00:31 PM
SENATOR CLAMAN asked for an explanation of the different
injection well classes.
MR. CROWTHER paraphrased from EPA website.
The Underground Injection Control program consists of
six classes of injection wells. Each well class is
based on the type and depth of the injection activity,
and the potential for that injection activity to
result in endangerment of a USDW.
Class I wells are used to inject hazardous and non-
hazardous wastes into deep, isolated rock formations.
Class II wells are used exclusively to inject fluids
associated with oil and natural gas production.
Class III wells are used to inject fluids to dissolve
and extract minerals.
Class IV wells are shallow wells used to inject
hazardous or radioactive wastes into or above a
geologic formation that contains a USDW.
Class V wells are used to inject non-hazardous fluids
underground. Most Class V wells are used to dispose of
wastes into or above underground sources of drinking
water.
Class VI wells are wells used for injection of carbon
dioxide (CO) into underground subsurface rock
2
formations for long-term storage, or geologic
sequestration.
SENATOR CLAMAN asked over which wells Alaska currently has
primacy.
MR. CROWTHER answered that the state has primacy for Class II
wells.
MS. PAINE added that the EPA allows states to assume a la carte
primacy for Class II and Class VI wells, but all other classes
have to be assumed together. She noted an earlier reference to
AOGCC having the authority to assume Class I primacy but
deciding it didn't need the breadth of the other classes at that
time.
4:03:24 PM
MS. PAINE directed attention to slide 9 and the generalized
project timeline to implement geologic CO storage. She noted
2
that it was adopted from North Dakota so the estimated times are
based on that jurisdiction. She made the following points:
similar The screening phase is a desktop exercise that looks at legacy
data, the CO source, whether the capture technology is
2
reasonably priced, and the distances between the source and
sink to estimate transportation costs.
similar Feasibility is the phase where site-specific data is acquired.
This could include additional seismic surveys, drilling
stratigraphic test wells to get a sense of the subsurface, and
collecting core data. Monitoring stations will be needed to
get baseline data on the conditions in the groundwater and the
atmosphere to inform things as the project moves forward.
North Dakota estimates this to take 9-18 months.
similar Project design and permit application is the phase where the
site-specific information is used to do modeling. The models
look beyond the first injection to estimate the plume at a
particular rate after 10-20 years of injection, and how long
it will take for the plume to stabilize after injection
ceases. Data continues to come in to inform the models. Vendor
contracts, designing the permit, and submitting the
application for the Class VI well permit come at the end of
this phase.
similar Regulatory review of the permit is estimated to take from 7-12
months in North Dakota, with permit approval at the end of the
process. This timeline could be extended in other states.
similar The investment and construction phase has the important IRS
marker for construction to begin by January 1, 2033 to qualify
for the 45Q tax credit.
similar The overall timeline can easily extend beyond four years.
4:07:10 PM
CO-CHAIR GIESSEL noted that Alaska always takes longer, and
asked if there were any lawsuits objecting to states applying
for Class VI primacy.
MR. CROWTHER responded that there is a diverse suit of groups
nationally that support CCUS, including environmental groups
that believe it is appropriately part of carbon management.
There are also groups that argue that CCUS isn't enough of a
solution because it doesn't reduce emissions to zero
immediately. To the question about litigation, he said it has
focused primarily on the transportation of CO over long
2
distances, often interstate. DNR doesn't anticipate legal
challenges in the near term and it would not be over long
distance transport.
4:09:09 PM
SENATOR CLAMAN asked how the Class VI primacy fits into the
timeline and whether that should be part of the evaluation.
MR. CROWTHER responded that primacy should be pursued on the
front end, but it could be at the same time as the screening and
feasibility phases. He added that the value of the state
assuming primacy at the start is that the estimated 7-12 months
for the regulatory review of the permit could easily take more
than 24 months if the EPA were to do the review.
SENATOR CLAMAN summarized that starting the primacy at the same
time as the screening phase would ideally result in the state
having primacy by the time the permits need to be filed. If
primacy hasn't been approved, then the applications go to the
EPA, which is a longer timeframe.
MR. CROWTHER said he agreed generally. The timeline was for a
private sector project developer, so it's a guess how they
choose to proceed as the state initiates the primacy effort.
Given the EPA statement to support state efforts to assume
primacy, a developer might initiate some things
contemporaneously.
Speaking to Senator Kaufman's question about what more the state
could do to promote CCUS developments and investments, he said
there probably are other opportunities the state could pursue,
but it is focused on the three components in SB 49 to assume
Class VI primacy, make state land available, and provide a
regulatory framework through AOGCC.
4:13:08 PM
MS. PAINE continued to slide 10 and the Red Tail Energy Project
to provide context for the timeline. She explained that this was
the first project North Dakota approved under Class VI primacy.
It is an ethanol facility that has a very high concentration of
CO as a byproduct of the fermentation process associated with
2
producing ethanol. The emissions are 180,000 metric tons/year
and the project surface area is about 3,480 acres. She said the
green dot in the image on the left is the injection well, the
white dot to the northwest is the monitoring well that tracks
the plume migration, the purple outline represents the modeled
area for the CO plume to spread over the life of the facility,
2
and the white dotted outline reflects the extent of the storage
facility permit area that can be used. The black dotted outline
reflects the area of review. This is the extent of the area that
is examined and monitored for a Class VI permit. She noted that
the picture on the right was of the exploration well.
4:15:20 PM
MS. PAINE provided the following information about North Dakota
and the Red Tail Energy Project:
similar North Dakota applied for Class VI primacy in 2013.
similar The Red Tail Energy Project started in 2016.
similar It took 5 years for the project to go from site screening to
design.
similar Starting the process was the signal to industry that enabled
the investment decisions to drill the wells, conduct the
seismic, and collect the cores.
similar This shows that some activities can be ongoing during the
primacy application process.
similar North Dakota was granted primacy authority for Class VI wells
in 2018.
similar The Red Tail Energy Project was permitted in 2021.
similar Commercial operation commenced in June, 2022.
She noted that the graphic on the left not only shows the phases
but also provides a feedback loop.
4:16:53 PM
MS. PAINE explained that slide 12 identifies the sections of SB
49 that correspond to the different phases. It shows the
sections associated with exploration and delineation, well and
facility permitting, leasing, storage operations, facility
closure, and post-closure. She noted that Sections 14 and 31 are
the primary sections, but overall the legislation addresses
everything an investor needs to know throughout the process.
4:17:49 PM
MS. PAINE advanced to slide 13 to review the four project
authorizations included in SB 49. She spoke to the following:
Carbon Storage Exploration License - issued by DNR
• Grants exclusive right to explore area for carbon
storage site
• 5-year term
• Work commitment and annual rental requirements
• Conversion to lease based on obtaining Carbon
Storage Permit and completion of work commitment
• Does not authorize specific activities require
further permits
SENATOR WIELECHOWSKI said he assumes the wells that will be used
to store the CO are those whose leases have expired, so the
2
state would not be faced with buying back leases.
MS. PAINE answered that buying back leases is not anticipated.
There are opportunities for existing lessees to use CO for
2
enhanced oil recovery and transition to carbon sequestration,
and for an existing oil and gas lessee to obtain a carbon
storage license. Carbon storage does not condemn or end an
existing property right or lease.
SENATOR WIELECHOWSKI asked if the expectation was for the state
to lease the carbon storage sites to private entities who will
run and manage them.
MS. PAINE confirmed that the state, through DNR, would be acting
as the landowner who leases the land for a fee. AOGCC will be
the regulator on the project to ensure subsurface protections.
SENATOR WIELECHOWSKI mentioned $2.50 and asked how much the
state might be expected to receive.
MS. PAINE requested clarification that he was asking about the
overall revenue from a CCUS project.
SENATOR WIELECHOWSKI mentioned the $85 45Q tax credits and asked
whether the state would receive $2.50 and the lessee $82.50.
MS. PAINE said $2.50 is a floor; the actual fee will be
negotiated as part of the exploration license and based on the
size of the area. She also pointed out that the lessee has costs
associated with capture, transportation, and operation of the
injection facility. She said the per ton injection fee is just
one way to realize revenue; others include sharing the 45Q tax
credits, bonus bids, and gross revenues.
SENATOR WIELECHOWSKI asked if the expectation was that an oil
and gas company could lease out a well and write that off their
corporate income taxes.
4:24:23 PM
MR. CROWTHER suggested the Department of Revenue (DOR) speak to
the question specifically, but his understanding was that
allowable lease expenditures under existing law are for the
production of oil and gas. In some circumstances that can
include enhanced oil recovery, but not projects solely for
carbon storage and sequestration.
CO-CHAIR GIESSEL said the committee could have DOR testify to
that specifically.
4:25:34 PM
MS. PAINE continued to discuss the project authorizations
described on slide 13:
Carbon Storage Facility Permit - issued by AOGCC
• Approves use of subsurface storage "container"
• Amalgamates pore space based on geological and
engineering data
• Provides for protection of other mineral and
property interests
• Establishes monitoring and bonding requirements
• Guides operations over the life of the project.
Carbon Storage Lease - issued by DNR
• Exclusive right to store CO in reservoir on state
2
lands as defined under the Storage Facility
Permit
• Includes terms for revenue to the state
• Valid over life of injection and site closure
• Required for EOR reservoirs that transition to
sequestration
Closure Certificate - issued by AOGCC
• Operator may apply at least 10 years post-
injection
• Public notice & hearing
• Must demonstrate stabilization of CO plume and
2
remediation activities complete
• Title to CO and long-term monitoring and
2
maintenance transfer to state
• Funded by carbon storage trust fund over life of
project
4:29:16 PM
MS. PAINE advanced to slide 14 and described the ongoing
oversight during the CO injection phase to ensure it is behaving
2
as modeled:
• Onsite inspection program
• Wellwork sundries
• Drilling permits
• Monthly reports
• Metering
• Injection
• Volumes
• Pressure surveys
• Well logs
• Data from monitoring wells
• Plume monitoring
4:30:07 PM
MS. PAINE advanced to slide 16 to describe funding sources:
Regulatory Program
AOGCC
• Carbon Dioxide Storage Facility Administrative
Fund
• Sec. 31: AS 41.06.165
• Creates fund to cover AOGCC operating costs
associated with oversight of carbon storage,
like fees collected for oil and gas oversight
• Income account revenue sources:
• Fees received under AS 41.06.165(a) - per
ton fee
• Fees received under AS 41.06.125 (permit
review) and 41.06.200 (determining storage
amounts)
• Earnings on the fund
Leasing & Licensing State Lands
DNR
• Carbon storage exploration licenses and leases
• Sec. 14: AS 38.05.710 & AS 38.05.720
• Establishes a minimum rental rate of $20 per
acre.
• Establishes a minimum injection charge of
$2.50 per ton of carbon dioxide
• Other commercial terms as applicable
• Sec. 14: AS 38.05.735
• Payments from carbon storage exploration
licenses and carbon storage leases flow to
the general fund and Alaska Permanent Fund
(Art. IX, Sec. 15, Alaska Constitution)
4:32:07 PM
SENATOR WIELECHOWSKI asked 1) where the $20 and $2.50 rates came
from and 2) is there a legal requirement to deposit the
percentage into the permanent fund.
MS. PAINE answered that DNR established the $20 rental rate and
$2.50 injection charge as minimums after surveying the publicly
available data. They're floors similar to what the state
established for the oil and gas regime. She deferred the second
question to Mr. Crowther.
MR. CROWTHER said DNR understands the pore space to be a mineral
resource, which is obligated to be deposited into the Alaska
Permanent Fund. A Supreme Court case related to the Cook Inlet
Natural Gas Storage (CINGSA) facility also identified pore space
used for storage as a mineral resource.
4:34:25 PM
MS. PAINE advanced to slide 17 to discuss the funding for the
carbon storage closure trust fund:
Sec. 4: AS 37.14.850. Carbon storage closure trust
fund.
• Industry-funded and state-administered trust fund
to be used solely for long-term monitoring of the
site during the Post-Closure Period
• Income account revenue sources:
• Payments received under AS 37.14.850(c)
• AS 41.06.180. Carbon storage facility injection
surcharge (Bill Sec. 31)
• Amount set by AOGCC on issuance of storage
facility permit
• Based on anticipated expenses to be incurred
post-closure phases
• Earnings on the account
• State may utilize funds directly or purchase
policies as markets mature
4:35:54 PM
MS. PAINE advanced to slide 18 to discuss three hypothetical
revenue opportunities:
1. Regional Power Facility
• 250,000 metric tons/year, $2.50 metric ton/year
• 20-year life
• Acreage ~1200 acres during injection, $20
acre/year
2. North Slope Emitting Facility
• 2,000,000 metric tons/year (50/50 EOR &
Storage), $2.50 metric ton/year (Storage)
• 20-year life
• Acreage ~10,000 acres during injection, $20
acre/year
3. CO Import & Sequestration Facility
2
• 10,000,000 metric tons/year, $2.50 acre/year
• 40-year life
• Acreage ~ 50,000 acres during injection, $20
acre/year
MR. CROWTHER restated that the foregoing were hypothetical
projects so they do not forecast the cost to capture the
emissions. The intention was to show that if the project occurs,
these were the kinds of revenue that could be expected under SB
49 as currently drafted.
4:38:42 PM
SENATOR CLAMAN asked if the idea in the third example was for a
third party to capture the carbon, transport it to Alaska, and
pay the state for storage.
MR. CROWTHER responded in the affirmative.
SENATOR CLAMAN asked whether the department had identified an
entity that would capture the carbon and transport it to Alaska
for storage, because the cost of transportation could be rather
expensive.
MR. CROWTHER agreed that in that scenario the transportation of
the CO would be a major cost. He also mentioned the presenter
2
earlier in the week who talked about barging CO over short
2
distances as well as trans-ocean shipping and the potential to
drive the cost of transport down.
4:41:32 PM
MS. PAINE advanced to slide 19 and described the following
hypothetical revenue opportunities:
• Not all CO emissions are feasibly captured
2
technology continues to rapidly develop
• Capital expenditures to retrofit existing
facilities cannot be met by existing incentives
in some cases
• Import of CO is dependent on further development
2
of shipping technology and infrastructure
• Timing from bill passage, if project through
screening phase:
• Licensing Revenues < 2 years
• Leasing Revenues < 5 years
CO-CHAIR GIESSEL asked if she previously said a project had to
start by 2032
MS. PAINE confirmed that construction has to start by the end of
2032 to qualify for the 45Q tax credit.
CO-CHAIR GIESSEL commented that sooner was better to pass this
policy.
MS. PAINE agreed.
4:43:49 PM
MS. PAINE directed attention to the chart on slide 20 that shows
the hypothetical revenue opportunities in the three hypothetical
scenarios for the use of the state's pore space She opined that
the numbers were a fair representation of lifetime revenues for
both a small and large project.
CO-CHAIR GIESSEL asked whether the state or producer would incur
the cost of insurance.
MR. CROWTHER answered that the chart focuses on the acreage
rental fee and the injection fee, which would be deposited into
the administrative fund. That revenue would accumulate over time
for the long-term liability of the state, so DNR doesn't
envision the state needing to participate in the insurance
market. However, an operator might choose to purchase insurance
to cover its operations.
4:45:47 PM
SENATOR KAUFMAN offered his understanding that hypothetical
scenario 2 (North Slope Facility Standalone CCUS Project) did
not anticipate shipping CO to the North Slope.
2
MR. CROWTHER confirmed that the example was based on the
existing North Slope Central Gas Processing Facility.
4:46:39 PM
MS. PAINE transitioned to the sectional summary of SB 49,
starting with Sections 1-14 on slide 22. She noted that she
would provide more detail on sections 14 and 31.
Section 1
Short title of bill: Carbon Capture, Utilization, and Storage
Act
Section 2 (AOGCC)
Grants AOGCC jurisdiction to regulate carbon storage unit
operations in the state like oil and gas (bill Sec. 14)
Section 3 (AOGCC)
Authorizes AOGCC to seek primary enforcement authority for
permitting and regulating Class VI injection wells for CO
2
Section 4 (DNR/AOGCC)
Creates Carbon Storage Closure Trust Fund to provide non-
sweepable fund for post-closure operations of State agencies
(bill Sec. 31, proposed AS 41.06.180)
Section 5 (DNR)
Adds carbon storage (bill Sec. 14) to mineral estate disposal
exemption for agricultural lands disposal in AS 38.05.069(e)
Section 6 (DNR)
Adds carbon storage (bill Sec. 14) exemption to AS 38.05.070(a)
for when state lands are leased for purposes other than
extrication of natural resources
Section 7 (DNR)
Adds carbon storage to provisions requiring lessees to pay
damages to landowners and to post bonds for that purpose; and
providing lessee access to access to the mineral estate if a
surface owner refuses to engage in a surface use agreement; this
is the same statutory process that exists for other mineral
estate development of split estate created by AS 38.05.125
4:49:00 PM
SENATOR WIELECHOWSKI paraphrased the first sentence of Section 7
and asked what kind of liability SB 49 exposes the state to in a
worst case scenario, and whether the state expected to purchase
insurance for such damages.
MS. PAINE responded that it was an existing provision in all oil
and gas leases and it had never been used. As a general rule,
the surface owners and project operators resolve any issues to
their mutual benefit. She also pointed out that this was just
for the surface estate and that the footprint of a carbon
storage facility was very small.
4:50:45 PM
MS. PAINE continued the sectional summary.
Sections 811 (DNR/DOG)
Adds carbon storage program (bill Sec. 14) to mineral leasing
statutes under AS 38.05.135, primarily providing for revenue
collection
Section 12 (DNR)
Adds carbon storage provision to exemptions for coal bed methane
under AS 38.05.180(gg) and unconventional gas under AS
38.05.180(ff) because carbon storage leasing might be possible
on unmineable coal seams
Section 13 (DNR)
Adds carbon storage leases to prohibition in the Kachemak Bay
oil and gas closure area
4:51:53 PM
SENATOR WIELECHOWSKI asked if other refuges or areas that
prohibit oil and gas exploration or development could be leased
out.
MS. PAINE answered that nothing was different for carbon storage
leasing than what is allowed for oil and gas leases. Later in
the bill several other areas are excluded, but the same
exclusion applies for oil and gas leases. She restated that the
carbon storage leases are intended to mirror the permissions for
oil and gas leases.
SENATOR WIELECHOWSKI noted the controversy in the MatSu Valley
years ago when drilling for coal bed methane extended under
private property. He asked whether the bill envisions CO being
2
stored under private property.
MR. CROWTHER answered that provisions later in the bill speak to
AOGCC's authority to amalgamate property interests from
unconsenting parties, which is similar to the authority that's
available for oil and gas.
4:54:22 PM
SENATOR WIELECHOWSKI asked about the liability associated with a
storage facility extending under an unconsenting landowner's
property.
MR. CROWTHER said he's neither a geologist nor an engineer, but
DNR envisions that the damages for an unconsenting property
owner would be financial. He continued to explain that the
injections would be very deep and into geologic structures that
make them secure for containing oil and gas or carbon dioxide,
and generally secure from affecting surface properties. He
clarified that there is no relationship to the fracking process.
4:56:28 PM
SENATOR WIELECHOWSKI asked whether property owners who
might not want any pipes or drilling equipment on their
land would be protected.
MR. CROWTHER said Section 7 speaks to that concern, and a
surface owner can be affected. In Alaska, the mineral
estate is dominant so the mineral estate owner, often the
state, has the right to lease for the exercise of those
rights. The existing statute doesn't prohibit the use, but
the operator would be liable for damages incurred by that
use. This might require the operator to proactively post a
bond to prepare for such a conflict.
CO-CHAIR GIESSEL stated that the discussion would continue
on Monday. She held SB 49 in committee.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 49 DNR CCUS Presentation 03.10.2023.pdf |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB 49 Bill Packet.pdf |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB 49 Transmittal Letter 01.26.2023.pdf |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB0049A.PDF |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB0049-1-3-012723-DNR-Y.PDF |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB0049-2-2-012723-CED-Y.PDF |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB0049-3-2-012723-REV-Y.PDF |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB0049-4-2-012723-DEC-Y.PDF |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB 49 Sectional Analysis 2.1.2023.pdf |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB 49 DNR DOG CCUS Bill One-Pager 2.1.2023.pdf |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB 49 Stantec - CCUS Peer-State Review Report January 30, 2023.pdf |
SRES 3/10/2023 3:30:00 PM |
SB 49 |
| SB 49 University of Alaska - Issue and Policy Review for CCUS in the State of Alaska.pdf |
SRES 3/10/2023 3:30:00 PM |
SB 49 |