Legislature(2023 - 2024)BARNES 124
02/24/2023 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB50 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 49 | TELECONFERENCED | |
| += | HB 50 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 50-CARBON STORAGE
1:04:00 PM
CHAIR MCKAY announced that the only order of business would be
HOUSE BILL NO. 50, "An Act relating to the geologic storage of
carbon dioxide; and providing for an effective date."
1:04:54 PM
CHAIR MCKAY stated that Kevin Connors would provide invited
testimony. He noted that the Plains CO2 Reduction (PCOR)
Partnership is focused on carbon capture, utilization, and
storage (CCUS) projects and is affiliated with the University of
North Dakota's Energy and Environmental Research Center (EERC).
He said Mr. Connors has been working with Alaska's university
system on carbon dioxide (CO2) storage projects and will provide
the committee with his insight.
1:06:19 PM
KEVIN CONNORS, Assistant Director, Regulatory Compliance and
Energy Policy, Energy and Environmental Research Center (EERC),
University of North Dakota, provided invited testimony in favor
of HB 50. He said he has a background in geology, worked in the
oil fields of western North Dakota, and worked for the State of
North Dakota as a petroleum engineer. In 2011 he became the
Carbon Capture and Storage (CCS) Supervisor for the State of
North Dakota where he led the state's efforts in developing a
regulatory program for CO2 storage and ultimately obtaining
Class VI primacy. He noted that the pursuit of Class VI primacy
for the State of Alaska is directly related to HB 50.
MR. CONNORS stated that North Dakota's comprehensive framework
for regulating geologic storage dates to 2002 when President
George Bush committed the US to a comprehensive strategy to
reduce greenhouse gas emissions. Funding was put in place for
the US Department of Energy to create the regional carbon
sequestration partnership program, one such program being the
PCOR Partnership, which he manages. The PCOR Partnership has
conducted applied research in CCS and CCUS for 20 years, today
its focus is on an accelerated commercial deployment phase. In
2019 Alaska became part of the PCOR Partnership and since then
the EERC has been a partner with the University of Alaska,
Fairbanks, to advance CCS and CCUS in Alaska.
MR. CONNORS reported that the PCOR Partnership is made up of 240
members representing the oil and gas industry, coal mining
electricity generation industry, gas processing and gas
transportation industry, ethanol industry, software providers,
technology providers, engineering consulting firms, tax equity
firms, companies focused on advancing commercial CCS, government
agencies, and academia. The Alaska portion of PCOR is comprised
of partnerships with the Department of Natural Resources (DNR),
the Alaska Oil and Gas Conservation Commission (AOGCC), and
Hilcorp Energy Company, an industrial partner. Today the PCOR
Partnership is still leveraging federal research dollars from
the US Department of Energy plus industry dollars in its focus
on commercial CCUS deployment.
1:11:07 PM
MR. CONNORS related that the Interstate Oil and Gas Compact
Commission (IOGCC), of which Alaska is a member, developed a
task force comprised of state oil and gas regulators, Department
of Energy representatives, and PCOR Partnership representatives.
This task force ultimately recommended that to best facilitate
orderly development of geologic storage of carbon dioxide, the
states and Canadian provinces should take the lead and embrace
two basic principles: 1) it is in the public interest to
promote geologic storage of carbon dioxide and 2) pore space in
the state should be regulated and managed as a resource under
resource management framework.
MR. CONNORS said HB 50 is a resource management framework that
dates to the IOGCC task force's development of a model statute
and model regulations in 2007. North Dakota customized that
model statute to its needs and in 2009 adopted legislation
similar to HB 50 to regulate geologic storage of CO2 and to
regulate pore space as a resource under a resource management
framework. North Dakota then applied for and received Class VI
primacy. North Dakota's decisions in 2008 with the work group
and ultimately with the state legislature were focused around
providing regulatory certainty for an eventual CCUS industry.
MR. CONNORS specified that to have a commercial CCUS industry or
investment in developing CCS projects, it is important to have
an energy industry, the right geology for geologic storage of
carbon dioxide, research and development, and regulatory
certainty. Both Alaska and North Dakota have energy producers
and exporters. Work has been done and will continue to be done
demonstrating that Alaska has suitable geology. Continued
research and development through the partnership of UAF and the
PCOR Partnership is positioning Alaska from a technical
standpoint. Policy and regulation play the role of regulatory
certainty for CCS and CCUS. Because of legislation similar [to
HB 50], and a law in place, and Class VI primacy, North Dakota
has a CCUS industry, investment coming into the state, and
projects being developed.
1:15:08 PM
MR. CONNORS related that he helped develop the State of North
Dakota's regulatory program during his eight years with the
state. Today at the EERC he works directly with the industry to
help develop CO2 storage projects, site screening through
feasibility and characterization, permitting, and operation and
monitoring of active sites from a commercial standpoint. To
date, North Dakota has permitted four projects, a fifth project
will be heard in March [2023], and several other projects are in
the earlier stages of development. The first commercial storage
project in North Dakota went into operation in June 2022. The
driver of this activity and investment is North Dakota's
regulatory certainty that began 15 years ago in legislation
similar to [HB 50].
MR. CONNORS pointed out that if a state doesn't have Class VI
primacy, the US Environmental Protection Agency (EPA) is the
regulatory authority for this activity. He said North Dakota
and Wyoming are the only two states with Class VI primacy,
everywhere else the EPA regional office is regulating this
activity. As of this morning, 42 permit application are in with
the different EPA regional offices across US, none of which have
approved. Today Illinois has two approved permits that are in
operation, and those permits took over five years for the
operator to get approval. In contrast, North Dakota with Class
VI primacy and the proper statutes in place, has issued permits
in less than a year for those core projects that have been
permitted.
1:18:36 PM
REPRESENTATIVE MEARS requested further clarity on how the PCOR
Partnership works.
MR. CONNORS explained that the PCOR Partnership receives funding
from its 240 member organizations and the US Department of
Energy. The commercial industry in North Dakota and across the
US has launched off the technical foundation built by PCOR
through its 20 years of research and development in CCUS.
Geologic characterization work done by PCOR identifies the ideal
geology for geologic storage of carbon dioxide, i.e. where to
inject and store large volumes of carbon dioxide. Another focus
of PCOR is infrastructure development. As well, PCOR is focused
on developing a prudent regulatory framework by engaging
regulators across the region. The public outreach component of
PCOR identifies challenges and finds solutions to them so there
can be accelerated commercial deployment. The PCOR Partnership
started out trying to determine whether CCS was possible, which
led to field testing and commercial demonstration. Today PCOR's
focus is on commercial deployment. Alaska came into the PCOR
Partnership in 2019, and the state's geology and industry are
being looked at, and a real opportunity is seen for commercial
deployment of geologic storage of carbon dioxide in Alaska.
1:21:02 PM
REPRESENTATIVE SADDLER, regarding North Dakota's CCUS industry
now entering the commercial development stage, asked what has
worked and what has not worked as originally envisioned.
MR. CONNORS answered that North Dakota has an 800-year supply of
lignite coal with the electricity it generates exported to other
states, so it's important to North Dakota's economy to be able
to utilize that resource well into the future. In 2008 North
Dakota's work group saw CCS as a great opportunity or solution
for North Dakota's long-term viability, specifically its coal
and power industries. It was known at that time that the
state's geology looked ideal for geologic storage and the work
group was anticipating future advancements in capture
technology, which are here today. The change is that today it's
not only the coal and electricity generation industry pursuing
carbon capture and storage projects and investment, but that
there's also a large interest from the state's oil and gas, gas
processing and gas transportation, and ethanol industries.
While those industries are robust in North Dakota, their
emissions are carbon intensive. Managing or reducing the carbon
intensity of those industries is being seen as an opportunity
that will allow those industries to thrive and grow over time.
The seeds of frameworks and policy that were sowed in 2008 and
2009 are bearing fruit today with North Dakota's major
industries being able to pursue carbon capture and storage.
1:24:10 PM
REPRESENTATIVE SADDLER inquired about what has been a surprise
and not developed as was thought it would.
MR. CONNORS responded that there haven't been many surprises in
North Dakota. However, the surprise has been the federal
government's inability to provide states this authority given
that the preamble to the federal Class VI rule, published in
2010, recognized that states are best suited to regulate this
activity. It took five years for the EPA to approve North
Dakota's Class VI program although, granted, North Dakota was
the first. Wyoming was second and it took the EPA about 2.5
years. Louisiana's application was submitted to the EPA about
1.5 years ago and is still pending approval. There is some
reluctance and it's a slower process than it should be to
provide states with primacy. North Dakota, Wyoming, Montana,
Nebraska, and Utah have adopted similar legislation to HB 50.
1:26:20 PM
REPRESENTATIVE MCCABE stated that the question for Alaska is
whether it's worth the fiscal note of about $1.2 million. He
surmised that Mr. Connors would say it's well worth the money
since North Dakota's coal, oil and gas, and gas transportation
industries are thriving because of what the state's legislature
did five or six years ago.
MR. CONNORS clarified that what is wanted is for North Dakota's
industries to be able to thrive through carbon management as a
potential solution. In 2001, North Dakota's governor announced
the ambitious goal of the state becoming carbon neutral by 2030.
With that announcement and North Dakota having Class VI primacy,
the state focused or reducing the carbon intensities of its
energy industries. The decisions made 15 years ago have driven
over $15 billion in investment into the state for this economic
opportunity related to managing the carbon emissions associated
with its energy and agriculture industries.
1:28:56 PM
REPRESENTATIVE SADDLER noted that North Dakota is the home of
the fracking revolution and the benefits that it brought to the
state. He asked what the current interplay is between the
existing oil and gas industry in North Dakota and the nascent
carbon capture and storage industry. He further asked about the
kind of facilities that are injecting CO2 through the four
permits.
MR. CONNORS, regarding the interplay, answered that the
technologies, engineering, and advancement in geologic storage
have all been derived from the oil and gas industry to the point
that [North Dakota] wouldn't be where it is today without that
industry. Now there is an opportunity in North Dakota to have
both saline storage and wide-scale CO2 enhanced oil recovery
(EOR). The Bakken Formation requires the advanced technology of
horizontal drilling and hydronic fracturing to be as prolific
and productive as it is, and CO2 enhanced oil recovery is being
looked at for the future of the Bakken. The 45Q tax credit is
driving saline storage projects or geologic storage projects and
the infrastructure that is built for that. The long-term vision
is carbon management with both CCS and CCUS utilizing that CO2
to maximize the recovery of both unconventional (the Bakken) and
conventional oil and gas resources in North Dakota. This is a
great opportunity to maximize those resources and to allow the
CO2 that's stored in association with EOR to be counted toward
reducing carbon emissions and ultimately creating a low carbon
intensity oil.
MR. CONNORS, regarding the four permits, answered that the first
commercial project permitted by North Dakota was a single
ethanol plant that sits on phenomenal geology. At an emission
of about 180,000 metric tons of CO2 per year, this small-scale
project was permitted in eight months, and the injection of CO2
began in June [2022]. The second and third permits were
submitted at the same time by Minnkota Power Cooperative as they
were for a stacked storage situation in the subsurface right
below its coal fired power plant, and both permits were approved
at the same time. Regarding the fourth permit, since 2000 the
Great Plains Synfuels Plant has been applying gasification to
lignite coal, capturing the CO2, and transporting about two
million tons a year by pipeline to the oil fields in southern
Saskatchewan. About a million metric tons of CO2 a year were
not being captured, so the EERC worked with Basin Electric to
characterize the geology directly underneath its Canton City
facility, and that permit was approved just [last month].
1:33:59 PM
REPRESENTATIVE ARMSTRONG recalled Mr. Connors' statement about
$15 [billion] in investment having come into North Dakota. She
asked whether the program is profitable [to the State of North
Dakota] and, if so, how long after receiving primacy it took for
the program to become profitable.
MR. CONNORS clarified that the State of North Dakota is not
necessarily receiving that money, rather the $15 billion in
investment was within the state for developing CCS sites,
including infrastructure development, building capture units,
and building multi-state pipelines to bring CO2 into the state.
He said North Dakota applied for Class VI primacy in 2013 and
was awarded primacy in 2018. Also in 2018, [Congress] amended
the 45Q tax credit by increasing the value of the tax credit for
saline storage and CO2 storage for EOR. Industry didn't
immediately react because there was uncertainty with the
amendments, but once the IRS created certainty by coming out
with guidance documents and a rule making, the scales tipped for
the economics of these projects and lots of interest from
industry started to be seen. In 2022, the Inflation Reduction
Act bumped up the 45Q tax credit for saline storage, CO2
enhanced oil recovery, and direct air capture. Today that
federal incentive is a major driver for commercial projects in
North Dakota and across the US.
1:36:51 PM
REPRESENTATIVE ARMSTRONG surmised that revenue coming into the
State of North Dakota's treasury may not be the goal, but rather
the ancillary benefits around investment and supporting oil,
gas, and coal within the state. She asked how much the State of
North Dakota must outlay over how many years to stand up the
program before it becomes profitable to the state treasury.
MR. CONNORS answered that he doesn't want to speak for the State
of North Dakota in that aspect, but he can speak to the statute
adopted in North Dakota that created the Carbon Dioxide Trust
Fund Account and the Administrative Trust Fund Account. A per
ton fee is associated with the injection of CO2, with part of
the fee going to the Administrative Trust Fund Account and part
to the long-term management fund. The State of North Dakota was
looking for a sustainable regulatory program, thereby providing
certainty for the state's energy and agriculture industries.
1:38:54 PM
CHAIR MCKAY pointed out that since the State of Alaska is the
subsurface owner, [the legislature's] view has a particular bias
towards how much money the State of Alaska is going to make and
how fast its investment in Class VI wells will be recovered.
Because the State of Alaska owns the depleted reservoirs where
the CO2 would [be injected], the state could spend $2-$3 million
initiating a Class VI primacy well process, and then maybe
nothing happens. The committee is therefore trying to get a
feel for how other states that own the subsurface mineral rights
have dealt with that situation.
MR. CONNORS confirmed North Dakota's situation is much different
because pore space ownership is the surface owner, and that is
predominantly privately owned pore space. So, the projects that
are going to be developed are acquiring privately owned pore
space for the most part. In Lower 48 states with state trust
lands, revenue is generated from access to pore space or pore
space leasing. He said he can't answer anything specific to
Alaska and the potential revenues because that isn't his area of
expertise.
MR. CONNORS pointed out that until CO2 storage came around, pore
space had no value, but today that geologic formation has value
and [is providing] economic opportunity. He explained that pore
space leasing is not a one-size-fits-all because each project
has different economics associated with it and therefore
different ability to pay for pore space access. A coal fired
powerplant has different economics than an ethanol production
facility and different economics than a natural gas processing
facility from which CO2 is being captured. There are different
values for CO2 based on the tax credit and other types of
markets. The Midwest US ethanol industry accelerates CCS
because there are other carbon markets for the ethanol product
that is produced.
1:42:38 PM
CHAIR MCKAY asked who owns, operates, and drilled the Class VI
wells in North Dakota if the pore space is owned by the private
property owner.
MR. CONNORS answered that these first four permitted projects
are wells that are located on the property of the facility owner
and ultimately the operator. One example is a coal fired
powerplant built in the vicinity of a lignite coal mine and the
coal mining company as the owner of that land is the pore space
owner for the storage project being developed around that site.
However, he noted, the next wave of projects is looking
different than the first wave. Projects are now coming in which
are bringing in CO2 from longer distances by developing
pipelines. They are accessing pore space or accessing the right
to use the surface to build a well pad, drill, and construct
Class VI injection wells on a surface that is currently being
leased for other projects.
1:45:04 PM
REPRESENTATIVE SADDLER, regarding multi-state pipelines, asked
whether North Dakota is accepting CO2 from other sources into
one of the four currently permitted projects. He further asked
whether North Dakota is interested and able to have CO2 from
other states injected into North Dakota pore space.
MR. CONNORS clarified that private investment is building the
multi-state pipelines into North Dakota. He said CO2 enhanced
oil recovery is seen as carbon management and future opportunity
to maximize North Dakota's oil and gas resources, specifically
the Bakken. Carbon dioxide from outside North Dakota is needed
for future CO2 EOR because even if all the stationary sources of
CO2 in North Dakota were pulled together, they wouldn't provide
enough CO2 to flood the Bakken and other oil and gas formations
to maximize recovery. Also, a benefit in general is seen to
North Dakota's agriculture industry because projects are
aggregating multiple ethanol facilities across the Midwest and
bringing that CO2 into North Dakota. So, yes, it's looking like
projects are under development where there is going to be out-
of-state CO2 [coming into North Dakota]. Two gas processing
facilities in Wyoming are catching CO2 and transporting it via
pipeline to southeast Montana and southwest North Dakota, and
Denbury Resources is injecting that CO2 into one of North
Dakota's unconventional fields for EOR.
MR. CONNORS, regarding his statement about the CO2 captured in
North Dakota and transported to southern Saskatchewan, related
that CO2 from the Dakota Gasification Plant has been utilized
for over 20 years and 40 million tons of CO2 has been stored in
the oil fields in southern Saskatchewan.
1:48:44 PM
REPRESENTATIVE MEARS asked whether there are any requirements or
parameters that must be met for putting carbon dioxide into
pipelines.
MR. CONNORS replied that the Pipeline and Hazardous Materials
Safety Administration (PHMSA) has regulated CO2 pipelines for
many years, including CO2 pipelines in Colorado, Texas, North
Dakota, Wyoming, and Montana. There are pipeline specifications
that the transporter wants to see for quality of CO2. The
pipeline routing and siting of those pipelines in [the North
Dakota] region is typically regulated and sited by state public
service commissions that have received authority from PHMSA.
CHAIR MCKAY offered his understanding that CO2 is very
corrosive, so pipelines and wellbores must be designed to
account for the corrosive nature of the gas.
MR. CONNORS clarified that CO2 is corrosive when introduced with
water, so typically water is removed at the point of capture and
the CO2 prepared for transport and injection into the well.
However, as a safety precaution pipelines and wellbores are
designed for the corrosive nature of CO2 when water is
introduced. He offered to speak further on Class VI injection
water requirements, material requirements, and corrosive
monitoring.
REPRESENTATIVE MEARS explained that she asked about parameters
because as this framework for Alaska is being set up, businesses
need to be thinking about utilizing [state-owned] pore space and
what parameters the businesses need to meet.
1:52:09 PM
REPRESENTATIVE SADDLER asked whether North Dakota has had
conflicts between the extractive industries and those that are
injecting CO2 and, if so, how they have shaken themselves out.
MR. CONNORS responded that he's not aware of any conflicts. He
explained that everything being done is derived from the oil and
gas industry, which is very interested in advancing CCS in North
Dakota. Part of the demonstration or application of those
storage projects was identifying any mineral bearing formations,
and state law and regulation ensures that any CO2 storage
activity will not prohibit anyone from developing or extracting
their minerals.
1:53:42 PM
REPRESENTATIVE SADDLER asked whether there was any organized
resistance to the carbon capture and storage industry developing
North Dakota and, if so, what was effective in answering the
skeptics or the critics.
MR. CONNORS answered that there hasn't been any resistance to
developing carbon storage projects. Because pore space rights
and landowner rights are being dealt with today, landowner
groups and landowners have shown concern and that's why it's
important for these projects to be compensating pore space
owners. He contrasted the resource management framework with a
waste disposal framework by explaining that the Class VI
requirements under the EPA's 2010 rule are a waste disposal
framework. The EPA doesn't have the authority under the Safe
Drinking Water Act to account for pore space ownership when it
permits a site, so there are no compensation considerations for
EPA. The EPA is looking for environmental criteria,
specifically the protection of underground sources of drinking
water. When the EPA is the authority, there is no part of that
Class VI application that considers ownership, leasing, or
access to that pore space. That's why it's important for states
to apply for and receive Class VI primacy and for state
legislatures to enact pore space laws and pore space ownership
considerations. An operator, in his opinion, could come into
Alaska or other states that don't have pore space ownership
defined in legislation, apply to the EPA regional office for a
Class VI permit, and be injecting CO2 without necessarily
compensating for pore space.
1:57:00 PM
CHAIR MCKAY remarked that talking to an entity already doing
this provides better understanding and comfort with the concept
and the project.
REPRESENTATIVE MEARS commented that she would like more time to
explore current projects to get a better feel of what Alaska's
future may be. While ethanol from agriculture isn't something
Alaska is going to have, she said, there are probably lessons to
be learned from those projects.
1:57:56 PM
REPRESENTATIVE SADDLER asked Mr. Connors whether he would like
to give legislators any advice as the committee considers carbon
capture and storage in Alaska.
MR. CONNORS stated he would like to provide future presentations
in person. He advised that passage of HB 50 is a key part of
Alaska's future ability to manage carbon dioxide emission while
having a thriving energy industry. The geology and the industry
don't go anywhere without the policy and the laws in place,
followed by the regulatory frameworks. Also, there is interest
and investment in direct air capture (DAC), which is still in
demonstration and small scale, but once DAC becomes upscaled
Alaska will have an opportunity with that technology and
industry. Another opportunity is the hydrogen economy, and the
storage component associated with that. Mr. Connors further
advised that besides advancing HB 50, he recommends applying for
and pursuing Class VI primacy, coupled with a resource
management framework, not just adopting the waste disposal
framework. Making it a resource management framework will give
Alaska all the tools it needs to manage the carbon emissions
associated with Alaska's industries and to have a great future.
2:00:34 PM
REPRESENTATIVE DIBERT requested more information about North
Dakota's "Management Fund."
MR. CONNORS explained that that was the IOGCC's early work and
that states need to regulate a few key pieces that fall outside
of the Class VI framework. One piece is the pore space
ownership/property rights issues. Another piece is when a
storage project comes to an end and the site is closed, which
falls in the resource management framework that was developed by
the IOGCC and adopted by North Dakota. A few other states,
including Wyoming, are also pursuing that. During the post-
closure phase, the operator demonstrates that the CO2 is stable,
the wells are properly closed and plugged, and the site is
reclaimed. The long-term monitoring function or caretaker role
for the stored CO2 is then taken on by the state and is funded
by a trust fund account that was paid throughout the operational
life of the project. Through an understanding derived from the
oil and gas industry, the IOGCC recognized the need for a long-
term caretaker role by state government because companies
dissolve, change hands, or go into bankruptcy.
2:03:28 PM
REPRESENTATIVE MCCABE asked whether direct air capture would
reduce PM2.5 [particulate matter 2.5 micrometers or less in
diameter] by taking out the solids and injecting the CO2.
MR. CONNORS stated he can't provide an answer because that isn't
part of his expertise. Regardless of what the capture facility
looks like, whether it's direct air capture or retrofitting a
coal plant, the key is having the right geology for storing the
captured CO2. Storage is typically at a depth of 2,600 feet
because the CO2 at the surface is being compressed to
supercritical state. Dense phase CO2 is a smaller molecule and
the smaller the molecule the more that can be stored, so a
certain subsurface depth is needed to maintain the temperature
and pressure. Also needed is the right formation to receive the
CO2, with cap rock above and below, and low-quality or saline
water within that formation, or a depleted reservoir.
2:06:04 PM
REPRESENTATIVE SADDLER noted that in Prudhoe Bay, CO2 or natural
gas is produced and then reinjected into the same reservoir,
whereas in the Bakken, CO2 from outside the system is used to
enhance oil recovery. He surmised the CO2 must forever remain
in the ground in a closed loop to obtain the 45Q tax credit.
MR. CONNORS confirmed Representative Saddler is correct. He
said the EERC, the PCOR Partnership, and other research groups
have done work to demonstrate that CO2 injected for EOR is
storage. It is associated storage versus dedicated storage,
which is how geologic storage of carbon dioxide is referred to.
The injected CO2 mixes with the oil, causing the oil to swell
and flow more easily, thereby recovering oil that wasn't
technically recoverable without the CO2. The CO2 is replacing
itself into the pore throat that the hydrocarbon moves out of,
so some CO2 stays in the reservoir. It is correct that when oil
is produced to the surface some CO2 is produced with it. But
the work done has demonstrated that it is a closed system, so
once it enters the system it stays in the system and there is a
tax credit available for that. More work needs to be done in
tight oil formations like the Bakken. Most of the CO2 used in
CO2 enhanced oil recovery is naturally occurring CO2 that is
found in the subsurface and extracted for use in enhanced oil
recovery. A big picture vision for the US in general, but not
necessarily North Dakota, is anthropogenic CO2, which is manmade
CO2 that is captured off major industries and stored in
association with enhanced oil recovery.
2:09:19 PM
REPRESENTATIVE SADDLER surmised that there is an obligation to
forever store the CO2 used for EOR and for which the 45Q tax
credit was obtained. He further surmised that when oil is
produced using EOR, the CO2 would have to be scrubbed out and
reinjected. He offered his assumption that there is a way to
measure and monitor the CO2 to ensure that the same amount for
which a tax credit was claimed is under control for forever.
MR. CONNORS confirmed Representative Saddler is correct. He
said there is a long technical history of this. That CO2 has
value, and the oil industry doesn't want to lose any of that
value. If CO2 is being produced, it is separated out and
recycled back into the system. To receive the 45Q tax credit it
must be shown that the CO2 is permanently stored and won't be
released to the atmosphere.
2:10:54 PM
CHAIR MCKAY offered the committee's appreciation for Mr.
Connors' presentation. He noted that the Department of Natural
Resources (DNR) will be before the committee on [2/27/23] to
present a big-picture financial flowchart that will provide an
understanding of the potential risks and benefits of HB 50. He
invited committee members to ask other questions of DNR.
2:13:18 PM
REPRESENTATIVE MCCABE related the concerns of a citizen about
this possibly causing an earthquake. He offered his assumption
that an environmental impact statement (EIS) or some other sort
of study would be required by the National Environmental
Protection Act (NEPA), or the EPA, or Alaska's Class VI primacy.
2:14:16 PM
JOHN CROWTHER, Deputy Commissioner, Office of the Commissioner,
Department of Natural Resources (DNR), responded that DNR
doesn't do an EIS for projects on state land, rather the
department does a best interest finding (BIF), which includes an
analysis of the surface impacts, surface activities, and
environmental impacts. A BIF would be a part of DNR's analysis
for these at the leasing level when an exploration license or
lease is issued. Also, specific development project approvals
consider things like environmental impact and footprint.
Similarly, the Alaska Oil and Gas Conservation Commission
(AOGCC) during its regulatory efforts to monitor the wells and
assess the safety, will consider the environmental impact of
those wells to ensure that the injection proceeds without
releases or migration to other reservoirs.
2:15:13 PM
REPRESENTATIVE MCCABE reiterated that he is hearing concern from
folks that the legislature is rushing into this, and
environmental disasters will be created. He said he needs
reassurance that the money being spent right now is for the
necessary statutory framework to allow carbon storage to move
forward and that the EISs, BIFs, or [Class] VIs cannot start
without defining where [the state] wants to go.
MR. CROWTHER confirmed that the intent is to put a framework
into place.
REPRESENTATIVE SADDLER noted that Alaska currently has in place
an oil and gas leasing framework that allows enhanced oil
recovery, which includes injection of CO2 into underground
basins. The legislature, he continued, is now considering a
parallel CO2 injection framework that will allow the injection
of CO2 into underground basins. He asked whether there is any
record or experience of earthquakes being caused by injection of
natural gas and CO2 into the ground on the North Slope.
MR. CROWTHER qualified that he isn't a geologist, but said he
understands that no seismic activity has been seen on the North
Slope associated with the 40-50 years of heavy-duty compression
and reinjection of that gas. The North Slope is not a very
seismic reactive area and the few earthquakes that have occurred
were attributed to the general geologic factors of the area. In
prior testimony, state geologist Dr. David LePain said that
seismic events associated with injection have not been
identified as an area of concern. [On the North Slope], the
intent of injecting carbon dioxide is to maintain the reservoir
quality by not creating structural changes to the geology. It
is true that in some areas of the US some small seismic activity
has been attributed to injecting highly compressed things to
purposely fracture formations. However, the goal and the
regulatory limitation is to not do that with CO2 injection.
2:19:14 PM
CHAIR MCKAY requested Mr. Huber of the AOGCC to also answer
Representative Saddler's question. He said he can't remember a
time when a specific earthquake was caused by oil and gas
activities in the Kenai area or the North Slope. He offered his
understanding that the AOGCC would tightly regulate the whole
operation subsurface.
BRETT HUBER, Commissioner, Chair, Alaska Oil and Gas
Conservation Commission (AOGCC), confirmed that the AOGCC has
the regulatory authority in this area. He said the AOGCC has a
very thorough permitting process and would consider such things
as formation integrity, geologic integrity, well pressures,
field pressures, injection pressures, and all the things that
AOGCC does now as a matter of course with Alaska's oil and gas
businesses. The AOGCC is dealing with cycling and enhanced oil
recovery and injection in those areas, and to AOGCC's knowledge
there hasn't been any injection-caused earthquake activity, even
in Cook Inlet. The injection has been at depths greater than
the fracture zone and while he wouldn't say it is impossible, he
would say it is extremely unlikely and hasn't been observed so
far. Neither of the two ways to create seismic events would be
approved if it came to the AOGCC.
2:21:24 PM
CHAIR MCKAY stated that Legislative Legal Services has requested
a committee substitute (CS) for HB 50 to address technical
issues that the legislature's lawyers flagged upon reviewing the
bill, which was drafted by the governor's legal team [prime
sponsor of HB 50 is House Rules by request of the governor].
The committee has requested further changes to address issues
that the administration brought to the committee's attention as
needing further clarity. Members will have an opportunity to
offer amendments before the bill leaves committee. Drafting and
adopting a CS to address issues does not imply that the members
of this committee are sponsors or supporters of the bill, HB 50
is always going to be a governor's bill.
2:23:18 PM
CHAIR MCKAY announced that HB 50 was held over.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 49 Transmittal Letter 01.26.2023.pdf |
HRES 2/24/2023 1:00:00 PM HRES 3/8/2023 1:00:00 PM |
HB 49 |
| HB 49 Sectional Analysis 2.1.2023.pdf |
HRES 2/24/2023 1:00:00 PM HRES 3/8/2023 1:00:00 PM |
HB 49 |
| HB 49 Carbon Offset Bill Overview 2.1.2023.pdf |
HRES 2/24/2023 1:00:00 PM HRES 3/8/2023 1:00:00 PM |
HB 49 |
| HB 49 - Alaska DNR Carbon Offset Opportunity Evaluation August 2022 Report.pdf |
HRES 2/24/2023 1:00:00 PM HRES 3/15/2023 1:00:00 PM |
HB 49 |
| HB 49 - Carbon Offset Opportunity Evaluation Appendix_A.pdf |
HRES 2/24/2023 1:00:00 PM |
HB 49 |
| HB 49 - Carbon Offset Opportunity Evaluation Appendix_B.pdf |
HRES 2/24/2023 1:00:00 PM HRES 3/15/2023 1:00:00 PM |
HB 49 |