Legislature(2023 - 2024)BUTROVICH 205
04/24/2024 03:30 PM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB50 | |
| Confirmation Hearing Alaska Commercial Fisheries Entry Commission | |
| HB50 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| *+ | HB 50 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
HB 50-CARBON STORAGE; COOK INLET OIL AND GAS
3:31:46 PM
CO-CHAIR GIESSEL announced the consideration of CS FOR HOUSE
BILL NO. 50(FIN), "An Act relating to carbon storage on state
land; relating to the powers and duties of the Alaska Oil and
Gas Conservation Commission; relating to carbon storage
exploration licenses; relating to carbon storage leases;
relating to carbon storage operator permits; relating to
enhanced oil or gas recovery; relating to long-term monitoring
and maintenance of storage facilities; relating to carbon oxide
sequestration tax credits; relating to the duties of the
Department of Natural Resources; relating to carbon dioxide
pipelines; and providing for an effective date."
3:32:01 PM
CO-CHAIR BISHOP joined the meeting.
3:32:17 PM
SENATOR CLAMAN joined the meeting.
3:33:41 PM
JOHN CROWTHER, Deputy Commissioner, Department of Natural
Resources (DNR), Anchorage, Alaska, co-presented an overview of
HB 50. He advanced to slide 11 of the DNR presentation dated
April 22, 2024:
[Original punctuation provided.]
HFIN CHANGES TO HB 50
Annual report to the legislature AS 38.05.735 (sec.
15)
Summary: Adds a new section requiring DNR to annually
report to the legislature information on carbon
storage applications, licenses, and leases. As well as
the accounting of the carbon storage closure trust
fund under AS 37.14.850.
Rationale:
• Consistent with annual oil and gas leasing report
to the legislature.
Amalgamating property interests AS 41.06.140 (sec.
31)
Summary: Replaces "mineral" rights with "pore space."
Rationale:
Clarifies AOGCC's authority to bring together all pore
space owners into a storage facility, separate and
distinct from mineral interest rights.
3:34:29 PM
MR. CROWTHER advanced to slide 12 and summarized HB 50:
[Original punctuation provided.]
SUMMARY
• Global events point to the urgency for Alaska
establishing a framework for the leasing of its
pore space for CCUS
• The CCUS regulatory and commercial landscape
continues to rapidly evolve
CSHB 50(FIN)
• Incorporates amendments that improve the State's
ability to maximize the value of its resources
• Clarifies and strengthens the State's ability to
protect life, health and safety of Alaskans
• Conforms with changes to EPA requirements based
on feedback received from EPA Region X and other
states that are necessary for AOGCC's Class VI
primacy application to be successful
3:35:03 PM
MR. CROWTHER directed attention to a second DNR presentation on
HB 50, dated April 24, 2024. He said the primary focus of this
presentation is the cost to develop Carbon Capture, Utilization,
and Storage (CCUS) projects and the value chain. He noted that
this includes consideration of the 45Q tax credit and its impact
on various project costs. It also considers the impact this has
on state revenue and includes hypothetical revenue scenarios. He
acknowledged that there is a great deal of uncertainty about
these projects and their costs as the industry is evolving.
3:35:56 PM
RYAN FITZPATRICK, Commercial Analyst, Division of Oil and Gas
(DOG), Department of Natural Resources (DNR), Anchorage, Alaska,
advanced to slide 2, which discusses the costs and challenges
associated with Carbon Capture, Utilization, and Storage (CCUS)
projects prior to startup. He explained that these are similar
to what is seen in oil and gas operations. He pointed out that
the startup capital needs for most CCUS projects are fairly
significant. This is in-line with oil and gas operations which
involve sub-surface assessments, exploration drilling,
production drilling, and various above-ground needs.
3:37:19 PM
SENATOR KAWASAKI commented that much of this discussion has
referenced these as separate and distinct projects (e.g. the
sequestration project is different from power plant that emits
the CO2). He asked how this compares to instances where it is a
single project (e.g. a power plant facility that sequesters
CO2).
3:37:54 PM
MR. FITZPATRICK replied that it is likely that in the future,
single storage facilities would service multiple capture
facilities. He noted that in the lower 48, projects have
typically included one CO2 capture source and one sequestration
source. He said that, over the next 5-10 years, this is
projected to transition to larger injection sites that service
multiple capture sites. This could potentially become a "fee for
service" model, where the injection occurs separate from the
capture. He added that this is a fairly new industry that is
evolving quickly.
3:39:10 PM
MR. FITZPATRICK advanced to slide 3 and described a hypothetical
45Q tax credit value chain. He discussed the various costs
associated with the value chain, including capture costs;
transportation costs, injection/operation costs; and storage
costs. He noted that the capture process is likely the most
expensive part of the process and added that the economics of
these projects can become a challenge relatively quickly. He
explained that leasing pore space falls under "storage costs."
This is where DNR would potentially see the value of leasing the
pore space - and could capture some of this value for the state.
He pointed out that much of the 45Q tax credit is eaten up in
these various costs, though there is the potential for residual
values on a project-by-project basis.
3:41:59 PM
SENATOR DUNBAR asked if slide 3 assumes that the only revenue
input is the 45Q tax credit.
3:42:12 PM
MR. FITZPATRICK replied yes and added that for the purpose of
this hypothetical scenario, that was the only revenue generated
by the project.
3:42:21 PM
SENATOR DUNBAR noted that, according to this scenario, the state
would end up with $625,000 per year, while the company would
retain $2.6 million of the 45Q tax credit. He commented that
this assumes the company is not receiving payment and questioned
whether there is any other way to get revenue from this process
(other than the 45Q tax credit).
3:42:48 PM
MR. FITZPATRICK replied that different project designs may
result in additional revenue generating opportunities. He added
that future slides contain additional hypothetical situations
that may address this question.
3:43:10 PM
MR. FITZPATRICK moved to slide 4 and provided hypothetical state
revenue opportunities:
[Original punctuation provided.]
Hypothetical State Revenue Opportunities
Regional Power Facility
• 250,000 metric tons/year, $2.50 metric ton/year
• 20-year life
• Acreage approx. 1200 acres during injection, $20
acre/year
North Slope Emitting Facility
• 2,000,000 metric tons/year (50/50 EOR & Storage),
$2.50 metric ton/year (Storage)
• 20-year life
• Acreage approx. 10,000 acres during injection,
$20 acre/year
CO2 Import & Sequestration Facility
• 10,000,000 metric tons/year, $2.50 acre/year
• 40-year life
• Acreage approx. 50,000 acres during injection,
$20 acre/year
MR. FITZPATRICK noted that these hypothetical revenue
opportunities contain certain assumptions; however, the
intention is not to predict whether these will occur if HB 50 is
passed - or that these types of projects would occur within the
suggested scenarios. Rather, this is an attempt to understand
the potential hypothetical revenue opportunities that might be
generated via HB 50. He stated that the North Slope Emitting
Facility is one example of additional revenue that could be
generated by these projects.
3:45:04 PM
CO-CHAIR BISHOP asked for an explanation of the $20/year acreage
fee.
3:45:15 PM
MR. CROWTHER replied that these numbers were included in
previous CCUS presentations, and this was the minimum originally
included in HB 50. He explained that this number was drawn from
examples taken from other states and was included as a reference
case. He clarified that the current version of HB 50 does not
include this number.
3:45:50 PM
CO-CHAIR BISHOP asked if the $20/year acreage fee would apply to
the facility's footprint. He asked for clarification that the
state would be charging for the reservoir space.
3:46:08 PM
MR. CROWTHER replied that this is similar to an oil and gas
lease in that the reservoir is extrapolated (in the
hypothetical) to cover approximately 1200 acres. The company
would need to secure the subsurface rights for this space - and
the $20/year acreage fee would be assessed against this space
(i.e. the expected size of the reservoir).
3:46:29 PM
MR. FITZPATRICK added that, like oil and gas leasing, DNR
anticipates the lease charges to be incurred during the site's
exploration phase. He said that once injection begins, the
injection fee takes over as the primary revenue source. He added
that the injection fee quickly overshadows the leasing payments.
3:46:57 PM
MR. FITZPATRICK advanced to slide 5 and noted that this shows
additional hypothetical revenue opportunities:
[Original punctuation provided.]
Hypothetical State Revenue Opportunities
• Not all CO2 emissions are feasibly captured technology
continues to rapidly develop
• Capital expenditures to retrofit existing facilities cannot
be met by existing incentives in some cases
• Import of CO2 is dependent on further development of
shipping technology and infrastructure
• 45Q tax credits only available for projects capturing CO2
in the US
• $60 per ton for Enhanced Oil Recovery
• $85 per ton for geologic carbon storage
• $180 per ton for geologic storage of carbon from
Direct Air Capture
3:47:04 PM
MR. FITZPATRICK advanced to slide 6 and discussed the potential
revenue from scenario 1: regional power facility. He noted that
this slide includes a higher level of detail than was presented
previously. He said, in this case, the 45Q tax credit would
generate $425 million in revenue over the life of the project.
He pointed out that the majority of this revenue is eaten up by
project costs (cost of capture, transportation, and injection
costs). Some of the remaining $65 million will be allocated
against the regulatory costs. He referenced the Carbon Storage
Closure Trust Fund, which is another source of outflow from this
project. He added that this is not a source of revenue but is
intended to help source additional regulatory costs. He
directed attention to the state revenue shown on the slide. He
noted that "exploration license" is an acreage fees. He surmised
that, during exploration, companies would license a larger
footprint than necessary for the ultimate injection facility,
then downgrade this once they reach the point of finalizing the
footprint. He said that the exploration license ends up
generating a little more revenue because it covers more ground
(i.e. it has a larger footprint) which is later downselected
into a more compact lease and injection fees begin to come
through. He noted that this scenario shows through year 11 and
goes through year 66, and briefly explained the data
calculations.
3:50:01 PM
MR. FITZPATRICK advanced to slide 7 and continued discussing
hypothetical state revenue opportunities. He pointed out that
the only change in slide 7 is the cost of capture, which was
increased to $70 per ton. The post-combustion capture cost
ranges from between $50 and $70 per ton. This illustrates how
changing something small can result in a drastic decrease in
total net profits, causing projects to become uneconomic.
3:50:57 PM
CO-CHAIR BISHOP asked if this data assumes that the 45Q tax
credit would be renewed every ten years.
3:51:07 PM
MR. FITZPATRICK replied yes. He explained that this hypothetical
scenario is for a 20-year facility, which could mean a renewal
of the 45Q tax credits - or it could mean that the injection
site continues for 20 years, during which time the storage
reservoir may operate for multiple different sources.
3:51:45 PM
MR. FITZPATRICK advanced to slide 8. He explained that this
compares the revenue pictures for the three scenarios presented
(regional power facility CCUS, North Slope facilities CCUS, and
CO2 import for sequestration). He pointed out that the North
Slope facilities CCUS - increased annual capture generates
additional injection fees along with enhanced oil revenues and a
potential for enhanced oil recovery. He said that this is a very
rough estimation. He stated that the CO2 import data refers to
the potential for importing CO2 from Asia and Pacific countries
and briefly described this in terms of liquified natural gas
tankers (to offer a sense of scale).
3:53:31 PM
MR. FITZPATRICK advanced to slide 9 and invited Dan Stickel,
chief economist for the Department of Revenue, to discuss
royalty and tax under current law and under HB 50.
3:54:14 PM
DAN STICKEL, Chief Economist, Department of Revenue, Juneau,
Alaska, explained that slide 9 helps to show how HB 50 relates
to current law and how current law treats CCUS projects. He
expressed hope that this would also address questions from the
previous hearing of HB 50. He said that HB 50 does not make
significant changes to current tax. He explained that production
tax - which applies to all oil and gas production in Alaska -
does not apply to stand-alone CCUS projects. He explained what
would qualify as a lease expenditure deduction. HB 50 does not
make any changes to the production tax. He said that property
tax applies to any oil and gas infrastructure in the state.
State property tax does not apply to a standalone CCUS project;
however, municipal property taxes may apply. With respect to
enhanced oil recovery, he explained that a project that involves
property used for carbon capture that has a primary use in oil
and gas exploration, production, or pipeline transportation,
would potentially be subject to state property tax. He stated
that state property tax would not apply to a standalone CCUS
project (unrelated to oil and gas production). HB 50 does not
change this regime.
3:57:26 PM
MR. STICKEL said that DOR has existing regulatory authority and
is thus able to clarify in regulations what is subject to tax
versus what is not subject to tax. He said that HB 50 does
change corporate income tax law. He explained that, currently,
C-corporations are subject to corporate income tax (most federal
tax credits are adopted by reference). He stated that HB 50
changes this for 45Q tax credits, disallowing the 45Q tax credit
under state tax. With regard to royalties, he said that the
intention of HB 50 is to create regulatory structure for a
standalone carbon capture project.
3:59:06 PM
SENATOR WIELECHOWSKI offered an example of a company that is
drilling a well and taking advantage of the 45Q tax credits; in
this case, they are storing CO2, but also extracting additional
oil. He asked if this would be deductible on the lease
expenditures.
4:00:00 PM
MR. STICKEL said DOR would gather details on the expenditure and
determine to what extent the expenditure is an "ordinary and
necessary, upstream, direct costs related to enhanced oil
recovery; if it meets this requirement, it would be an allowable
lease expenditure deduction under the oil and gas production
tax. If it does not meet this test, it would not be allowable.
4:00:34 PM
SENATOR WIELECHOWSKI asked if any degree of relatedness would
result in the full deduction - or if some projects would only be
allowed a partial deduction.
4:00:48 PM
MR. STICKEL replied that DOR would consider these on a case-by-
case basis.
4:01:10 PM
SENATOR WIELECHOWSKI asked for clarification on whether, once a
project meets the criteria, the deduction would be "all or
nothing" or whether it would potentially be a partial deduction
based on the proportionality.
4:01:17 PM
MR. STICKEL replied that any cost that meets the aforementioned
requirements would be a deductible cost.
4:01:41 PM
SENATOR WIELECHOWSKI expressed concerns. He commented that the
costs are substantial. He said that the state would finance the
lease expenditures and the company would receive the tax credit.
He opined that this is not fair and could be considered "double-
dipping." He said that he has an amendment prepared to address
this.
4:02:27 PM
CO-CHAIR BISHOP shared an example of a North Slope producer
capturing 10 metric tons of CO2 per year and storing half
(taking advantage of the 45Q tax credit on this half) while
using the other half for enhanced oil recovery. He asked whether
this producer could take advantage of the 45Q tax credit for the
half used for enhanced oil recovery.
4:03:14 PM
MR. STICKEL replied that in each scenario, DOR would gather
information and make a decision. He directed attention to slide
9, which contains the criteria for determining whether a
particular expenditure would impact production taxes. He
reiterated that HB 50 does not make any changes to current law.
He said that a standalone CCUS project does not meet the
requirements and therefore those costs would not be deducted. If
the CCUS project is associated with enhanced oil recovery, DOR
would determine whether it meets the requirements of "ordinary
and necessary, upstream, direct costs related to enhanced oil
recovery." He explained that this is the threshold used to
determine whether the expenditures would be deductible against a
production tax or not.
4:04:30 PM
SENATOR DUNBAR noted that C corporations are subject to the
income tax. He wondered whether the taxes would apply the same
way to an S corporation. He asked if it is the nature of the
entity or the nature of the tax that matters.
4:04:58 PM
MR. STICKEL replied that the type of corporation does not impact
royalties, production taxes, or property taxes. The corporate
income tax is levied on C corporations; S corporations are not
subject to this tax.
4:05:37 PM
SENATOR DUNBAR offered a hypothetical scenario in which the law
was changed, and certain S corporations were then subject to the
corporate income tax. He asked whether it would apply in the
same way - and whether these corporations could then use the 45Q
tax credits.
4:05:58 PM
MR. STICKEL replied that any companies newly subject to the
corporate income tax, under current state law, would be able to
apply the 45Q tax credit to a portion of their state tax. He
explained that this is disallowed under HB 50.
4:06:27 PM
SENATOR WIELECHOWSKI directed attention to slides 6 and 7, which
are hypothetical scenarios for a regional power facility. He
asked whether a similar hypothetical scenario is available for a
North Slope project.
4:06:57 PM
MR. FITZPATRICK answered no. He explained that DOR only
considered the revenues for the North Slope project.
4:07:17 PM
SENATOR WIELECHOWSKI asked if analysis was done.
4:07:24 PM
MR. FITZPATRICK replied that DOR took the analysis from the
first scenario (on slide 6) but did not independently evaluate
the costs for the North Slope. He directed attention to the
costs associated with scenario 1 (slides 6 and 7) and said that
those costs are publicly reported and can then be scaled up
using the same cost-per-ton metric. He explained how this could
be applied to the North Slope to determine those costs.
4:08:48 PM
SENATOR WIELECHOWSKI directed attention to slide 6 and asked for
confirmation of his understanding of the projected capture costs
and project costs, and the potential North Slope costs.
4:09:15 PM
MR. FITZPATRICK clarified that DOR is hypothesizing these
numbers.
4:09:22 PM
SENATOR WIELECHOWSKI agreed that it is all hypothetical. He said
it would be eight times extrapolated. He shared his calculations
and asked for confirmation that the project costs would be $2.4
billion.
4:09:47 PM
MR. FITZPATRICK agreed that costs would be approximately $2.4
billion.
4:09:55 PM
SENATOR WIELECHOWSKI asked what percent would go to enhanced oil
recovery.
4:10:03 PM
MR. FITZPATRICK replied that in this hypothetical scenario, 50
percent was hypothesized; however, it could be more or it could
be less. He added that it also depends on the opportunities for
enhanced oil recovery (using the CO2). He emphasized that there
is limited data available and therefore these are very rough
estimates.
4:10:50 PM
SENATOR WIELECHOWSKI said that, assuming its 50 percent, total
project cost would fall around $1.2 billion.
4:11:00 PM
MR. FITZPATRICK replied that this is correct.
SENATOR WIELECHOWSKI shared his understanding that the lease
expenditures are 35 percent. He asked for confirmation of his
understanding that taxes would therefore be reduced by $450
million.
4:11:18 PM
MR. STICKEL explained that to the extent any costs for enhanced
oil recovery meet the threshold of ordinary and necessary,
upstream, direct costs, they would be allowable lease
expenditure deductions under the oil and gas production tax. He
said that this tax consists of a net profits tax with a 35
percent tax rate and a gross minimum tax floor. The maximum
potential benefit would be 35 percent of lease expenditures.
4:12:01 PM
SENATOR WIELECHOWSKI shared his understanding that, according to
his calculations, if the company has roughly $2.4 billion in
expenditures (assuming 50 percent), then the state would lose
roughly over $400 million in production taxes. He asked for
clarification that these calculations are correct.
4:12:24 PM
MR. STICKEL said that the potential lease expenditure deduction
could be $400 million.
SENATOR WIELECHOWSKI pointed out that this is not reflected in
the data provided by DOR.
4:12:44 PM
MR. CROWTHER replied that the data in the presentation reflects
hypothetical revenues and is not an analysis of all costs and
potential revenue. He pointed out that Senator Wielechowski's
calculations presume that all of the costs would fit the
deduction requirements; however, he shared his belief that DNR
has not made this the case for a category of costs. He stated
that DNR is not asserting that the cost of capture is - or is
not - a lease expenditure.
4:13:47 PM
SENATOR WIELECHOWSKI asked whether DNR believes that it is
important to inform the legislature that it could cost the state
over $400 million in lost production taxes for a single project.
4:14:27 PM
SENATOR CLAMAN said that, in 2023, the legislature passed
legislation related to carbon offset in the timber industry. He
asked if the state has entered into any contracts since the
legislation was passed.
4:14:55 PM
MR. CROWTHER shared his understanding that DNR has proposed
draft regulations which are currently moving through the public
review process. Once this process is complete, DNR will begin to
review potential projects. He noted that conceptual projects
have been proposed; however, the regulations are not final and
therefore no contracts have been issued.
4:15:20 PM
SENATOR CLAMAN said that the hypothetical scenarios are
interesting; however, the projects would require a substantial
investment by commercial interests. Additionally, distance
between the production and storage sites may be an issue. He
said that he understands opening the pathway for this
opportunity. He questioned what would happen if those
opportunities did not develop.
4:16:50 PM
JOHN BOYLE, Commissioner, Department of Natural Resources,
Anchorage, Alaska, replied that this is a relevant question. He
referred to the earlier question about carbon offset projects in
the forestry sector and said that there has been interest. He
said that DNR has received interest in carbon offset development
opportunities from a variety of sectors and expressed confidence
that opportunities would develop, once the regulations are in
place. With regard to CCUS, he said DNR has had many
conversations with developers.
4:19:12 PM
MR. BOYLE shared about the US Department of Energy's recent trip
to Japan, which included discussion of Alaska potentially
storing captured Japanese carbon and the possibility of a US
carbon sequestration hub. He noted that this would apply to
imported carbon. He indicated that there are many operators
interested in creating hydrogen, methanol, ammonia production
facilities and capturing CO2 is essential to these operations.
He noted that Alaska is in a unique geopolitical position that
holds significant interest and investment potential.
4:21:32 PM
CO-CHAIR GIESSEL noted that the focus of this hearing is the
fiscal aspects of HB 50 and suggested that this question be
taken up at a later time.
4:22:26 PM
NICHOLAS FULFORD, Senior Director, Gas and Energy Transition,
GaffneyCline, Houston, Texas, delivered a presentation on HB 50.
He advanced to slide 2 and began by discussing the wider
business sector as it relates to carbon capture and storage
(CCS). Many of these projects are in the Gulf Coast area of the
United States, which he surmised would serve as a guide for
Alaska's business model. He pointed out that projects are
emerging in response to a demand - emitters need to find
somewhere to store CO2. He gave several examples of the kinds of
projects that are in need of CO2 storage. He explained that each
program must have sufficient funds to pay for the elements in
the chain. He noted that for every $1 invested in geological
storage, $7 or $8 are invested into carbon capture.
4:24:35 PM
MR. FULFORD shared the two principles that govern the economics
of CCS - the concentration of CO2 in need of sequestration, and
the pressure. He explained that the base source category
includes gas processing, synthesis gas, ethanol, ammonia, and
some applications of hydrogen, all of which work under 45Q tax
credits. The next source category includes coal, cement, and the
"hard to abate" sector, which includes iron, steel, and cement,
among others. With respect to the potential success of CCS, he
said that most global emissions fall within the "hard to abate"
sector. He stated that the gulf coast projects are addressing
the tip of the iceberg. He noted that growth and development is
attempting to move toward more challenging projects.
4:26:12 PM
MR. FULFORD advanced to slide 3 and discussed the economic cost
curve for CCS projects. He said that the challenges around
pressure and purity result in a cost curve that begins very low
and quickly expands upward. He noted that direct air capture
falls at the high point of the curve, in the region of $100s per
ton. He explained that, historically, in the context of the 45Q
tax credits, there has been significant material incentive to
allow producers to receive the credit, make the investment, and
have an economic return. He pointed out that economic rent that
supports investment falls on the lefthand side of the graph.
4:27:10 PM
MR. FULFORD advanced to slide 4 and continued to discuss the
economic cost curve for CCS projects. He briefly described the
incentives around carbon capture and how they have grown. He
noted that the costs for CCS are decreasing. He explained that
the hub-based business model for CCS is beneficial because
amalgamating a series of emissions - and building one large
carbon sequestration unit to deal with it - results in decreased
costs. This is a gradual emergence of a more material, CCS
addressable market that is able to address hard to abate
projects.
4:28:27 PM
MR. FULFORD advanced to slide 5 and discussed how higher costs
will impact marginal CCS projects. He noted that the question of
how to achieve a suitable balance between profitability and
revenue for the state has been discussed with regard to HB 50.
He said in this emerging, highly speculative world, it is
difficult to pin down the economics of a project. He added that
the projects he has worked on have had challenging economics. He
referred to the graph on slide 5 and said that the revenue curve
is based on 45Q tax credits and noted that the cost curve is
just beginning to go down. This slide illustrates the effect of
a fixed charge on leasing costs for acreage. He explained that
the effect of a minimum charge would be to mitigate the benefit
of the 45Q tax credit. This would move the revenue curve down.
He explained the impact this would have on the range of
profitable projects. He surmised that one unintentional cost
would be potentially jeopardizing projects that would otherwise
have gone ahead. Other projects would have the necessary
economic rent to support the charges. He offered the export of
CO2 from Japan as another example of an instance when creating
an economically viable plan could be impacted by a minimum
charge on leasing.
4:31:14 PM5
MR. FULFORD advanced to slide 6 and discussed how higher costs
would impact CCS projects. He said that past projects have
involved a single LNG plant and a single sequestration storage
unit. However, hub-based business model is gaining momentum in
the lower 48. He highlighted the financial and commercial
implications of this type of program. He described the way in
which risk is transformed along the chain.
4:33:34 PM
CO-CHAIR BISHOP asked for clarification of the potential
downside risks of 45Q incentives.
4:33:45 PM
MR. FULFORD explained that investors are concerned with
"regulatory risk." He pointed out that the 45Q tax credit has a
12-year limitation - and there is question about what will
happen after 12 years, as most of the projects have the
potential to run for 20-40 years. Some investors decline to
invest in CCUS due to the risk associated with government
sponsored revenue streams. Others are taking advantage of the
12-year revenue stream and not expecting more. More progressive
investors recognize that CO2 capture is growing in importance
and assuming that the 45Q tax credit will exist indefinitely
with the potential to be increased. He stated that, no matter
the jurisdiction, the CCUS revenue model is always driven by
policy.
4:35:28 PM
SENATOR KAUFMAN asked if Mr. Fulford had prepared a risk
register. He opined that all risk should be tabulated in order
to prepare for potential issues.
4:36:48 PM
MR. FULFORD replied that a risk register was not within the
scope of his work with DNR; however, he shared that he is chair
of an international CCS working group that recently published a
risk register. He said that he would share the details of the
risk register with the committee. He noted that the
aforementioned risk register focuses on commercial risk along
the value chain, although there are other documented programs
that focus on physical risk and reservoir risk in particular. He
added that this is typically closely monitored via regulatory
frameworks.
4:37:51 PM
MR. FULFORD advanced to slide 7 and said that this translates
theoretical risks into "investability." He explained that CCS
projects are typically measured in terms of "levelized cost of
storage" - similar to what is done with an oil and gas project.
He briefly described this process, including pore space leasing
and upfront fees. He noted that in Texas and Louisianna this is
typically negotiated directly with the private landowner. He
said that this type of analysis provides a pure, economic
perspective on the "break-even cost" of a CCS project. He
explained how this relates to projects utilizing a hub-model,
which requires risk transfer. He stated that while analysis can
begin with a technical financial evaluation of the facility,
additional risks and their implications must also be considered.
4:40:52 PM
SENATOR WIELECHOWSKI pointed out that the costs for these
projects differs greatly from the Gulf Coast to Alaska. He noted
on the Gulf Coast, the cost is $20-$25/ton, while DNR estimates
the cost in Alaska to be $72-$82/ton. He asked if these costs
are reasonable - and if it is likely that this will be the
actual cost in Alaska.
4:41:21 PM
MR. FULFORD replied that it depends on the specifics of the
project. He added that, at this point, many speculative projects
can be considered. He said that he does not see any error in the
data provided by DNR. However, consideration of compression
would likely have a large impact.
4:42:21 PM
SENATOR WIELECHOWSKI asked if other states are providing tax
incentives for CCS projects.
4:42:50 PM
MR. FULFORD replied that he is unaware of states providing
material tax provisions being introduced. He said that the
economic typically rely on the 45Q tax credits. He explained
that, with enhanced oil recovery projects, the difference
between the $60/ton offered by 45Q tax credits and the $85/ton
for geological permanent sequestration is often made up by the
fee the CO2 user is prepared to pay for the enhanced CO2. As a
result, the EOR economics and the sequestration economics look
fairly similar for most of the projects he has considered.
4:44:09 PM
CO-CHAIR GIESSEL indicated the committee would briefly interrupt
the hearing on HB 50 and take up consideration of a governor's
appointee.
HB 50-CARBON STORAGE; COOK INLET OIL AND GAS
4:57:04 PM
CO-CHAIR GIESSEL resumed the hearing on HB 50.
4:57:34 PM
FRANK PASKVAN, Affiliate Professor, University of Alaska
Fairbanks (UAF) and Institute of Northern Engineering,
Fairbanks, Alaska, delivered a presentation on carbon storage.
He offered a brief work history and described his current work
for UAF and the state of Alaska.
4:58:59 PM
MR. PASKVAN advanced to slide 2:
[Original punctuation provided.]
Affordable and Reliable Energy through Carbon Capture
Use and Sequestration
Carbon Capture Use and Sequestration (CCUS) has the
potential to:
• Reduce the cost of energy.
• Meet future voluntary or required emission
reductions.
• Make oil-, gas-, and coal-fired heat and power
plants nearly carbon-neutral.
• Remove both CO2 and pollutants.
CCUS research at UAF's Institute of Northern
Engineering focuses on:
• Building knowledge and establishing a legal and
regulatory framework for Alaska.
• Conducting feasibility studies to improve the use
and sustainability of local energy resources.
• Innovating new energy industries in Alaska (e.g.
direct air capture of CO2; hydrogen or ammonia-
based fuel from natural gas).
• Developing Alaska's workforce through the Energy
Resources Engineering program at the University
of Alaska Fairbanks starting in the fall of 2024.
5:00:32 PM
MR. PASKVAN advanced to slide 3 and presented key takeaways for
the global CCS Institute Annual Report for 2023
[Original punctuation provided.]
Global CCS Institute Annual Report for 2023
Key takeaways, changes from 2022 to 2023:
• 48 percent increase
• The CO2 capture capacity of all CCS
facilities under development has grown to
361 million tons per annum (Mtpa) growth
of 48 percent since the 2022 report.
• 198 new facilities have been added to the
development pipeline, bringing the current
total to 41 projects in operation, 26 under
construction and 325 in advanced and early
development
MR. PASKVAN emphasized that CCS continues to gain traction
globally and locally; this results in hundreds of millions in
global investment dollars in carbon capture and sequestration.
5:02:00 PM
MR. PASKVAN advanced to slide 4 and discussed the theoretical
project timeline. He explained that CCS projects can take years
to mature from concept to execution. He added that, to be
eligible for the 45Q tax credits, a project must break ground by
January 1, 2033. He said that projects must lower uncertainty in
order to appeal to investors. He argued that the only way to
reduce a project's uncertainty is to pass carbon storage
legislation. He reiterated that projects take time to mature and
pointed out that the eligibility for the 45Q tax credit is
quickly approaching. He argued that this underscores the current
need for a regulatory and legal framework in the state.
5:03:44 PM
MR. PASKVAN advanced to slide 5 and discussed the need for CO2
storage:
[Original punctuation provided.]
ARCCS Project Determine CO2 storage volume Northern
Cook Inlet
• Carbon Storage capacity, proved through
engineering and geoscience, is key requirement
for any CCS Project
• Beluga River Field has estimated 60+ years
storage for 300 MW net biomass-coal power plant
with CCS
• Project evaluates aggregating CO2 from Chugach
Electric's two Anchorage natural gas power plants
• DOE awarded $9 million to UAF November 2023.
Cannot be accepted until matching funds secured.
• $2.2 million matching funds request included
in UA Budget
MR. PASKVAN briefly described the Alaska Railbelt Carbon Capture
and Storage (ARCCS) project. He noted that this research project
is supported by Gwen Holdmann, UAF's associate vice chancellor
for research for innovation.
5:07:17 PM
CO-CHAIR BISHOP inquired about the diameter of the pipeline and
the cost per mile to lay the pipeline.
5:07:31 PM
MR. PASKVAN briefly explained the method used to determine the
diameter of the pipeline. He said the project accounts for a 12
16-inch diameter pipeline, depending on the volume of CO2 to be
moved. He noted that distance is also a factor. He said that the
cost was approximately $137 million for a 75-mile pipeline. He
said that the specific numbers can be found in the study, which
is available for the committee to review. He stated that UAF is
requesting funding support for this project.
5:08:49 PM
MR. PASKVAN advanced to slide 6:
[Original punctuation provided.]
CCS Technology and Application
• CCS Technology is Proven and Cost Effective
• EPA states CCS adequately demonstrated
technology for certain natural gas and coal-
fired power generation
• Proposing CCS, low-GHG hydrogen co-fire, or
other emission controls starting in 2030 as
best systems of emissions reduction (BSER)
• Federal Register 5/23/2023 vol.88 No.99
p.33291
• Use of Alaska's abundant Coal, Oil, and Natural
Gas resources may require CCS
• With CCS, coal and natural gas power plants
across Alaska can provide reliable power
• Coal is the most abundant fossil fuel in the U.S.
• 27 percent of the world's coal is in the
U.S. and half of all U.S. coal resources are
found in Alaska.
5:11:39 PM
MR. PASKVAN paraphrased from the following sections of the
Environmental Protection Agency (EPA) Fact Sheet on Greenhouse
Gas Standards and Guidelines for Fossil fuel-fired Power Plants
Proposed Rule:
[Original punctuation provided.]
Fact Sheet on Greenhouse Gas Standards and Guidelines
for Fossil fuel-fired Power Plants Proposed Rule
Summary
On May 11, 2023, the U.S. Environmental Protection
Agency (EPA) announced proposed new carbon pollution
standards for coal and gas-fired power plants .... The
proposed limits and guidelines require ambitious
reductions in carbon pollution based on proven and
cost-effective control technologies that can be
applied directly to power plants. They also provide
owners and operators of power plants with ample lead
time and substantial compliance flexibilities,
allowing power companies and grid operators to make
sound long-term planning and investment decisions, and
supporting the power sector's ability to continue
delivering reliable and affordable electricity.
The proposed standards are based on technologies such
as carbon capture and sequestration/storage (CCS),
low-GHG hydrogen co-firing, and natural gas co-firing,
which can be applied directly to power plants that use
fossil fuels to generate electricity (page 1).
State plans would reflect limits that go into place in
2030 for existing coal-fired units. Depending on the
expected length of the units' period of operation,
those proposed limits are based on CO2 emission rates
achieved by natural gas co-firing or CCS (page 3).
Emission Guidelines for Existing Fossil Fuel-Fired
Steam Generating EGUs (Primarily Existing Coal Units)
EPA is proposing that the BSER for coal-fired steam
EGUs that will operate in the long-term (i.e., after
December 31, 2039) is the use of carbon capture and
storage (CCS) with 90 percent capture of CO2. The
associated degree of emission limitation is an 88.4
percent reduction in emission rate (lb CO2/MWh-gross
basis).
EPA has determined that CCS satisfies the BSER
criteria for these sources because it is adequately
demonstrated, achieves significant reductions in GHG
emissions, and is highly cost-effective (page 6).
5:16:26 PM
CO-CHAIR GIESSEL commented that this seems to indicate that 45Q
tax credits are available; however, there is a mandate to
implement CCUS - particularly if Alaska wants to generating coal
power. She directed attention to slide 8 and asked for
confirmation of her understanding that CCUS does not lower the
cost of energy.
5:17:01 PM
MR. PASKVAN confirmed that this is correct. He advanced to slide
8 and gave an overview of the results and conclusions of the
study, "Low Carbon Biomass-coal Power with CCS: Results and
Conclusions." He explained the chart titled, "Electricity Cost
Comparison, With and Without CCS, $/MWh." He pointed out that
continuing to use natural gas power would result in increased
costs over time. He compared the cost per kilowatt hour (Kwh) of
electricity for several states, including Hawaii and California.
He explained that utilizing biomass-coal with carbon capture
would result in a lower cost per Kwh while removing CO2.
5:20:47 PM
MR. PASKVAN continued his discussion of slide 8:
[Original punctuation provided.]
Low Carbon Biomass-Coal Power with CCS: Results and Conclusions
• Biomass-coal electricity with CCS is attractive
• Delivers affordable, reliable, clean, long-term energy
security
• Lower electricity cost than natural gas with or
without CCS
• Lower CO2 emissions than natural gas
• Hundreds of years of local fuel supply
• CCS lowers electricity cost since 45Q credits exceed
CCS costs
• CCS increases natural gas electricity cost since costs
exceed 45Q credits, especially for high regional gas
prices
• Lowering Railbelt electricity cost lowers Rural electricity
cost through Power Cost Equalization
• Further engineering design can enable cost, technology, and
site location improvements
5:23:23 PM
CO-CHAIR GIESSEL opened public testimony on HB 50.
5:23:58 PM
KEN HUCKEBA, representing self, Wasilla, Alaska, testified in
opposition to HB 50. He argued that 45Q tax credit revenue would
be harvested by outside companies, such as Santos. He shared his
belief that the legislature should ensure that no 45Q tax credit
monies go to foreign companies. He expressed concern regarding
the safety of CCUS projects and referred to a case in Norway in
which 900 feet of cap rock were fractured. He asserted that HB
50 does not contain adequate protections for potential seismic
activity. He argued that the "business model" of HB 50 is
intended to harvest 45Q tax credits - and expressed strong
opposition to this potentially being given to foreign companies.
5:25:33 PM
TODD LINSDLEY, representing self, Anchorage, Alaska, testified
in opposition to HB 50. He argued that HB 50 would enable a
"gold rush" for 45Q tax credits. He stated that no evidence has
been given to quantify the premise that CCUS will reverse the
effects of climate change. He argued that carbon sequestration
does not provide a material benefit to the state and negatively
impacts the civil liberties of landowners.
5:27:05 PM
KAYCI HANSON, representing self, Ninilchik, Alaska, testified in
opposition to HB 50. She said HB 50 is an attempt to greenwash
the industry. She argued that removing the minimum payment for
carbon storage will result in program costs that exceed any fees
generated - effectively rendering HB 50 a fossil-fuel subsidy
that provides no real benefit to the state. She argued that the
state should focus on sustainable, green energy production - not
on carbon capture projects designed by the entities responsible
for creating the issue CCUS attempts to solve.
5:28:18 PM
KEN GRIFFIN, representing self, Wasilla, Alaska, testified in
opposition to HB 50. He said the legislature works for the
residents, not corporations and universities. He argued that the
economics of HB 50 are equivalent to extortion. He asserted that
the EPA recognizes that there is no climate crisis. He stated
that, globally, every carbon capture project has underperformed
by more than 50 percent. He questioned what this means in terms
of cost and risk. He emphasized the negative impacts and
asserted that Alaska's citizens do not support HB 50.
5:29:58 PM
CONNOR HAJDUKOVICH, External Affairs and Policy Coordinator,
Resource Development Council, Anchorage, Alaska, testified in
support of HB 50. He gave a brief overview of the Resource
Development Council (RDC) and thanked the legislature for
passing legislation approving class VI well primacy during the
2023 legislative session. He said that HB 50 would allow Alaska
to remain competitive among CCUS programs nationwide. He
indicated that implementing a CCUS program is a long process and
argued that further delay could result in Alaska losing out to
other states already working to establish similar programs. He
said that many of RDC's member companies have adopted corporate
net zero emission policies and would benefit from the creation
of a CCUS program in Alaska.
5:31:27 PM
KASSIE ANDREWS, representing self, Anchorage, Alaska, testified
in opposition to HB 50. She said the only incentive for CCUS
projects is the 45Q tax credit, which she argued has a fraud
rate of at least 90 percent. She stated that this tax credit is
estimated to cost well over $100 billion. She asserted that no
other action has been taken to assure the success of future CCUS
projects. She argued that HB 50 is not market driven; rather,
government is forcing action based on the erroneous idea that
global warming can be impacted by human activity. She asserted
that carbon control is equivalent to controlling people.
5:32:40 PM
CO-CHAIR GIESSEL closed public testimony on HB 50.
5:32:57 PM
CO-CHAIR GIESSEL [held HB 50 in committee.]