Legislature(2023 - 2024)ADAMS 519
05/03/2023 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB50 | |
| HB49 | |
| Presentation: Alaska Liquefied Natural Gas Project Update | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| += | HB 49 | TELECONFERENCED | |
| += | HB 50 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE FINANCE COMMITTEE
May 3, 2023
1:34 p.m.
1:34:08 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 1:34 p.m.
MEMBERS PRESENT
Representative Bryce Edgmon, Co-Chair
Representative Neal Foster, Co-Chair
Representative DeLena Johnson, Co-Chair
Representative Julie Coulombe
Representative Mike Cronk
Representative Alyse Galvin
Representative Sara Hannan
Representative Andy Josephson
Representative Dan Ortiz
Representative Will Stapp
Representative Frank Tomaszewski
MEMBERS ABSENT
None
ALSO PRESENT
Nicholas Fulford, Senior Director, Gas and Energy
Transition, GaffneyCline; John Crowther, Deputy
Commissioner, Department of Natural Resources; Rena Miller,
Special Assistant, Office of the Commissioner, Department
of Natural Resources; Eric Demoulin, Director of
Administrative Services, Department of Revenue; Frank
Richards, President, Alaska Gasline Development
Corporation; Nick Szymoniak, Manager, New Business
Ventures, Alaska Gasline Development Corporation;
Representative Justin Ruffridge.
PRESENT VIA TELECONFERENCE
Ashlee Adoko, Director of Office of Project Management and
Permitting, Department of Natural Resources; Helge Eng,
Director, Division of Forestry and Fire Protection,
Department of Natural Resources; Kris Hess, Deputy
Director, Division of Mining, Land and Water, Department of
Natural Resources.
SUMMARY
HB 50 CARBON STORAGE
HB 50 was HEARD and HELD in committee for further
consideration.
HB 49 CARBON OFFSET PROGRAM ON STATE LAND
HB 49 was HEARD and HELD in committee for further
consideration.
PRESENTATION: ALASKA LIQUEFIED NATURAL GAS PROJECT UPDATE
Co-Chair Foster reviewed the meeting agenda.
HOUSE BILL NO. 50
"An Act relating to the geologic storage of carbon
dioxide; and providing for an effective date."
1:35:10 PM
AT EASE
1:35:57 PM
RECONVENED
Co-Chair Foster continued to review the agenda.
1:36:41 PM
NICHOLAS FULFORD, SENIOR DIRECTOR, GAS AND ENERGY
TRANSITION, GAFFNEYCLINE, introduced himself and the
PowerPoint presentation "CCUS Value Chain and Business
Case" dated May 3, 2023 (copy on file). He shared that he
had worked on around a dozen CCS [carbon capture storage]
projects worldwide, but predominately in Texas and
Louisiana. He began on slide 2 and provided the agenda for
the presentation. He stated that the industry was unfolding
at a rapid rate. He relayed there were quite a few useful
lessons that could be drawn from activities around the
world. One of the features of the journey was that the
different sequestration agreements had reached an advanced
stage in their discussions so that cost stack and pore
space leasing costs were starting to come to the surface.
As the contracts became more sophisticated there were a
number of commercial considerations emerging. He reported
that the environment for CCS in Alaska was very different
from Texas, Louisiana, and many other parts of the world.
Mr. Fulford moved to slide 3 titled "Significance of State
Related Charges in Development." He shared that in the
context of the CCS industry, Alaska was in a fairly early
stage. He elaborated that many of the projects in Texas and
Louisiana had reached fully termed sequestration agreements
typically between an emitter (e.g., a petrochemical plant
or power station) and transportation storage companies
(T&S). He detailed that T&S entities had to address where
the carbon dioxide (CO2) was sequestered, and part of their
contractual framework pertained to pore space leasing
agreements. He expected the journey in Alaska to move
through the same kind of phase. He relayed that the focus
had been on the geology and rock properties in the past few
months and the outcome of the work was to demonstrate that
the state had considerable potential.
Mr. Fulford continued reviewing stages on slide 3. The
second stage was techno-economic project feasibility, which
included a high level dialogue with potential emitters and
people interested in storing CO2 and a more advanced
perspective on pore space leasing. He noted it would
include the kind of regulatory and legislative framework HB
50 was designed to address.
Mr. Fulford moved to the third phase, which would be termed
a pre-financial investment decision (FID) phase. He
detailed that the emitters and the sequestering T&S
companies were finding it useful to adopt a heads of
agreement framework, which entailed an eight to ten-page
agreement (that was not typically legally binding) to
provide some assurance for lenders and the industries
looking to sequester their carbon. He expounded that part
of the agreement would likely include a reasonably detailed
explanation of the pore space arrangements and location. At
that point, much more detailed financial modeling would
occur, including levelized cost storage and taxes. The
fourth phase FID would include an array of contracts,
which would be carefully scrutinized by lenders,
particularly if any project finance was involved. There
would also be an EPC or development contract to look at
construction.
1:42:01 PM
Representative Hannan asked what the last term [EPC] used
by Mr. Fulford stood for.
Mr. Fulford replied that EPC stood for engineering,
procurement, and construction (EPC) contract.
1:42:26 PM
Representative Galvin referenced the technical feasibility
stage shown on slide 3. She recalled discussion in
committee the previous week about transportation of a
product thousands of miles to another location. She found
it to be a significant barrier to the project concept. She
remarked that the committee had not yet seen the size or
type of container needed. She thought it was an important
part of the plan. Alternatively, she considered that
perhaps there was only thought about oil and gas on the
North Slope, which was an entirely different vision. She
asked for Mr. Fulford's comments.
Mr. Fulford responded that the distance between the
emitting source and the sequestration site was a critical
part of the picture. He stated that the distance was
relatively short for most of the existing projects or
projects in development. He highlighted an ammonia plant
where an injection well was being drilled within the plant
boundary, which created substantial savings. He estimated
that for the Gulf Coast, the distance the economics were
sustainable was about 50 miles. He elaborated that at that
point the compression in the pipeline tariffs started to
encroach. He noted it was within the current envelope of
the 45Q tax credits of about $85 per ton and the capture,
transport, and sequestration came out of that. The marine
transport of CO2 was being done between Denmark and Norway
and was a relatively groundbreaking and developing
technology. Although there had not been any largescale CO2
marine transportation vessels built yet, they were on the
drawing board. He relayed that to move CO2 from Southeast
Asia to Alaska in a large oceangoing CO2 vessel would cost
about $50 per ton. He stated it would be comparable to a
complex CO2 capture facility.
Representative Galvin surmised that if the ship were to be
built and the [transportation] cost was $50 per ton, it
sounded like the market was much higher than in other
places. She remarked that she could be wrong and perhaps
Japan and Asia had other market choices. She asked if
Alaska was really a good choice for them.
Mr. Fulford responded that there were a number of energy
intensive Asian economies without any readily available CO2
sequestration facilities; therefore, a number of them were
looking actively at cross border CO2 export projects, in
which case the distance and complexity was a factor. The
regulatory ability to monitor and measure and be confident
in secure storage was also particularly important. He
stated that one interesting synergy with respect to Alaska
was the potential export of LNG [liquid natural gas] and
the import of CO2. There were a number of Japanese
companies looking at the concept. Although the economics
and technology were yet to be determined, it was one of the
factors that made CO2 imports more relevant than other
ones.
Representative Galvin asked Mr. Fulford to speak to the
economics of a future situation where the technology
existed for Asia or another country to ship its carbon to
Alaska for sequestration and Alaska shipped out its LNG or
another gas product. She asked what the revenue would look
like for Alaska.
Mr. Fulford responded that the strategic scale of CCUS
[carbon capture, utilization, and storage] in Alaska was
significant on a global level. He stated it was useful to
keep in mind that the numbers and volumes were material
when turning them into revenue numbers. He relayed that
moving LNG from Alaska to Asia cost about $1.00 per million
Btu [British thermal unit], which corresponded to about $50
per ton. He elaborated that when exporting LNG, the
exporter bore the return cost of the empty ship. He stated
that equally with CO2 "you'd be doing the same." He relayed
that in theory, if the activities could be combined into
one business model, it would mean the potential for halving
the costs, which would create much more economic
opportunity. He believed the concept was a number of years
away, but it was worthy of exploration for Alaska's oil and
gas future. He noted there were other strategies available
including processing gas into ammonia or another organic
compound, which was more transportable than hydrogen and
could be used to export instead of gas. He stated that CCUS
was a facilitating technology that would aid in the
process.
1:51:09 PM
Representative Josephson referenced the terms price
discovery and levelized cost storage used by Mr. Fulford.
He asked for an explanation of the terms.
Mr. Fulford responded that there were dozens of emitters in
the U.S. Gulf Coast energy corridor who were all looking
for cost effective storage of their CO2. There were perhaps
half a dozen viable storage candidates. He elaborated that
currently the dialogue was going back and forth between
emitters and storage entities and price discovery was the
negotiation process of what was almost a commodity price.
Levelized cost was a term associated with carbon projects
and was a way of turning the capital and operating costs
into a tariff. He elaborated that the levelized cost of CO2
storage may be $20 per ton, which meant that financing the
capital and operating expenditures would require a $20 per
ton tariff over a 20-year period in order to pay it off.
1:53:32 PM
Co-Chair Johnson referred to the CO2 backhaul. She asked
whether natural gas was a liquid that compressed at
relatively the same rate [as CO2] making it possible to use
the same ships [for transportation].
Mr. Fulford explained that the concept of LNG out and CO2
back had economic advantage, but the technology did not yet
exist. The factors mentioned by Co-Chair Johnson were key
and would have to be addressed. He believed it would be
many years before the option was available.
Co-Chair Johnson referenced the number of different
entities from which the CO2 might be received. She asked if
CO2 gas was pure or included other chemical compounds. She
asked if it varied by company.
Mr. Fulford replied that for a point to point CCS scheme,
the quality of the CO2 was much less important as long as
it was in a form that could be easily injected and would
remain in the reservoir. He relayed that CO2 quality was
key for emerging industrial hubs in the same way that gas
transmission system had a certain spec, which had to be
adhered to. He stated in that case, some emitters may place
additional costs in pretreating CO2 to get it to the right
quality.
1:56:28 PM
Mr. Fulford advanced to slide 4 and the unit technical cost
of some examples of real life sequestration projects. He
detailed that the technical cost amounted to the upfront
capital expenditures and 20 years of operating
expenditures. He noted the information was useful as a
comparison between different concepts, but it did not
translate into a tariff. For the most part, the capture of
CO2 was a significantly higher proportion of capital than
lease storage. He relayed that the transport and to some
extent the compression were variable. The example on the
left of the slide was an industrial hub concept and showed
relatively small transport and storage cost, reflecting
economies of scale in the unit technical cost. The other
two examples on the slide showed a gas processing project
and an LNG acid gas pre-treatment project. He explained
that the predominance of capital and operating expense
required for the two projects was for the capture. He noted
he would go into additional detail on the numbers in the
next couple of slides.
Mr. Fulford moved to slide 5 titled "Example Costs for a
200 to 250MMscfd Project (3.9 to 4.8 MTPA)." The slide
corresponded to the gas processing and LNG acid gas pre-
treatment projects [shown on slide 4]. He noted the two
projects were very similar. He pointed out that a certain
amount of compression was required to bring the CO2 up to
the required critical pressures. The slide showed $77.3
million in compression capital expenditure and $40 million
for injection wells. The other costs were less in
descending order of magnitude. The example project was 4 to
5 million tons per annum (MTPA) of CO2 with approximately
$125 million in upfront capital expenditures. The right
side of the chart listed operating expenditures with the
two key components being fuel for the compression and
monitoring cost of injection wells and monitoring
equipment, which was very expensive. The total operating
expenditure was about $8 million.
Mr. Fulford continued to slide 6 and went through a
potential hypothetical scenario in terms of what the cost
may be for leasing the pore space. The scenario applied a
$1 per ton additional cost for the pore space lease, which
changed the numbers accordingly. The change added about
$4.5 million per annum of operating expenditures (a 35
percent increase compared to the example without pore space
leasing).
Mr. Fulford moved to slide 7 and highlighted a scenario
where the pore space lease was capitalized and moved
upfront as a capacity charge or something similar. He
detailed that at a 10 percent discount rate the pore space
lease (capital) came to about $38 million, which added
about 30 percent (the capital expenditure would go from
$125 million up to $163 million). The purpose of the slides
was to provide real life examples to give a sense of how
much projects cost and the impact of pore space.
2:00:12 PM
Representative Hannan looked at the row in the capital
expenditures column of the examples showing the owner's
cost. She asked if that reflected the contractor or
developer cost for Alaska. She noted that Alaska would be
the owner of the pore space. She asked if the pore space
lease cost was borne solely by the developer. She noted
that in some of the examples discussed, Alaska was the
owner of the space and perhaps a developer in some regard.
Mr. Fulford replied that the owner's costs predominately
related to the surface facilities and were typically paid
by the developer. He noted that the legal and regulatory
arrangement surrounding the ownership of pore space in
Alaska was well defined in its constitution. He stated that
generally the costs would be sustained by the developing
company and not the state.
Representative Hannan stated her understanding there was
not currently an example of an LNG/CO2 exchange because it
was not happening anywhere yet. She noted that under the
concept of the LNG project in Alaska, the state would own
the project and would invest in its development. She asked
for verification that Alaska expected to be the owner of
the sequestration pore space and the owner of the
accompanying facilities.
Mr. Fulford replied that the concept of the export of LNG
and import of CO2 was in the distant future and may not be
feasible given it was so far away; however, in the context
of the LNG project, he envisioned that a project of that
scale and complexity would require a series of legislative
steps to go forward (which was the case in most countries
GaffneyCline worked with in terms of LNG development). The
default assumption would be that the LNG project would pay
a tariff to a T&S company to deal with its CO2. He remarked
that it could be done in a different way, which had more
synergies for the state and the way its revenues were
determined.
2:03:34 PM
Representative Stapp observed that the examples used a 12-
year operating capacity time in the formula used. He asked
if it was standard in the industry to amortize costs over
12 years. He highlighted that the pieces of legislation
under discussion had a much longer timeframe.
Mr. Fulford responded that the 12 years was a throwback to
the previous 45Q [tax] structure. He relayed that 20 years
would be more typical injection framework and possibly
longer.
Representative Stapp asked if a 20-year calculation would
reduce the cost because there would be 20 years of capital
expenditures versus 12.
Mr. Fulford responded in the affirmative. He stated that
with discount rates, the later years started to have less
effect. He relayed that for most companies looking at
developments, being able to secure the longest possible
secured cashflow was advantages for everyone and resulted
in lower tariffs.
Representative Stapp asked if the increase of the per
tonnage fees to the allowable federal 45Q tax credits was
incorporated into the cost assessments. He believed it was
$85 per ton for standard capture and he understood it was
considerably higher for direct-year capture at $180 [per
ton].
Mr. Fulford replied that he was frequently asked how to
factor in 45Q and was it considered a credit or revenue. He
explained that GaffneyCline considered the 45Q tax cashflow
and the associated direct pay to be revenue. For example,
if the levelized cost was $50 per ton (which may be typical
for a gas processing plant) and a tax credit could be
secured at $85 (for a limited time), it would be considered
as a profitable project with an IRR [internal rate of
return] of potentially greater than 10 percent.
Representative Stapp remarked that the cost per ton for
carbon storage was less than the available 45Q tax credit.
He remarked on the seven-year period. He asked if the
difference in the capital expenditure cost of the project
was factored in. He stated a project would not be paying
any taxes at a federal level even if it was a subsidy.
Alternatively, he asked whether the effective credit made a
project economical or not was used as a baseline.
Mr. Fulford responded that the capital investment and
operating expenditures involved in a CCUS project was
purely a cost and unless there was a revenue mechanism to
compensate, no investment would happen. He noted it was the
reason nothing was happening despite the interest in CCUS
from a lot of countries. There was an emissions trading
system in Europe, which was about $100 per ton. There was
the LCFS [low carbon fuel standard] in California, which
was similar depending on how much could be captured.
Additionally, there was the federal 45Q. He explained it
was providing a very significant financial incentive. He
highlighted an LNG pre-treatment plant already producing
CO2 as an example. He stated it was roughly adequate for
something like an ammonia or hydrogen plant, and inadequate
for a gas-fired power station. He explained there was a
merit order of projects, some were economic and others were
not and the cutoff was somewhere between a large hydrogen
plant and a gas-fired power station.
2:08:38 PM
Co-Chair Johnson thought Mr. Fulford had stated that some
of the carbon capture technology was not yet available. She
asked what kind of carbon emissions load existed that may
be transported to Alaska.
Mr. Fulford replied that the largest projects being
discussed in Texas were 100 MPTA (the Exxon Houston ship
channel project). There was also an existing pipeline that
would take 16 MTPA. He noted that in the context of
industrial emissions across the country it was minimal. The
limitation was the economics of capture.
Co-Chair Johnson referred to the monitoring equipment
(capital and operating) costs. She assumed that the
standards from the registry would drive what the monitoring
equipment would be.
Mr. Fulford responded affirmatively. He relayed that all of
the projects had to obtain a license from the EPA
[Environmental Protection Agency] or from the state
authority depending on the jurisdiction. He stated it would
determine the extensive array of surface and surface
monitoring to examine what was happening to the plume and
check for any leakage.
Co-Chair Johnson surmised it applied to carbon and the
Alaska Gasline Development Corporation (AGDC) depending on
whether there was a line or other types of equipment
installed. She asked how 404 primacy would impact the
capital costs. She asked if Mr. Fulford anticipated any
difference in the capital cost if the state assumed it.
Mr. Fulford replied that the capital investment would
probably not change, but the operating expenditure may be
reduced. He elaborated that based on some of the projects
GaffneyCline was working on, the cost of an EPA class VI
permit application was relatively high but expected to
drop. He remarked that for states with primacy, the class
VI process was perceived to be much less complex.
Co-Chair Johnson wondered how familiar Mr. Fulford was with
companies' financing based on zero carbon emissions. For
example, project financing where zero carbon emissions was
a requirement or provided a given number of points towards
obtaining a loan.
Mr. Fulford summarized that he was very familiar with the
topic, which likely warranted a separate discussion. He
explained there were clear examples of low carbon projects
attracting low cost finance from different sources. There
were an increasing number of financial organizations that
would deprioritize or not lend to projects they perceived
to be incompatible with their carbon goals. Additionally,
some of the tech companies with a particularly aggressive
net zero target would pay several hundred dollars per ton
for a CO2 removal credit.
2:14:41 PM
Co-Chair Edgmon stated his understanding that three states
had 404 primacy including Florida, New Jersey, and
Michigan. He asked if all three states were doing carbon
capture.
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, responded that the 404 primacy was distinct from
the class VI primacy. He did not know the status of carbon
projects in the three states mentioned by Co-Chair Edgmon,
but it was not dependent or associated with 404 primacy. He
clarified that the class VI primacy through the EPA was for
sequestration wells.
Co-Chair Edgmon stated that was his understanding. He
thought the exchange between Co-Chair Johnson and Mr.
Fulford could have been inferred differently.
2:15:33 PM
Mr. Fulford advanced to slide 8 titled "Supply, Demand and
Levelized Cost." He highlighted a scenario turning the cost
breakdown on slide 7 into a tariff excluding the pore lease
cost spaces and the other significant commercial risks, the
levelized cost or tariff would likely be about $10 to $12
per ton. He stated there seemed to be a price of about $20
per ton that would support some of the larger T&S projects
serving the Gulf Coast. The slide highlighted there was a
substantial amount of sequestration potential available in
the U.S. and to be competitive it was necessary to be at
the lefthand side of the curve shown on slide 8. He used
the ExxonMobil Houston ship channel project (the largest
envisaged project) as an example with 100 MTPA for 20
years, which was about 2 gigatonnes and on the left side of
the chart. He relayed that Alaska was perceived to have
about 50 gigatonnes available in the Cook Inlet, which was
also still very much on the lefthand side of the chart.
Mr. Fulford briefly turned to slide 9 showing a summary of
some of the leasing fees other states had been securing. He
turned to slide 10 titled "Alaska Considerations." He
relayed that on a technical level, most of the Gulf Coast
projects were aimed exclusively at saline aquifers (water
carrying geological formations), which had an extensive but
less well defined CO2 storage capacity. The focus in Alaska
was currently on depleted gas reservoirs, which were well
documented and with very clear traps. The largest
difference conceptually between Alaska and other parts of
the U.S. was that Alaska had very low state emissions. He
discussed the three benefits of Alaska pursuing a CCUS
strategy. The first was that the foundation of the Alaska
economy continued to be the oil and gas industry. He stated
that as all of the recent developments had served to
underline, to enable the industry to continue to make the
future tax revenues more resilient, an assertive and
clearly established carbon management strategy would be
needed to help go forward. He elaborated that not only
would it protect existing revenues and cashflow, it would
potentially secure new investments and future tax royalty
that may otherwise be at risk in a world without carbon
management.
2:19:37 PM
Mr. Fulford relayed that the second benefit was the LNG
project (the monetization of North Slope natural gas). He
stated that having a robust carbon management strategy to
accompany the project would be an essential part of the
project going forward from a "social license" perspective.
He shared that based on his experience speaking with
Japanese banks and others who could conceivably be
interested, it was clear that lending to such a project
would be dependent on it being presented in a low carbon
fashion. He explained that natural gas and carbon capture
were two foundation stones of the ammonia and hydrogen
industry, which would be an important feature going
forward. The third benefit the potential for Alaska to
participate in the large scale imports of CO2.
Representative Josephson noted that he was a big supporter
of the large diameter gasline proposed in past legislation,
SB 138 [legislation proposed by former Governor Sean
Parnell in 2014] and could see how "this" could be helpful
to that endeavor. He considered the subject of social
license [in regard to CCUS projects being a catalyst for
LNG/gas monetization (shown on slide 10)]. He asked if it
could potentially less helpful if the goal post on the
international scene moved, which was likely to happen. For
example, if the Paris Accord became the Barcelona Accord
and had more aggressive goals to achieve. He asked if the
consideration could become outdated because the world was
in crisis.
Mr. Fulford responded that it was a very topical question.
He stated that part of his role at GaffneyCline was to take
a view on gas and LNG demand and how it was unfolding.
Currently there was likely a bigger gap in LNG forecasts,
particularly in the post 2030 era. He considered the
investment required to move the world's energy systems to a
renewable or net zero system and the ability of global
economies to sustain the expenditure. He explained it was
difficult to create the circumstance where rapid
decarbonization would occur. He believed taking a more
balanced view of the role that unmitigated natural gas or
low carbon fuels like ammonia or hydrogen would take and
looking at the timeframe for the Alaska LNG project, it
should be a viable proposition with the right buyer and
contract structure. He noted that much would depend on the
willingness of buyers to invest.
2:23:31 PM
Mr. Fulford provided conclusions on slide 11. He relayed
that the commercial framework for CCUS was rapidly
evolving; however, the tariffs and price point based on the
hardware and required capital expenditure were beginning to
come together. The capture economics continued to be the
biggest part of the equation and getting those addressed
was perhaps the key to large scale CCUS. The commercial
terms varied significantly depending on the risk
allocation. In particular, currently the biggest stumbling
block was the ability of an emitter to guarantee off taker.
He explained that an emitter would always want its CO2 to
be taken, but a storage project may not always be able to
take it. There was currently a very active negotiating
dialogue in the U.S., from which there were many lessons to
be learned in Alaska. Much of the same dialogue was being
held outside the U.S. at the government level, with a bit
slower pace and a different set of cost drivers.
Representative Ortiz looked at slide 11 and asked for an
explanation of the bullet point: "commercial terms depend
heavily on project structure and risk allocation."
Mr. Fulford responded with an example. He explained that
once a large industrial emitter secured sequestration, it
was able to collect the 45Q [tax credit] and perhaps a
premium for low carbon fuel. However, if the emitter was
unable to secure the emissions, it may face liabilities of
$100 to $300 per ton for having to vent the CO2, or not. On
the other hand, the storage entity may be paid $20 per ton
to take the CO2. He clarified that the emitter was ideally
not about to take a $300 liability for not doing so. He
explained that the back and forth on short and long-term
liabilities could create some large, stranded costs, which
had to be somehow allocated in the contract framework.
2:26:30 PM
Co-Chair Edgmon asked how Mr. Fulford would respond to the
viewpoint that the idea of carbon capture could be
considered a Ponzi scheme. He reasoned that by the time
much of the factors were worked out, particularly on the
sequestration side, the planet may have pivoted to more
carbon friendly in terms of emissions. He considered that
idea seemed promising in the current environment but may
not bear out in the future. He referenced the continued use
of the word "emerging" [used to describe carbon capture
technology]. He asked what Mr. Fulford would say to a
person who thought the idea sounded like crypto currency or
something similar. He stated that the end goal was to not
just provide environmental social government (ESG) licenses
to an emitter, but to actually reduce carbon. He asked what
would happen if it did not pan out and the multibillion
dollar emerging industry began to sputter and disappear.
Mr. Fulford replied that real money was currently being
deployed into CCS from credible and respectable
institutions including pension funds and New York based
infrastructure funds. Secondly, the International Panel on
Climate Change (IPCC) was pushing hard for a rapid
decarbonization of the world's economy. He elaborated that
the IPCC had stated that CCUS was an essential part of the
transition from present to net zero. He considered some of
the transformational energy systems like fusion and
imagined that in 50 or so years carbon capture would be an
older technology; however, there was a very clear role for
the next 50 years and investment was taking place
currently.
Co-Chair Edgmon thanked Mr. Fulford for the presentation.
Co-Chair Foster thanked Mr. Fulford and set an amendment
deadline for May 10, 2023, at 5:00 p.m.
HB 50 was HEARD and HELD in committee for further
consideration.
2:30:49 PM
AT EASE
2:32:34 PM
RECONVENED
HOUSE BILL NO. 49
"An Act authorizing the Department of Natural
Resources to lease land for carbon management
purposes; establishing a carbon offset program for
state land; authorizing the sale of carbon offset
credits; and providing for an effective date."
Co-Chair Foster began with a review of the fiscal notes.
2:34:14 PM
ASHLEE ADOKO, DIRECTOR OF OFFICE OF PROJECT MANAGEMENT AND
PERMITTING, DEPARTMENT OF NATURAL RESOURCES (via
teleconference), reviewed the fiscal impact note OMB
Component Number 2733, control code RFFnp, dated 5/2/23.
For FY 24, the total operating cost was $194.4 and
consisted of $156.1 in personal services, $10.0 in travel,
$16.3 in services, and $12.0 in commodities for one full-
time permanent large project coordinator position beginning
in FY 24 to stand up and administer the state projects
program (path 2 in the upcoming presentation). The fund
source was undesignated general funds (UGF) to be replaced
with revenue.
Representative Josephson asked about Ms. Odoko's statement
that general funds would be replaced by revenue. He did not
see that going out to FY 29.
Ms. Adoko responded that the Department of Natural
Resources (DNR) did not know exactly when revenues would be
online and the department would provide additional detail
on the topic during its presentation. She had additional
notes regarding FY 25 and beyond if the committee was
interested.
Co-Chair Foster asked Ms. Adoko to repeat her last
statement.
Ms. Adoko explained that she had covered FY 24 in her
fiscal note explanation but offered to provide additional
information on FY 25 and beyond.
Co-Chair Foster asked for clarification. He asked Ms. Adoko
to proceed.
Ms. Adoko relayed that for FY 25, the total operating costs
were $369.8, made up of $264.5 in personal services, $10.0
in travel, $81.3 in services, and $14.3 in commodities. The
cost covered a full-time administrative officer I permanent
position to perform budget, reporting, accounting, and
other functions to support the state projects program (path
2 in the upcoming presentation. There was a cost associated
with one survey needed to support the state projects
program. The numbers carried forward for FY 26 and beyond
to support the large project coordinator and administrative
officer.
2:38:49 PM
RENA MILLER, SPECIAL ASSISTANT, OFFICE OF THE COMMISSIONER,
DEPARTMENT OF NATURAL RESOURCES, remarked that there was
also a capital request on the fiscal note.
Ms. Adoko added that there was a capital appropriations
request of $425.0 for contracting the subject matter expert
and consult for developing program regulations and
contracts and implementing the state projects program.
Co-Chair Foster thanked Ms. Adoko. He moved to the next
fiscal note.
2:39:56 PM
HELGE ENG, DIRECTOR, DIVISION OF FORESTRY AND FIRE
PROTECTION, DEPARTMENT OF NATURAL RESOURCES, (via
teleconference), went through the fiscal note control code
ZmXiS, OMB component number 435. The note showed FY 24
costs of $147.3 including $107.9 for a forester, $10.0 for
travel, $17.4 for services, and $12.0 for commodities. The
note showed a startup cost of $10.0 and supply costs of
$2.0 annually. The out years beginning in FY 25 would
revert to $2.0 annually, for a total of $137.3. Revenues
were not specifically estimated due to timeline uncertainty
and potential project variation. He relayed that credit
sales may occur in FY 28 at the earliest. Revenue generated
from carbon offset projects would be deposited into the
carbon offset fund established by the bill.
Mr. Eng continued to review the fiscal note. Expenditures
for Division of Forestry and Fire Protection (DOF) and
Office of Project Management and Permitting (OPMP) staff
would be funded by unrestricted general funds (UGF), but
the intent was to utilize the carbon offset funds in place
of general fund dollars once revenues began materializing.
The one permanent forester position would primarily be
involved in updating state forest management plans as
required by the legislation as well as inventory and
ensuring management practices adhered to the commitments in
the carbon offset project and meet the requirements of the
projects. Regulations would be developed and adopted by the
commissioner.
2:43:24 PM
Representative Josephson had not heard that the earliest
credit sale would occur in FY 28. He observed that project
development would occur in the coming two fiscal years
followed by the intervening carbon offset project
development timeline, which sounded familiar to project
development. He asked why so much time was needed. He did
not sense that the tribes needed as much time to get going.
Mr. Eng responded that the fiscal note was an estimate and
was developed with experts in the field. He stated that
carbon offset projects were an undertaking. Based on his
experience, the timeline shown in the fiscal note was
fairly typical for a carbon offset project.
Ms. Miller added that Anew had presented on general project
timelines and had indicated that 18 months was a reasonable
time from start to finish for a project, but due to the
variability of conditions in Alaska depending on the
specific project, a second field season may be necessary.
She explained that project timing worked well and could
encompass two field seasons within 18 months, the timeframe
would be more condensed; however, depending on start dates
and field season timing it may take 24 months. She stated
the department hoped to get things off the ground as soon
as possible. There would likely be private landowners and
the department would have to write regulations. She
elaborated there would be a period of time after
regulations were written where the department would field
interest and consider which projects to advance.
Representative Josephson asked if the bill would apply to
private landowners.
Ms. Miller responded in the negative. She relayed there was
language in the state projects area that made it abundantly
clear. She referenced Representative Josephson's mention
that Alaska Native Corporations may have the ability to get
projects going faster. She clarified that had been her
previous reference to the private landowner difference.
2:46:37 PM
Representative Hannan stated that the bill had been talked
about as a forestry bill; however, she observed that out of
the four positions in the three fiscal notes, the forester
position was the cheapest. She remarked that according to
the fiscal notes, the bulk of the money required to operate
the bill would be in OPMP, operated by a consultant to do
website development and monitoring. She stated there had
been discussion about the need to increase the state's
forest management practices and regularly measure and
monitor. She asked if her understanding was accurate.
Ms. Miller responded that there was an important
differentiation between project costs for any particular
project and the cost of the state having the carbon offset
program that would undertake multiple projects that may or
may not all be related to forestry. The things required by
the project including inventory required by the registry,
the computer modeling, the papering of the project design,
and ongoing verification and auditing were all project
costs and were not reflected in the fiscal notes. She added
that looking to the likelihood that some of the greatest
carbon attributes were in the forests, it made forestry
projects a very likely endeavor for the new carbon offset
program. The situation would entail a lot of ongoing work
with DOF as the project continued. She clarified that DOF
would not be doing the project, but it would need to be
doing a number of things to support the project. The
division would also need to manage timber harvests, which
was not technically part of the project.
Representative Hannan referenced the capital budget item in
the OPMP fiscal note. She referenced the contractor that
would develop the website and conduct registry work. She
surmised the contractor was not likely to be an Alaskan
entity. She thought it would be someone dealing with carbon
offset across the country versus someone in Alaska helping
the state manage its forest.
Ms. Miller responded that working specifically with the
registry would be a project cost. She referenced the OPMP
contract cost of $75,000 for website and systems
development and explained that the bill required project
details to be reported by the state regularly. There were
additional funds for expertise on setting up the project
framework and regulations. She noted it was a new field and
the department wanted to ensure regulations were
established with expertise in the field. There was also
$250,000 in capital related to contractual subject matter
expertise (largely legal and commercial) that would help
the state in evaluating contractual and commercial terms
with entities it would be working with on projects.
2:50:53 PM
Representative Josephson referenced Ms. Miller's statement
that the project costs would not be shown in the fiscal
notes. He asked if it was because they were taken from the
state's share of the profit. He asked where the project
costs resided if they were not in the fiscal notes.
Ms. Miller responded that the upcoming presentation would
go into more detail on the topic. She explained that absent
upfront capitalization, the state would be working with a
turnkey type of developer/contractor that would cover the
upfront project costs including inventory, papering, and
computer modeling of carbon storage. The contractor would
receive a portion of the credit revenue in exchange for
frontloading the costs and taking the initial project risk.
In the future there would be incoming revenue from the
project into the fund created under the bill, which would
provide a source of capitalization for future projects
where the state could look at other contractual agreements
and service contracts that would potentially enable the
state to undertake more of the work directly.
Representative Josephson referenced the department's
statements about the need to monitor timber harvest by the
program. He asked if it was fair to say that the bill had
the effect theoretically of slowing timber harvest.
Ms. Miller responded that the department did not expect
carbon offset projects to slow timber sales. Timber sales
would continue to be managed by the division. She explained
that if there was a carbon offset project on lands where
timber sales occurred, the forests would need to be managed
in part under the carbon offset project.
Representative Josephson surmised that it could necessitate
a reduction in harvest.
Ms. Miller responded that DNR did not anticipate a
reduction in harvest under the improved forest management
protocols the state would be doing on those forests. The
department expected to be making a commitment with the
registry to not increase harvest levels to the full annual
allowable cut on land enrolled in a project.
2:54:01 PM
Representative Galvin recalled from a prior presentation to
the committee the idea about a turnkey project where the
state would be able to work with an organization that was
responsible for the detailed work. She remarked that when
she had asked about the costs the organization would charge
it was her impression the answer depended on many different
variables. She considered that it may have something to do
with what was negotiated. She had heard the cost was up to
20 percent of the project. She asked if other states that
may be working on similar legislation ever included "not to
exceed" clauses [on the costs]. She asked if the department
had a process on other projects where it had guardrails in
place.
Ms. Miller responded that Michigan was the only other state
with carbon offset projects on public land. She would
follow up with information on details on the arrangement in
that context. She elaborated that there were some unusual
terms in the RFP [request for proposal], such as the
exclusive right to all future projects on those state
forests. She stated it was always a balance and she
confirmed that details were negotiated. She noted there may
be other things a party may want to negotiate in a
contract. For example, perhaps a developer would train in-
house employees so they would be more able to do projects
in the future without relying on a project developer. She
relayed there was no limit on the topic in the bill. She
believed the protection was somewhat inherent in the
responsibilities of the department in looking out for the
state's best interests and being able to regularly justify
what it was doing as they came before the legislature
annually and other times as requested. She thought the
department had a strong track record of being responsible
in that context.
Representative Galvin remarked that the concept in the bill
was potentially a big ticket item of around $300 million.
She referenced an "amazing project" that someone had
presented in recent months. She reasoned that 20 percent of
that total was a substantial chunk of change to be the
moderator of the work. She understood it was a lot of work,
but also appreciated it was an opportunity for business as
well as for legislators. She thanked the department.
Co-Chair Foster requested a review of the fiscal note from
the DNR Division of Mining, Land and Water.
2:58:06 PM
KRIS HESS, DEPUTY DIRECTOR, DIVISION OF MINING, LAND AND
WATER, DEPARTMENT OF NATURAL RESOURCES (via
teleconference), went through OMB Component Number 3002,
control code OEyBr. She clarified that the fiscal note
pertained to the leasing program only and not for the state
project program previously discussed by OPMP and DOF. For
FY 24 the note included $117.5 for a full-time natural
resource specialist III position, $5.0 for travel, $17.4
for services, and $12.0 for commodities for a total of
$151.9. For FY 25 through FY 29, the total operating costs
dropped by $10,000 because it was a one-time cost in
commodities and supplies to set up the office. The funding
source was UGF and there would be a transition over to
program receipts once revenue started coming in. She
relayed that the division would come back to the committee
if the program required additional positions in the future.
She detailed that the new position was a range 18 and would
initially be used to set up regulations. The position would
travel to help develop the regulations and would
subsequently transition to adjudicating applications for
leases on state land.
Co-Chair Foster requested a review of the fiscal note from
the Department of Revenue (DOR).
3:02:30 PM
ERIC DEMOULIN, DIRECTOR OF ADMINISTRATIVE SERVICES,
DEPARTMENT OF REVENUE, relayed that the DOR fiscal note,
OMB Component Number 123, had been reduced down to zero.
The fiscal note discussed the need for collaboration with
DNR when it came to fiscal management of the program and
generating new revenues for the state. He relayed it was
anticipated there would be substantial collaboration
between the executive leadership of both departments to be
able to bring the credits to market, which would include
conversations with stakeholders as things started to
evolve. The department had decided to come back to the
committee for personal services needs in future budget
cycles as the programs were developed and started to gain
traction. He asked if there were any questions from the
committee.
Co-Chair Foster noted there were currently no questions. He
thanked Mr. DeMoulin.
3:03:39 PM
Co-Chair Foster relayed that the committee would hear two
additional presentations during the meeting. He began with
a presentation from DNR.
Ms. Miller introduced the PowerPoint presentation titled
"House Bill 49: Fiscal Picture," dated May 3, 2023 (copy on
file). She relayed that the bill would allow the state to
stand up two programs for leasing and state projects to
enable the state to monetize natural resources through
carbon. The department was not asking for approval of any
specific project in the legislation. She highlighted that
there was a strong and growing interest in carbon offsets
and capital to be deployed. The department wanted to ensure
Alaska was positioned well to participate in the carbon
business, to make good use of its resources and provide
revenue to the state. The bill included two distinct paths
to monetizing carbon. The first path was state leases to
third parties, referred to as "carbon leases" (bill
Sections 3 through 5). The second path was for the state
itself to undertake carbon offset projects, referred to as
"state projects" (bill Sections 1 through 2 and 6 through
13). The two paths had different costs and different
revenues, which would be reviewed in the presentation.
Ms. Miller moved to slide 4 titled "Path 1: Carbon leases."
As reviewed in the fiscal note from the Division of Mining,
Land and Water, the department would need people to
promulgate regulations and receive and process lease
applications. Once leases were awarded, they would need
ongoing monitoring to ensure conditions were met and that
everything was in line. The department was seeking one
permanent full-time position. There was program receipt
authority for the Division of Mining, Land and Water in the
legislation and ideally, once there was incoming revenue
from carbon leases, the revenue would supplant general fund
and the additional would go to the general fund. The
revenue for the carbon leases was indeterminate in amount
and timing and was driven entirely by demand of people who
have interest in carbon use on state land. She noted it
would vary depending on the area of land lease, the
particular concept, the value of what they were able to
store, and who they were able to generate returns with.
Ms. Miller continued to review path 1 pertaining to carbon
leases on slide 5. She highlighted that timber harvest
rights were not included with a land lease. She provided a
hypothetical example of a carbon lease where a company
wanted to lease 10,000 acres and invested capital of its
own to regenerate a forest. She elaborated that it may be
20 or more years before the trees were large enough to
sequester the amount of carbon needed to meet protocols,
but at that point the company could generate offsets
through the new trees and make revenue. Under the scenario,
while the bill gave options, it was likely the state would
want some kind of annual fee for the land lease and
potentially a percentage of the carbon revenues once there
was revenue coming to the lessee for their work and
invested capital. Under the example, the land and forest
would revert to the state at the end of 55 years.
Ms. Miller reviewed a second hypothetical carbon lease
example on slide 5. The scenario involved a kelp farm
(potentially grown for food production) that overlaid a
carbon offset project to help with kelp production
economics or because they were interested generally. Under
the scenario, the state may get an annual fee for the land
lease and some percentage of the carbon revenue.
3:08:25 PM
Representative Galvin asked why the state would choose to
lease acres to another company that could find its own
turnkey organization to assume risks of a project. She
thought it seemed the state was hiring another middle
manager. She was trying to understand the reasons.
Ms. Miller responded that although the bill required the
division to structure compensation to maximize return to
the state, a lessee's primary motivation may or may not be
profit off the carbon. She used the kelp farm scenario [on
slide 5] as an example. Potentially there would be enough
of a carbon purpose associated to offset some of the
marginal economics. In that instance the state would be
realizing some percentage of revenue related to the carbon
purpose and the ability to advance another program the
legislature had authorized that went to local economic
development. The other example [on slide 5] involved
substantial risk and upfront capital. She noted it may or
may not be something the state was prepared to engage in.
She stated that if a third party wanted to take it on,
there was the potential to let them take the risk that the
trees grow the way they were supposed to on schedule and
that they were able to generate the credits, put upfront
capital in, and still generate some revenue from allowing
someone else to take on the activities.
Ms. Miller believed that in other instances, a lessee's
primary interest may be trying out some newer carbon
purpose things that were not quite as established. Under
the scenario, the lessee would be looking to achieve an
environmental benefit and the revenue was important too in
order to justify and fund the work and the state would get
its share of the revenue. She believed there were a number
of permutations. She reminded committee members that the
state forests were not eligible for lease and would be
reserved for state projects.
Representative Galvin asked if Native organizations had
done anything similar involving leasing of acres and a
middle person. Alternatively, she wondered whether Native
organizations had directly contacted companies looking to
take on a project.
Ms. Miller responded that to her knowledge the landowner
did not lease the land to a developer. She stated her
understanding that the landowner was able to work directly
with a developer as a partner/contractor to develop
projects.
3:12:39 PM
Ms. Miller advanced to slide 7 titled "Path 2: State
Projects - Review." She detailed that the bill stood up the
carbon offset program for the state to undertake its own
projects that would be housed under OPMP. She explained it
was an existing model within DNR that was proven at being
able to manage things spanning different divisions and
needs. The state would be the project proponent and owner
and may work with a partner such as a project developer.
There would be costs to start and manage a project over its
term. The project would generate credits for carbon stored
and the state would sell credits to buyers and generate
revenue.
Ms. Miller continued to discuss path 2 pertaining to state
projects on slide 8. She noted that the committee had seen
similar information from Kurt Krapfl with the American
Carbon Registry and potentially from Josh Strauss with
Anew. The idea was to show how the steps worked within a
project.
Ms. Miller advanced to slide 9 and discussed costs
associated with state projects. There were fixed program
costs regardless of the number of projects the state
undertook. She highlighted that the costs shown on the
slide were reflected in the fiscal notes. The slide also
noted the initial capital to OPMP to establish the
framework and retain expertise. Project dependent costs
included feasibility analysis, implementation (including
the initial forest inventory, computer modeling of the
growth to set a baseline and accountability), papering a
project in order to submit it to the registry, and ongoing
project maintenance (inventories were required periodically
as well as onsite and desktop verifications).
Ms. Miller continued to review project dependent costs on
slide 10. There were a variety of ways for the state to
approach projects including use of state staff and funds or
contracting with a project developer. She elaborated that
the state could hire a project developer on a fee for
service basis or work with the Department of Revenue to
hire separate marketing companies to assist with marketing.
The state could also look to an ala carte concept and
contract directly on a fee-for-services basis with
companies engaged in one particular aspect of the project
development such as counting and measuring trees in the
forest inventory or computer modeling for the growth.
Ms. Miller advanced to state project scenarios on slide 11.
The scenarios featured potential pilot projects identified
by Anew. She clarified that the slide did not indicate the
projects would be undertaken or in the exact form described
by Anew; however, they provided a way to show how the costs
and returns played out over the life of a project. The
scenarios included modest returns, and much would depend on
timing and number of projects, the project sizes, the
verified carbon stored by the projects, the price of
credits, and the marketing success. Ultimately, the money
from the credit sales would flow into the fund created
under the bill. The department saw carbon as an additional
layer of land and resource use that complimented the
existing uses, which did not consume or sever a state
resource, and was additive (e.g., in state forests with
ongoing harvests).
3:17:11 PM
Ms. Miller continued to slide 12 titled "Path 2: State
Projects 1-project scenario." The slide used and expanded
on Anew's crediting tables. The column on the left showed
the project year, the second column showed the total
credits generated in a project, the third column reduced
the credits by 30 percent to account for any leakage, and
the fourth column showed buffer credits at 18 percent on
average (the insurance pool in the event of natural
disasters required by the registry). The fifth and sixth
columns showed conservation and removal credits,
respectively. She believed Mr. Strauss with Anew had
thoroughly described the difference between the two items.
The seventh column showed gross project revenue and the
eighth column reflected the project expense, which was
specific to the project. The next columns showed the net
project revenue and developer share, respectively. She
noted the developer share was 20 percent, if any, because
projects that were not turnkey operations would not be a
flat 20 percent. She elaborated that a fee-for-services
model would be covered in the project expenses. The second
to last column on the right reflected fiscal note/DNR
program costs, which were not part of the project but were
important to show when looking at potential revenue from a
project. The final column was net state revenue that
reflected everything pulled together.
Ms. Miller moved to a scenario on slide 13 where three
projects were done concurrently. She relayed that the big
difference was in the fixed DNR program costs, which had
not changed from the one project slide [12] to the three
project slide [13]. She highlighted a larger scope of
potential revenue [shown in the net state revenue column on
the right].
Ms. Miller continued to slide 14 titled "Path 2: Carbon
Offset Revenue Fund." She explained that revenue from
credit sales would flow to the fund. She referenced Section
6, page 6, lines 13 through 20 of the legislation where the
fund details were laid out. She reviewed the slide:
HB 49 version \U:
• Fund is outside general fund (GF)
• Revenue automatically flows into fund "shall" be
deposited
• Legislative appropriation required for DNR fund use
• Used for purposes of Carbon Offset Program
• Unobligated amount over $10M returns to GF annually
Ms. Miller addressed potential uses [of the fund]. The fund
would go towards paying project bills and required project
maintenance (ongoing costs of recurring inventories and
audits in order to keep generating additional credits from
the project). She elaborated that there may be projects at
some point with other activities involved (e.g., thinning)
that would generate additional credits. The fund would also
be used towards initiating additional carbon offset
projects and feasibility, start-up, and implementation to
continue generating additional revenue to the fund and
general fund.
3:21:16 PM
Representative Josephson asked for verification that state
forests were eligible and a prime target for the program.
Ms. Miller responded that "we've been able to affirm the
potential of that" and trees had a tremendous ability to
store carbon. She stated that trees would be the first
place to start looking at the different projects.
Representative Tomaszewski stated his understanding that
once the fund reached $10 million, anything above that
would start rolling into the general fund. He looked at the
one project scenario for state projects on slide 12 that
showed $11 million in 2032. He asked for verification that
there would be no revenue to the general fund for ten
years.
Ms. Miller responded it was true assuming there was only
one project. She clarified that DNR found it highly
unlikely there would only be one project. The department
thought there was tremendous potential and anticipated
multiple projects.
Representative Tomaszewski observed the costs were $4.5
million during the same time period and $11 million in
revenue.
3:23:09 PM
Co-Chair Edgmon thought that the numbers built into the
ten-year forecast for the state were wildly above what the
committee was hearing presently. He cited $300 million in
the current year, $500 million for the next year, and $900
million coming up. He stated it was perhaps attainable down
the road if every cylinder collected at full speed.
However, the assessment he was hearing was much smaller and
more modest. He stated it was still promising and worth
exploring but did not reflect hundreds of millions of
dollars. He asked for comment.
Ms. Miller responded that the department was discussing and
presenting modest revenues with the affirmed potential. The
department wanted to build on and explore what it believed
to be greater potential. She stated it would depend on what
kind of protocols the state was able to tap into under the
parameters of the bill on what kind of land.
Co-Chair Edgmon asked if it was possible to have several
hundred million in revenue in a handful of years.
Ms. Miller responded it was not possible in a handful of
years due to the initial time constraints. She estimated
there were around four years to do regulations, receive and
evaluate projects, decide what projects to move forward
with, and 18 to 24 months of project development.
3:24:46 PM
Representative Coulombe observed that the expenses in the
fiscal notes and the $447,100 [shown in the DNR program
cost columns on slides 12 and 13] were all coming out of
UGF, but the revenues went into a different fund.
Ms. Miller responded that the positions would be funded by
UGF until there was sufficient revenue coming in from
carbon offset projects to supplant the UGF. She stated it
would be immediately. She relayed that the column showing
DNR program costs did not indicate a fund source. She
explained that if there was revenue in the carbon offset
fund, it would cover the cost and UGF would no longer be
necessary.
Representative Coulombe remarked it did not appear there
would be any revenue in the years indicated by Ms. Miller.
She thought it looked like the state was paying and paying
and then it would magically be flipped.
Ms. Miller confirmed that the state would rely on UGF in
the initial years before credit revenue was flowing.
Co-Chair Foster thanked Ms. Miller for her presentation.
HB 49 was HEARD and HELD in committee for further
consideration.
3:26:42 PM
AT EASE
3:30:30 PM
RECONVENED
^PRESENTATION: ALASKA LIQUEFIED NATURAL GAS PROJECT UPDATE
3:30:39 PM
FRANK RICHARDS, PRESIDENT, ALASKA GASLINE DEVELOPMENT
CORPORATION, introduced himself and his colleague. He
relayed he would provide an update on Alaska Gasline
Development Corporation's (AGDC) commercial structure and
on activities the corporation had undertaken to move the
[Alaska Liquified Natural Gas (LNG)] project forward. He
provided a PowerPoint presentation titled "Alaska LNG
Project Update," dated May 3, 2023 (copy on file). He
reviewed that AGDC was a state corporation created by the
legislature in 2013 with a mission to maximizing the North
Slope natural gas assets to be able to ring them through
and develop infrastructure for Alaska's needs to help lower
the cost for Alaskans and commercialize resources and
provide them to international markets to bring in revenue
to the state.
Mr. Richards moved to slide 3 and stated that the Alaska
LNG project was not the project legislators had heard or
read about over the last 20 years. He explained that some
modifications had been made over the past several years,
primarily around the commercial aspects of the project in
terms of lowering the cost of supply. Additionally, the
concept was to increase revenues to the state and would
transition development back to the private sector for
funding and construction.
Mr. Richards turned to slide 4 titled "Alaska LNG: Gas for
Alaskans and Export." He relayed that LNG stood for
liquified natural gas. The project would utilize resources
in the Prudhoe Bay and Point Thomson Units for a total of
40 trillion cubic feet (Tcf) of proven, conventional
produced gas available for export. The gas in Prudhoe Bay
alone amounted to 8.5 billion feet, which was compressed
and put back down. The project included the development of
an Arctic carbon capture plant on the North Slope where
carbon dioxide (CO2) would be removed, captured, and
sequestered in a reservoir. He explained it would enable
the project to take advantage of the [federal] 45Q tax
credits that would equate to $600 million in additional
annual revenue. The pipeline would run from Prudhoe Bay
paralleling the Trans-Alaska Pipeline System (TAPS) towards
Fairbanks and continuing along the Parks Highway and Alaska
Railroad to Nikiski where an LNG plant would be built
adjacent to the existing Agrium and Kenai LNG facilities.
The LNG would be produced at the plant in Nikiski and
shipped overseas on tankers.
3:33:38 PM
Mr. Richards moved to slide 4 and highlighted that Senator
Dan Sullivan had recently shared with the legislature that
the Congressional delegation had been very supportive of
the project. He shared that Senator Sullivan had traveled
to Asia with AGDC to interface with countries and
offtakers. He noted the senator's enthusiasm and support
was very helpful.
Representative Josephson referenced Mr. Richards' statement
about the $600 million more to the project with 45Q tax
credits. He asked if the amount was net to the state.
Mr. Richards responded that the 45Q tax credits were
extended in a bipartisan effort by Congress. He clarified
that the owners of a carbon plant like the Arctic carbon
capture plant would receive the tax credits. The first five
years would equate to approximately $600 million in cash
available to the operator and the remaining seven years of
the project's life would be in tax credits available for
the producer to sell. He elaborated that the credits would
be $85 per ton and the plant would capture about 7 million
tons per year.
3:35:44 PM
Representative Stapp asked if the plant would qualify for
the direct capture credit of up to $180. He asked for
verification that the amount was on top of the existing
credits available for enhanced oil recovery.
Mr. Richards responded that there were two provisions in
the 45Q tax credits. One was for carbon sequestration
priced at $85 per ton. The other was for enhanced oil
recovery at $55 per ton. He clarified that the credits were
not cumulative.
Representative Tomaszewski asked if the 807 miles of pipe
[shown on slide 4] was large diameter.
Mr. Richards responded that the pipe was 42 inches in
diameter and would be buried for the vast majority of the
line except for fault crossings.
Representative Tomaszewski observed that the proposed route
was well outside the Fairbanks boundary. He asked what kind
of tap was included for the Fairbanks area.
Mr. Richards responded that there was an offtake point for
Fairbanks located off the Chatanika River. The alignment
would run south to Livengood and cross the area around
Minto Flats. He noted it was the first major offtake point
on the line.
3:37:31 PM
Representative Hannan presumed that the monetary
descriptions and benefits Mr. Richards described were
critical through the numbers in the rest of the
presentation. She recalled from one of the committee's
meetings on carbon sequestration that there was 10 years in
the tax code before Congress would have to renew the credit
or it would go away. She wondered if AGDC used the same
timeframe for the development of the project given that the
Arctic carbon capture plant was critical to the economics.
Alternatively, she wondered if the project would extend to
15 to 20 years. She noted she may have the tax code
expiration date wrong.
Mr. Richards responded that AGDC and Goldman Sachs
calculated the tax credit timeframe to be 12 years, which
equated to approximately $7.2 billion available to the
project. He pointed to a chart on slide 6 showing the cost
of supply. He deferred to his colleague for additional
detail in the 45Q tax credit provision.
3:39:06 PM
NICK SZYMONIAK, MANAGER, NEW BUSINESS VENTURES, ALASKA
GASLINE DEVELOPMENT CORPORATION, responded that Alaska LNG
was very competitive with strong economics. The challenge
of moving the project forward was due to its size and
complexity, not the economics. The state's cost of supply
was $6.55 to deliver to Asia including the purchase of the
gas on the North Slope, paying for profits to the investors
of the AK LNG system, and transportation. He highlighted
that the cost was well below LNG market prices in Asia and
was cheaper than Cook Inlet gas. He stated that as any
business owner, the state and investors would not be
selling the LNG at the cost of supply, it would be sold at
market prices. He noted that prices may be linked to crude
oil, Henry Hubb (Lower 48 gas price), or a combination of
the two and fixed costs. The cost of supply included $1.45
for raw gas and fuel, of that $1.25 was the purchase price
of the raw gas from producers. He relayed that the
discussions were currently under negotiations. There was
the possibility that if the gas could be sold above $6.55
that the extra revenue could be shared between the
producers, the state, and investors.
Representative Hannan restated her previous question. She
provided a scenario where the tax code expired in 12 years
and the line was not yet operating. She asked AGDC was
saying that it was immaterial to the economics of the
project. She asked for verification that the project could
move forward without the carbon capture element and the
element was merely an ancillary benefit that made the
project more profitable.
Mr. Richards responded in the affirmative. He shared that
in talks with individuals in Washington D.C. around the
bipartisan reestablishment of the provision, they had seen
the benefit and had recreated it and increased the cost. He
noted that hopefully the bipartisan support would continue
when it needed to be renewed in the future. However, AGDC
was not relying on it, but it was a solid benefit to the
project.
Mr. Szymoniak added that there was a deadline for when
construction needed to start, which he believed was eight
to ten years out. The corporation expected construction to
start within that period followed by the 12-year period. He
stated they did not run a material risk of running out of
time to benefit from the 45Q tax credits.
3:41:53 PM
Representative Cronk remarked that he had the same concern
as Representative Tomaszewski. He highlighted that the
coldest area in Alaska was the Interior and he hoped that
it was not excluded from benefitting from a cheap source of
heat. He asked if all of the land needed to build the line
was secured.
Mr. Richards responded that 93 percent of the land had been
leased to the project by the state or the federal
government. There was 7 percent remaining and AGDC would be
in discussions with the municipalities and private
landowners. He stated that the remaining lands would be
leased prior to the final investment decision.
3:42:54 PM
Mr. Richards moved to slide 7 titled "Lower Cost Energy for
Alaskans." The mission provided by the legislature was the
ability to provide and realize North Slope assets to bring
low cost energy to Alaskans. He detailed that the cost of
supply on the international market was $6.55, which meant
Alaskans would be able to receive the gas at a range
between $4 and $5 per million btu because it would not
require liquification or shipping. The price charts shown
on slide 7 provided an indicator of what the price would be
compared to historic Cook Inlet gas prices. The slide also
showed a price comparison between natural gas, heating oil,
and electricity. The outcome was a significant savings to
households using natural gas or had electricity produced by
natural gas.
Mr. Szymoniak continued to slide 8 titled "Alaska LNG: New
State Revenue." He relayed that the analysis on net state
revenue that would be generated by the AK LNG project had
been produced by the Department of Revenue (DOR). He noted
that AGDC had worked closely with DOR on the inputs. He
detailed that the chart included property taxes at the full
statutory 20 mills, but it only showed the state's share
and excluded the municipal share. The chart also included
the corporate income tax for the upstream and midstream. He
highlighted a significant jump in corporate income tax
revenue around year 10, which was associated with
depreciation of the investment in AK LNG pipeline and
plant. The chart also reflected production tax and
royalties, which accrued from the sale of natural gas and
increased production from Point Thomson that would be
unlocked by a major gas sale to the AK LNG project.
Mr. Richards advanced to slide 9 titled "Positive Climate
Impact." He relayed that the positive impact of the project
would be the replacement of coal in Asia with natural gas.
He pointed to a bar chart reflecting the lifecycle of
greenhouse gas emissions from natural gas versus coal
power. He emphasized that 77 million tons of carbon dioxide
would not be emitted from coal power production by
replacing it with natural gas from Alaska.
Mr. Richards moved to slide 10 titled "Major Permits and
Authorizations." He relayed that the AK LNG project had
gone through the regulatory process led by the Federal
Energy Regulatory Commission (FERC). He elaborated that
AGDC had obtained the federal permits and the two major
state permits pertaining to air quality. The corporation
had the rights-of-way and it would continue to keep the
projects current and ready to go to construction.
3:46:02 PM
Representative Cronk asked for details about the Alaska
Rural Energy Fund.
Mr. Richards responded that that the Alaska Rural Energy
Fund was created in either HB 9 or SB 138 where legislators
saw there were communities that would not be benefiting
from energy off the project. The legislation created an
affordable energy fund that would allow revenues to come
into the state that the legislature could appropriate to
communities without direct access to the project. He
relayed that 20 percent of the royalty payments would be
paid into the fund that could be appropriated by the
legislature.
Representative Josephson wanted to ensure that another bill
sponsored by Senator James Kaufman would not eliminate the
fund.
Co-Chair Foster suggested that Mr. Richards may want to
check with Senator Kaufman to make sure his legislation
would not eliminate something AGDC may need in the future.
Mr. Richards noted that Senator Hoffman had been "pretty
gleeful" about the recognition that the fund was there. He
would follow up with the senator's staff.
Co-Chair Edgmon did not know whether Representative
Josephson was referring to a bill that the committee had
heard on rural electrification. He noted it was completely
different [than the topic at hand].
3:47:48 PM
Mr. Szymoniak relayed that the next several slides would
describe how AGDC was going about getting AK LNG built and
developed with private investors. He stated that over the
years there had been substantial effort and capital spent
on AK LNG by the state and producers. He elaborated that
the effort had gone to a fully permitted project with
significant engineering, design, and field work behind it.
He explained that the permitting and work to date was very
valuable. There were many investors looking to invest in
LNG projects. The asset was fully owned by AGDC and the
corporation had hired Goldman Sachs to raise investment
capital for AK LNG. He reported it would take an additional
~$150 million to get the project to a final investment
decision (FID) when construction would start and the full
$44 billion was committed. Much of the additional funding
would be for front end engineering and design (FEED) and
the overhead and legal and commercial work to get all of
the LNG sales contracts, financing agreements, and other
agreements to advance the project.
3:48:56 PM
Co-Chair Johnson noted there were currently differences
between the funding included in the House and Senate
operating budgets. She explained that one of the reasons
for the difference was the inclusion of a federal
appropriation of $4 million secured by [U.S.] Senator Lisa
Murkowski. She stated that some of the difference was the
House's inclusion of some operating funds for AGDC. She
believed that the Senate had possibly included some capital
funding outside of the $4 million. She asked for details on
the funding AGDC needed.
Mr. Richards responded that the FY 24 operating request in
the governor's budget was approximately $3.1 million for
personal services, travel, services, and commodities to
keep the AGDC operating team moving forward. The funding
provided for a small number of employees, computer
services, rent, heat, electricity, and small commodities.
The $4 million that came in from Senator Murkowski had not
been included in the capital budget request because it had
been working its way through Congress at the time. Congress
had passed the bill and the president had signed it; the
bill included $4 million in federal funds specifically for
AGDC to use in FEED. He elaborated that the FEED effort was
approximately $150 million. The corporation was looking to
the private sector to fund the amount in addition to the
amount provided by Congress. He noted that unbeknownst to
AGDC the federal funding had a match requirement, which was
the reason for a $2.5 million request for state funds. The
funds would go towards moving the project through
commercial and legal aspects and FEED to bring the project
ultimately to FID. He summarized that AGDC's operating
budget request was included in the House's budget. The
second funding request was around receipt authority and
match requirements.
3:52:25 PM
Representative Hannan asked whether AGDC was requesting
that the two additional requests be in the FY 24 or FY 25
budget. She asked if the general fund match was to match a
federal capital receipt.
Mr. Richards clarified that it was a FY 24 request and the
federal fund receipt authority of $4 million was the
Senator Murkowski appropriation for FEED. In order to
utilize the federal funding, there was a state match
requirement of $2.5 million UGF.
Representative Hannan asked if it was the first time the
committee had been notified of the request for inclusion in
the FY 24 operating budget.
Co-Chair Johnson responded that the request was not brand
new. She explained it was the reason AGDC had been invited
to present to the committee. She had learned of the request
recently; it had not been part of the original operating
budget because the federal funding came in mid-session. The
idea was to hear from AGDC to get an update and to be
appreciative of the funding and learn what the legislature
needed to do in terms of matching funds.
Mr. Richards added that Senator Murkowski's request was in
the U.S. operating budget ahead of time; however, AGDC had
not known what the [U.S.] Department of Energy's (DOE)
match requirement would be, if any. He stated it had taken
AGDC almost three months to work through the DOE hierarchy
to get to a program manager and understand there was a
match requirement. He explained it was the reason for the
late news provided to the governor and Office of Management
and Budget. He apologized for the timing of the request and
explained it had been extremely difficult to get a response
from DOE.
3:55:28 PM
Representative Josephson stated his understanding that the
$3.1 million in the House version of the operating budget
was not included in the Senate's version. He asked how AGDC
would move forward without the money if the Senate
prevailed on the issue.
Mr. Richards responded that AGDC would not move forward. He
explained that it would not have the legislative authority
or the funding to be able to continue operations. He stated
that if the budget did not include the funding, he supposed
AGDC would move out of its offices, layoff its people, and
put its project in boxes.
Co-Chair Edgmon stated his understanding that Goldman Sachs
was under agreement to raise investment capital to get the
project to FID, which eventually would lead to the $44
billion construction portion of the project. He asked if
the funding to pay Goldman Sachs was under the service line
item totaling $1,197,000 [shown on slide 20].
Mr. Richards responded that Goldman Sachs was working with
AGDC on a contingency basis and would not get paid until
funds were raised from private sector entities. He
clarified that Goldman Sachs would be paid by the private
sector entities, not AGDC.
3:57:04 PM
Representative Galvin looked at the $1.8 million for
personal services [on slide 20] and considered the
additional $4 million in federal receipts. She asked how
many employees currently worked at AGDC.
Mr. Richards responded there were currently four filled
positions, but there were eight or nine PCNs available.
Representative Galvin asked for verification that the
services request was for other contracting work, not for
Goldman Sachs. She asked what the request represented. She
noted it was not a typical budget for the committee to look
at and she was striving for more clarity on the request.
Mr. Richards responded that the services line represented
paying rent, utilities, IT services, and some small
contracts for personal services. The majority of the work
AGDC had done over the years to advance the project on the
commercial side had been part of the corporation's capital
expenditures. He explained that when the legislature
capitalized the AK LNG fund, AGDC had been utilizing those
funds with the authorization of its board of directors to
advance the project. He stated it was where most of AGDC's
contractual expenses resided.
Co-Chair Foster asked if Mr. Richards was only in town for
the rest of the day.
Mr. Richards agreed.
Co-Chair Foster stated there was time for one additional
question. He offered to bring AGDC back before the
committee at a later date to answer any additional
questions.
3:59:28 PM
Representative Stapp referenced AGDC's testimony that the
project had the best economics of any project in North
America. He asked if ADGC had high confidence that Goldman
Sachs would be able to raise the required $150 million in
private equity needed for FID.
Mr. Richards responded in the affirmative. He relayed that
Goldman Sachs was not doing the work for free; the
financial entity saw the value in the project. He explained
that Goldman Sachs was bringing high value equity
developers and international companies to the table to
advance the project.
Co-Chair Foster asked if Mr. Richards had any closing
comments.
Mr. Richards thanked the committee for its time. He stated
that AGDC was advancing the project and there was keen
interest. Part of the keen interest was working with
investors who were doing their due diligence on the project
and on the state. The corporation was engaged with
investors on a daily basis and its goal was to present
hopefully positive results in the near-term.
Co-Chair Foster thanked the presenters. He noted there may
be an additional meeting scheduled to answer any additional
questions the committee may have.
Co-Chair Foster acknowledged Representative Justin
Ruffridge in the room.
Co-Chair Foster reviewed the agenda for the following day's
meeting.
ADJOURNMENT
4:03:03 PM
The meeting was adjourned at 4:02 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 49 NEW FN DNR Forest Mngmt 042523.pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 49 |
| HB 49 NEW FN DOR Comm Office 041923.pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 49 |
| HB 49 NEW FN DNR Mining Land Water 4-26-23.pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 49 |
| HB3.VerB.SupportingDocs.5.1.23.pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 3 |
| HB49 Fiscal Picture DNR-HFIN 5-3-23 .pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 49 |
| HB 50 2023 04 17 DNR Response to HFIN Q April 11, 2023.pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 50 |
| HB 49 NEW FN DNR Project Mngmt 4-26-23.pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 49 |
| AGDC HFIN 5.3.23 Presentation.pdf |
HFIN 5/3/2023 1:30:00 PM |
AGDC - HFIN 050323 |
| HB 49 NEW FN DNR Admin&Support $ 5-2-23.pdf |
HFIN 5/3/2023 1:30:00 PM |
HB 49 |
| Alaska LNG Revenue Analysis 2023.04.21 - SOA Spring Update AGDC .pdf |
HFIN 5/3/2023 1:30:00 PM |
AGDC - HFIN 050323 |