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 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
| 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 |