Legislature(2023 - 2024)ANCH LIO DENALI Rm
11/19/2024 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation(s): Cook Inlet/royalty Relief Update | |
| Presentation(s): Ak Lng Update | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
November 19, 2024
1:00 p.m.
MEMBERS PRESENT
Representative Tom McKay, Chair
Representative George Rauscher, Vice Chair
Representative Thomas Baker (via teleconference)
Representative Kevin McCabe
Representative Dan Saddler
Representative Stanley Wright
Representative Jennie Armstrong (via teleconference)
Representative Donna Mears
Representative Maxine Dibert (via teleconference)
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representatives Julie Coulombe,
Representative Alyse Galvin
Representative Neal Foster
Representative Cathy Tilton
COMMITTEE CALENDAR
PRESENTATION(S): COOK INLET/ROYALTY RELIEF UPDATE
- HEARD
PRESENTATION(S): AK LNG UPDATE
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
JOHN CROWTHER, Deputy Commissioner
Alaska Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Co-offered the Cook Inlet/Royalty Relief
Update presentation.
DEREK NOTTINGHAM, Director
Division of Oil and Gas
Alaska Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Co-offered the Cook Inlet/Royalty Relief
Update presentation.
WESTON NASH, Commercial Analyst
Division of Oil and Gas
Alaska Department of Natural Resources
POSITION STATEMENT: Co-presented a PowerPoint, titled "Cook
Inlet Oil & Gas Update."
NICHOLAS FULFORD, Senior Director
GaffneyCline
Houston, Texas
POSITION STATEMENT: Presented a PowerPoint, titled "Cook Inlet
Royalty Analysis."
COSTA SWIFT, Vice President
Upstream and Carbon Management Consulting Team
Wood Mackenzie
Sydney, Australia
POSITION STATEMENT: Presented a PowerPoint, titled "Economic
viability assessment and economic value of Alaska LNG project -
Phase 1," during the AK LNG Update presentation.
FRANK RICHARDS, President
Alaska Gasline Development Corporation (AGDC)
Anchorage, Alaska
POSITION STATEMENT: Presented a PowerPoint, titled "Alaka's
Energy Future: The Alaska Gas Pipeline" during the AK LNG
presentation.
NICK SZYMONIAK, New Business Ventures Manager
Alaska Gasline Development Corporation
Anchorage, Alaska
POSITION STATEMENT: As an invited testifier, answered questions
during the AK LNG Update presentation.
ACTION NARRATIVE
1:00:45 PM
CHAIR TOM MCKAY called the House Resources Standing Committee
meeting to order at 1:00 p.m. Representatives Wright, McCabe,
Mears, Saddler, Rauscher, Baker (via teleconference), Dibert
(via teleconference), Armstrong (via teleconference), and McKay
were present at the call to order. Other legislators present
were Representatives Coulombe, Galvin, Foster, and Tilton. Also
present on-line were Representatives Cronk, Representative
Tomaszewski, and Dibert.
CHAIR MCKAY noted the following legislators-elect were present:
Mia Costello, Chuck Kopp, Elexie Moore, and Jubilee Underwood.
^PRESENTATION(S): COOK INLET/ROYALTY RELIEF UPDATE
PRESENTATION(S): COOK INLET/ROYALTY RELIEF UPDATE
1:03:56 PM
CHAIR MCKAY announced that the first order of business would be
the Cook Inlet/Royalty Relief Update presentation.
1:05:23 PM
JOHN CROWTHER, Deputy Commissioner, Alaska Department of Natural
Resources, introduced a PowerPoint presentation [hard copy
included in the committee packet], titled "Cook Inlet Oil & Gas
Update."
1:06:52 PM
DEREK NOTTINGHAM, Director, Division of Oil and Gas, Alaska
Department of Natural Resources, explained the importance of
Cook Inlet gas to the State of Alaska. It provides 70 percent
of electrical and heat power to the state, serving approximately
500,000 people primarily in the Anchorage Railbelt.
1:08:18 PM
MR. CROWTHER noted that Cook Inlet development involves Cook
Inlet oil production as well, which meets some state fuel needs.
1:08:56 PM
MR. NOTTINGHAM continued the presentation with an overview of
the history of Cook Inlet gas and oil production beginning in
1958. Cook Inlet has produced over 104 billion barrels of oil
and 12 trillion cubic feet (tcf) of gas from 26 producing fields
and 8 different companies. Gas production had been declining
since 1990. He discussed the potential of remaining resources,
pointing out the potential for 14 tcf of conventional gas in the
Cook Inlet Basin located in an area of approximately five
million acres, some of which is in inaccessible lands such as
wildlife refuges or in areas which would not be economically
viable. He described the bidding and leasing processes specific
to Cook Inlet, defining oil and gas units and how they relate to
the lease processes. He explained how primary lease terms would
be extended when a company begins to produce commercially from
that lease. He also described how the division manages surface
and subsurface resources, maximizing recovery and efficiency
using annual development plans. He reviewed the different types
of leases and the number of years those leases would encompass
as well as several types of exploration leases. He talked about
how the leases could be extended beyond exploration to
production or be returned to the state and become available to
other companies for potential future leases. He explained that
oil units and gas units are managed by annual development plans.
1:15:15 PM
MR. NOTTINGHAM resumed his presentation by describing lease sale
results in 2024, pointing out the very competitive leasing terms
that were offered in order to attract new investment. The
primary bids were from Hilcorp Alaska. He directed the
committee's attention to the graph on slide 7, which showed the
Cook Inlet Production History and slide 8, which showed the oil
and gas companies that were lease-holders both historically and
currently. He said that Cook Inlet oil and gas production has
declined considerably since peak production years, but the
fields which were big producers in 2000 continued to produce a
significant portion of the gas from the inlet. He also pointed
out that there have not been significant new discoveries in the
last 25 years. He drew the committee's attention to slide 9,
titled "Cook Inlet Production by Field," which showed the 2024
fields, producers, lessees, and the oil and gas production. He
reviewed the changes over time, referencing several companies
which are no longer using Cook Inlet gas, such as the Kenai LNG
plant and the Nutrien Fertilizer Plant, and discussed the
reasons they were no longer in production. As gas prices
increased, products from the liquified natural gas (LNG) plant
and the fertilizer plant were no longer economically viable.
1:20:01 PM
CHAIR MCKAY asked whether lower gas prices would result in
resumed production by these and other investors, and if Alaska
could offer lower gas prices, whether it would result in a
return of industries and jobs.
MR. NOTTINGHAM responded that he believed that if there was a
lower cost feed stock, some of the industries would come back.
He next turned his attention to an explanation of gas storage:
how much can be stored; how storage functions; and how much is
currently being stored.
1:23:38 PM
CHAIR MCKAY referred to House Bill 50 passed at the end of the
Thirty-Third Alaska State Legislature and pointed to provisions
of the legislation that expanded gas storage capacity, and he
asked about Hilcorp's request for additional storage.
MR. CROWTHER responded that Hilcorp has been doing open season
to solicit additional interest in storage volumes by potential
entities such as utilities and anticipates filing with the
Regulatory Commission of Alaska (RCA) to allow storage rates and
tariffs for those fields. The department has modified the
leases to allow Hilcorp to do its own storage in those fields in
order to allow third party storage.
1:25:43 PM
WESTON NASH, Commercial Analyst, Division of Oil and Gas,
continued the PowerPoint presentation on slide 13, titled "DNR
2022 Cook Inlet Forecast." He explained the purpose of doing an
independent analysis of the gas supply in Cook Inlet, the
methodology used, and the key assumptions. The primary
assumption was that there would be 15 development wells per year
until 2030 and no new wells after that. He also described a
hypothetical model for new gas development in Cook Inlet, which
included estimated investments as well as estimated proportional
costs. He called the committee's attention to the graph on
slide 15, which illustrated Cook Inlet gas demand projected over
time from current activity in 2024 to 2041. He then showed
slide 16, which summarized the 2024 drilling and production
activities and slide 17, which illustrated the results of three
seismic surveys that were released in 2024. Additional seismic
surveys are expected to be released over the next two to three
years. The final slide showed the statutes that apply to oil
and gas royalties and leasing.
1:34:00 PM
CHAIR MCKAY questioned whether the royalty modifications
referred to in AS 38.05.180(j) are subject to change with
administrative changes in Alaska.
MR. CROWTHER explained the process for modifications under that
statute and how it would provide some durability. There are
conditions that can cause an end to a royalty modification, but
they would not be terminable unilaterally or purely based on a
change in policy preference.
1:35:55 PM
REPRESENTATIVE MCCABE referred to the graphics on slide 10 and
asked why Marathon was not included on the chart.
MR. CROWTHER responded that Marathon is the petroleum refiner on
the Kenai Peninsula and is using some natural gas in its
operations. These are included in the "Commercial" bar on the
chart. Marathon is considered a key part of the energy mix in
Southcentral Alaska because its projects provide heat, fuel, and
electricity.
REPRESENTATIVE MCCABE asked whether Marathon is one of the two
gasoline refineries remaining in Alaska.
MR. NASH said that there are three refineries in Alaska, but
Marathon is the only Alaska refinery producing gasoline for
vehicle use.
REPRESENTATIVE MCCABE drew attention to the chart in slide 15.
He asked about the difference between heating and total demand,
the extra 26 billion cubic feet (bcf), and whether it refers to
electrical production.
MR. NASH responded in the affirmative.
1:37:45 PM
REPRESENTATIVE SADDLER reiterated Representative McCabe's
earlier question regarding whether a commissioner could change a
royalty relief agreement or end it.
MR. CROWTHER explained that after royalty relief is formally
offered and effectuated by the department, it is a contractual
change between the state and the lessee. Therefore it can't be
changed unilaterally by the state. There may be a condition or
limitation on the royalty relief that causes it to later expire
or terminate, but changes cannot be made simply because there is
a change in administration.
1:39:02 PM
REPRESENTATIVE MEARS asked for clarification regarding the
changes in gas productivity and availability for heating and
production as illustrated in the chart on slide 15.
MR. NOTTINGHAM explained that some of the gas was used to fuel
production of electricity and heating as well as commercial and
industrial operations.
1:40:30 PM
CHAIR MCKAY questioned which slide would show the proven gas
reserves that are remaining and accessible for Kitchen Lights
and Cosmopolitan.
MR. CROWTHER called Representative McKay's attention to the
green bars on slide 15. He explained that they show the known
undeveloped reserves equivalent to approximately 300 bcf.
Bluecrest, which operated Cosmopolitan, identified approximately
250 bcf. The Kitchen Lights unit, operated by HEX/Furie, has
identified 200 to 300 bcf of what it believes is developable
gas.
1:42:40 PM
REPRESENTATIVE MCCABE asked for confirmation that Cook Inlet gas
for electricity and heating could be extended to 2030 if Kitchen
Lights and Cosmopolitan were able to expand their operations.
MR. CROWTHER agreed with Representative McCabe's assessment and
suggested that new development activity and additional resources
might extend a little beyond that.
CHAIR MCKAY commented on the possibility of experiencing
electrical and heating shortages if the known undeveloped
reserves are not utilized.
MR. CROWTHER agreed that without additional resource
availability, shortages were estimated starting in 2028.
1:43:30 PM
CHAIR MCKAY introduced Nicholas Fulford, Senior Director of
GaffneyCline, explained that GaffneyCline is currently under
contract with the Legislative Budget and Audit Committee.
1:44:00 PM
NICHOLAS FULFORD, Senior Director, GaffneyCline, directed
attention to a PowerPoint, titled "Cook Inlet Royalty Analysis"
[hard copy included in the committee packet]. He began his
presentation by explaining the rationale behind the work
presented to the committee. He set out the broader developments
affecting the global investment environment in the oil and gas
industry. He referred to slide 2, titled "Market Conditions,"
pointing out that the last four to five years have been
exceptionally disruptive for the oil and gas industry.
Disruptive events have created a more difficult investment
scenario for gas and oil by developers, bankers, and financiers.
That means price volatility for gas and oil with subsequent
significant changes in cash flow. This results in a difficult
environment for predicting financial revenues. As capital
investments go up, the concerns of investors increase.
Investors are now demanding better capital discipline with
improved action on climate policy and climate mitigation as part
of oil and gas developments. These are some of the increased
challenges to attracting investment to oil and gas
jurisdictions.
1:48:00 PM
MR. FULFORD moved to slide 3, titled "Energy Demand and
Competition for Upstream Capital." He discussed several
scenarios including a high increase in energy demand versus the
possibility of a net zero situation. The uncertainty has
resulted in lower investments by the "Super Majors." However,
there have been recent improvement globally in rate of return as
well as higher investments in conventional oil and gas projects.
1:50:01 PM
MR. FULFORD moved to slide 4, titled "Responses to Changes in
Market Conditions." He asked the committee to consider the
global response to changes in the markets, pointing out that
many governments have enacted changes in royalties for the
purpose of attracting investment. The chart on slide 4 shows
that many countries have legislated changes in their royalties
in order to attract investment. He commented that all over the
world, governments have considered the trade-off between state
revenues in taxes and royalties and the ability to attract
investment. This situation has caused some of the investment
hesitation for future development in Cook Inlet. He moved to
slide 5, titled "Increased Consideration of Asset Specific
Characteristics," and pointed out that the price of natural gas
in global markets has dropped below what it used to be in
previous years, causing the economics of specific gas
developments to suffer.
1:53:00 PM
CHAIR MCKAY asked for clarification regarding the fourth bullet
on slide 5.
MR. FULFORD responded by pointing out the differences between
dry gas and condensate. When the value of the condensate is
high, the natural gas is almost a byproduct and has a very low
cost. The economics are more difficult with a dry gas
development with no financial support from liquid condensate.
CHAIR MCKAY asked whether Point Thompson was a good example
because it is a condensate and a natural gas field.
MR. FULFORD agreed.
1:54:39 PM
MR. FULFORD showed slide 6, titled " Considerations for Cook
Inlet." He asked the committee to take the last few slides into
consideration when looking at Cook Inlet. In addition to global
concerns about capital investment, Cook Inlet presents some
particular features which makes investment problematic. One is
the increase of cost which affects not only Alaska but also the
global market. He described the core development concerns as
having an aging infrastructure; lack of access for some
services; challenging climate and environmental considerations;
less transportation availability; and the liabilities involved
with decommissioning a facility. He explained that gas buyers
are seeking diversified energy sources. He also broached the
subject of a possible gas line from the North Slope.
1:57:16 PM
CHAIR MCKAY referred to one of the factors referred to by Mr.
Fulford on the slide, titled "Market Conditions," which
pertained to investors demands. He asked what "action on
climate change" referred to. He expressed his understanding
that investors will not finance projects unless there is a
framework to strip the carbon out.
MR. FULFORD pointed out the complexity of the issue. He
explained that many lenders have risk committees and regulatory
constraints which prevent them from investing in unmitigated oil
and gas development. However, the banks are also in the
business of lending and earning interest, so many of them have
developed a more realistic view toward climate policy. Measures
which could enable decarbonization would probably be sufficient
to address many of the investors' concerns.
1:59:41 PM
REPRESENTATIVE SADDLER questioned whether the risk factors were
in any particular order such as greater to lesser.
MR. FULFORD replied that it was a random list, but the biggest
risks were first, to establish a reliable long-term buyer, who
will continue to support gas price terms and second, to
determine what contractual framework would mitigate against
significant price changes if the gas pipeline were connected to
the Anchorage area. In response to a follow-up question, he
said he believed the greatest supply risk would be cost
pressures and the greatest market risk would be securing a long-
term gas supply contract with an appropriate buyer. The
reference to gas buyers actively seeking diversification
represents an ongoing concern.
2:01:46 PM
MR. FULFORD drew the committee's attention to the slide, titled
"Development Cases Evaluated," which illustrated two
hypothetical Cook Inlet projects. The first hypothetical was a
standalone shallow water gas field, and the second was the
incremental development of an existing onshore gas-condensate
field. The two biggest economic factors in gas development
would be the resource size and gas price.
2:04:53 PM
CHAIR MCKAY requested clarification regarding pricing. He asked
whether Alaska would see more investment and more drilling if
the current royalty of $8.50 per million cubic foot (mcf) was
increased to $12 to $15 mcf.
MR. FULFORD responded that it was a logical conclusion based on
the information presented on the slide.
CHAIR MCKAY referred to the gas reservoirs in Cook Inlet and
asked whether Cook Inlet pricing would be affected if LNG was
purchased on the global market for $15 mcf to meet increasing
demand.
MR. FULFORD responded by suggesting a third alternative which
would be to offer a Cook Inlet gas developer a similar price in
order to facilitate development which would bolster the supply
of gas to Anchorage.
CHAIR MCKAY presented a hypothetical scenario in which
Bluecrest, Hilcorp, and HEX/Fury were approached and told that
LNG was going to be imported at $15 per mcf. In order to
prevent this, he hypothesized, these companies might drill more
wells at $15 mcf instead.
MR. FULFORD said that was a reasonable assumption.
2:08:16 PM
REPRESENTATIVE SADDLER asked whether, under Chair McKay's
scenario, importing LNG would enhance or erode royalty rates.
MR. FULFORD explained that the issue was too complex for a
simple answer.
2:09:59 PM
MR. FULFORD moved to the slide, titled "250 bcf New Development"
and called the committee's attention to the difference between
the left and right columns. He pointed out the difference
between a 10-year royalty relief and a permanent royalty relief,
saying that it would be relatively minor in terms of investment.
He also referred to the challenges of supporting a new offshore
platform. Some of the challenges would be mitigated by tying to
an adjacent facility or by tying to the shore. He then
addressed other elements in the economics of Cook Inlet gas
development. If an offshore platform is funded, a 500bcf
recoverable gas volume is significantly more attractive than a
250bcf of recoverable gas.
2:14:56 PM
CHAIR MCKAY mentioned that the Cosmopolitan field is a 230 bcf
proven gas field.
MR. FULFORD commented that the economics would be improved if
there were ways to increase the resource. He then segued into a
discussion regarding how a dry gas resource can be ramped up
into full production relatively quickly and the capacity would
have a significant impact on the economics of the well. He then
explained the scenarios presented in the next two slides, titled
"Example Economics - Impact of 100% Take or Pay and flat daily
nominations" and "Example Economics - Impact of potential Gas
Line/Price Adjustment ($1/MM Btu discount in 2035)." He
compared GaffneyCline's analyses with those completed by DNR and
described the similarity of the results. He concluded his
presentation with several takeaways including a review regarding
the challenges of a 250 bcf offshore development; a description
of steps which could facilitate exploration and development; and
comments regarding HB 393 and HB 280.
2:18:43 PM
CHAIR MCKAY referred to prior analyses of royalty relief versus
royalty production. It had been suggested that the state
revenues lost by offering developers royalty relief would be
significantly less than the savings of providing gas to
consumers.
MR. FULFORD allowed that was possible, but additional study was
needed to determine what the comparison of royalty relief and
savings to consumers would actually be.
2:19:58 PM
REPRESENTATIVE SADDLER pointed out that the State of Alaska has
authority over royalties, but other factors are outside the
state's control. He explained that royalties are a more certain
source of revenue.
2:21:14 PM
REPRESENTATIVE MCCABE responded that the point of royalty relief
is to get affordable gas to Alaskans.
2:22:24 PM
REPRESENTATIVE MEARS pointed out that some analyses have
indicated that the new floor for natural gas would be up to $14
bcf whether it is Cook Inlet gas, imports, or the proposed gas
pipeline.
2:23:40 PM
CHAIR MCKAY reminded committee members that they should consider
the socioeconomic impacts on constituents that rely on the oil
and gas industry in Cook Inlet, such as job security.
2:25:41 PM
The committee took an at-ease from 2:26 pm to 2:44 pm.
^PRESENTATION(S): AK LNG UPDATE
PRESENTATION(S): AK LNG UPDATE
2:44:06 PM
CHAIR MCKAY announced that the final order of business would be
the AK LNG Update presentation.
CHAIR MCKAY reviewed that under HB 268, the legislature had
asked for an independent third-party analysis of the feasibility
of a phased approach to constructing the Alaska Liquified
Natural Gas (AK LNG) project.
2:47:45 PM
COSTA SWIFT, Vice President, Upstream and Carbon Management
Consulting Team, Wood Mackenzie, as part of the AK LNG Update
presentation, began a PowerPoint, titled "Economic viability
assessment and economic value of Alaska LNG project - Phase 1"
[hard copy included in the committee packet]. He stated that
Cook Inlet gas production has declined, and exploration wells
have not discovered enough to replenish reserves, which are
expected to be depleted by the mid-2030s. The demand for gas
has declined over the past 20 years, and the cost of gas has
increased. It is expected that prices will continue to increase
as the reserves are depleted. Mr. Swift described two
alternatives to address the supply gap: a new gas pipeline and
LNG imports. The new gas pipeline would connect Southcentral
Alaska with the northern fields. The LNG imports would require
infrastructure to import and store LNG.
2:53:52 PM
MR. SWIFT noted that if the pipeline connecting Southcentral
Alaska and the northern fields were built, there is an
anticipated increase in demand for gas. Fairbanks would shift
to gas, the Nikiski refinery would increase its gas demand, and
there would be additional industrial demands. In response to
questions from Chair McKay, Mr. Swift stated that there would be
an increase in industrial gas demand, power gas demand, and
Fairbanks gas demands. In response to Representative McCabe,
Mr. Swift stated that the Fairbanks resident would save between
$800 and $1,500 annually on their fuel with the construction of
the pipeline.
MR. SWIFT then moved on to four scenarios describing the
existing gas demand, the existing gas demand plus additional gas
demand based on historical gas demand, the estimated potential
for new demand brought by high-consuming facilities, and the
estimated potential for new demand brought on by the
construction of an LNG facility. Of the four scenarios, the
construction of an LNG facility would entail the largest
potential for increased gas demand. He noted that the total
estimated cost of a pipeline connecting Southcentral Alaska and
the northern fields of Alaska is approximately $10.8 billion for
Phase 1 and compared the cost to recently built and proposed
pipelines, both in the United States and internationally.
3:00:15 PM
MR. SWIFT, in response to Chair McKay, noted that Mountain
Valley and the Canadian Coastal Gas Link were both built in
highly populated areas with increased regulatory challenges.
Both factors have lengthened the timeline and increased the
overall cost of the pipeline. In response to further committee
questions, Mr. Swift noted that the cost is acquired through a
top-down benchmark approach and does not have an additional
breakdown of costs for the pipeline. He said the cost of the
Alaska LNG Pipeline is within the parameter averages, albeit on
the higher end of costs. Alaska provides unique challenges when
it comes to construction projects. He said he would follow up
with data regarding cost overruns for the other pipelines listed
on slide 10 of the presentation. He clarified that the projects
listed in italics are unfinished. Finally, he noted that the
cost of the Fairbanks spur was not included in Scenario 1 on
slide 9. He noted that any spur required to connect to the
Trans-Alaska Pipeline System [TAPS] would need to be paid for,
and a tariff would be involved in the cost of the spur.
3:09:20 PM
FRANK RICHARDS, President, Alaska Gasline Development
Corporation (AGDC), at the invitation of Chair McKay, stated
that there is an offtake point near the Chatanika River on the
Alaska LNG Pipeline corridor. The route goes up and over Murphy
Dome. The cost estimate is $180 million, with the tariff
estimated to add 0.80. He stated the permitting process went
forward under the Army Corps of Engineers.
3:10:43 PM
MR. SWIFT noted that additional costs, including Compression,
Cook Inlet Crossing, and Point Thompson Expansion would bring
the total to approximately $14.3 billion. In response to Chair
McKay and Representative Saddler, Mr. Swift noted that that the
project would originate in Prudhoe Bay and the offtake would
assume Great Bear Pantheon Gas through the life of the analysis
that Wood Mackenzie had completed [2070].
3:15:14 PM
MR. SWIFT, on slide 12, advised that of the four scenarios, the
Alaska LNG Pipeline has the most potential to lower the cost of
gas to $2.23/gallon. On slide 13, he noted how additional
factors, such as property tax and a federal loan guarantee, have
the most impact on the cost of gas. Slide 13 isolated many
variables and calculated their individual impact on the
delivered cost of gas. Mr. Swift confirmed that the gas from
Prudhoe Bay has a higher carbon dioxide (CO2) content, which
would have an additional impact on the cost of gas. In response
to Chair McKay, he noted that every billion dollars that the
capital expenditure (CAPEX) is reduced effectively equates to a
dollar reduction of the delivered cost of gas.
MR. SWIFT continued to slide 14. He stated that in the analysis
of LNG imports as an alternative, Wood Mackenzie considered the
actual cost of the material [LNG], the shipping costs, the cost
to revert the liquid back to its gaseous form, and the cost of
onshore gas reception. He started with the most likely
contracts for purchasing LNG: Japan Korea Marker (JKM) or oil-
indexed long-term pricing. He noted that JKM is more likely for
long-term purchase agreements [10-20 years]. Next, shipping
costs can have an impact on the delivered cost of LNG. Mr.
Swift noted in response to Representative McCabe that Alaska
does have an advantage due to its proximity to the LNG markets
in the Pacific. Mr. Swift described shipping routes and costs
from JKM to Alaska routed through Canada, Australia, or Mexico.
CHAIR MCKAY offered his understanding that under the current
federal administration, there was an existing ban on the export
of LNG from the United States.
MR. SWIFT clarified that there was a pause on permitting for new
LNG projects.
CHAIR MCKAY then asked how much of Japan's imported LNG comes
from Russia.
MR. SWIFT responded that he did not have that information at the
time.
3:31:42 PM
MR. SWIFT moved to the next part of the analysis regarding the
floating storage regasification unit (FSRU). On slide 17, Mr.
Swift noted the graph showing the average cost range of an FSRU.
He stated that operating FSRUs generally show a low utilization
rate ranging from 40-45 percent annually per unit. He stated
the larger the unit, the lower the cost of regasification.
There may be additional costs associated with onshore storage
operations, but there could also be opportunities for
optimization.
3:36:48 PM
MR. SWIFT stated the fourth cost consideration is the cost of
connecting the FSRUs to the existing network of pipelines or the
onshore reception. That connection involves building a jetty,
constructing an offloading facility, and constructing facilities
necessary to connect to the existing network. Of the 48 FSRUs
in Wood Mackenzie's database, the CAPEX ranges from $50 million
to $500 million.
MR. SWIFT stated that the total LNG import cost is estimated to
range between $10.21 per metric million British thermal units
(mmbtu) and $13.72/mmbtu whereas the total cost of gas delivered
via pipeline would range between $2.23/mmbtu and $12.80/mmbtu.
MR. SWIFT moved on to slide 20, which detailed the approach to
assess the socioeconomic benefits of Alaska LNG Phase 1. This
approach included: total capital expenditure for construction,
benefits for the lifetime of the project, indirect and induced
benefits, and potential for savings. Mr. Swift stated that the
in-state economic impact for LNG imports is approximately $1.4
billion, whereas the in-state economic impact for the Alaska LNG
Phase 1 is approximately $16.5 billion, with an estimated $6.2
billion in savings on cost to the consumer. In response to
Representative McCabe, Mr. Swift noted that the graphs on slide
21 do not pertain to any government tax credits that may be
applicable. In response to Representative Saddler, Mr. Swift
defined "economic impact" as gross value added to the overall
GDP of Alaska.
MR. SWIFT moved on to slide 22, which illustrated the impacts in
jobs created from Alaska LNG Phase 1 and from the LNG imports
alternative. The graphs included direct, indirect, and induced
jobs and were divided between construction and operations
phases. In the construction phase, Alaska LNG Phase 1 is
projected to create 4.0 times as many jobs as LNG imports. In
the operations phase, Alaska LNG Phase 1 is projected to create
4.6 times as many jobs as LNG imports. Mr. Swift stated this is
primarily due to a larger in-state construction scope for Alaska
LNG Phase 1. In response to Chair McKay, Mr. Swift noted that
the jobs created are only related to the LNG imports or Alaska
LNG Phase 1.
3:45:34 PM
MR. SWIFT, in response to Representative Dibert, explained the
bullet point on slide 8 noting "90% penetration with a 3-year
transition (2031-2033)" was an assumption based on the
construction of Alaska LNG Phase 1. He then continued to slide
23, detailing some additional benefits specific to Fairbanks
with the switch from wood/oil to gas for its energy needs,
including cleaner air and removing Fairbanks' nonattainment
designation, which could increase access to private and/or
public investments.
3:51:58 PM
MR. SWIFT moved on to the last slide. In summary, the cost of
the pipeline would be approximately $10.8 billion. With the
decline of the Cook Inlet gas supply, Wood Mackenzie forecasts a
demand gap to begin by 2030. Finally, Mr. Swift reiterated the
analysis of two potential options to address the supply and
demand gap: natural gas supply via pipeline or natural gas
supply via LNG imports.
3:59:50 PM
CHAIR MCKAY invited Frank Richards to begin his portion of the
presentation.
MR. RICHARDS, as part of the AK LNG Update presentation, began a
PowerPoint, titled "Alaska's Energy Future: The Alaska Gas
Pipeline" [hard copy included in the committee packet]. He said
the pipeline would begin in the North Slope Borough and end in
the Matanuska-Susitna ("Mat-Su") Borough, where it ties into the
existing infrastructure. Phase 2 entails construction of gas
treatment facilities in the North Slope and LNG export
facilities. On slide 2, Mr. Richards noted that the project has
gone through all necessary regulatory processes. On slide 3, he
noted that the Phase 1 Pipeline can compete with the cost of
importing LNG. He stated that Alaskans will benefit from lower
cost energy. On slide 5, he stated his belief that the Wood
Mackenzie analysis showed a positive economic value to the
state.
MR. RICHARDS moved on to slide 6, which described the timeline
of the pipeline. During 2025, the basic engineering of the
backstop agreement must be completed, or the front-end
engineering design (FEED). During 2026, financing for the FEED
backstop must be secured. Pipeline construction is estimated to
start in 2027, with the construction estimated to be completed
by 2031. On slide 7, Mr. Richards noted that FEED is the final
step before final investment decision (FID) and construction can
begin on the Alaska gas pipeline.
MR. RICHARDS stated, on slide 8, that the Alaska Gas Development
Corporation (AGDC) was working on accruing utility support and
the support of other LNG developers. He moved on to slide 9 and
described the North Slope gas supply. He said, due to low-cost
access, Great Bear Pantheon is the preferred supplier. However,
back up supply agreements are required, given that the fields of
Great Bear Pantheon are still in development. He noted that
"back up" gas suppliers are necessary for financing. Mr.
Richards stated AGDC is in talks with Prudhoe Bay, Point
Thomson, and the Satellite Fields. He noted that these backup
fields either need gas treatment to remove carbon dioxide (CO2)
or require additional infrastructure.
4:09:07 PM
MR. RICHARDS, in response to a question from Representative
McCabe about whether Canada might be a supplier for the
pipeline, said that AGDC wanted to look at Alaska suppliers
first, as that would be the most cost-effective. Mr. Richards
moved to the final slide of the presentation and stated that
AGDC's primary goal was to raise funds for the Alaska LNG FEED
and development costs to reach FID. He noted that the
"development capital" needed for the full Alaska LNG scope was
$150 million, and $50 million for Phase 1. Mr. Richards also
stated that AGDC plans for the funds to come from private
investors and developers. In response to Representative
Saddler, he said the State of Alaska would be responsible for
construction costs if the it elected to take on a percentage of
ownership of the pipeline.
4:13:50 PM
NICK SZYMONIAK, New Business Ventures Manager, Alaska Gasline
Development Corporation, reiterated that the funds are expected
to come entirely from the private sector, and the state would
have the option to contribute financially.
4:17:14 PM
MR. RICHARDS, in response to Representative Mears, said the
legislature intended for the renewable energy fund (REF) to
receive revenue from a portion of state taxes, to provide
benefits to communities that do not have direct access to the
pipeline. In response to Representative McCabe's suggestion of
the use of bond funds, Mr. Richards replied that it is up to the
legislature to decide if and how it would like to fund the
project. He also noted that the legislature gave AGDC bonding
authority. In response to a remark from Representative Dibert
that any funding allocation should include the Fairbanks spur
and any necessary infrastructure, he assured that an update
would be provided in the cost estimate through FEED. In
response to Representative Baker, he clarified that all the
federal permits had been completed, but not all the state and
municipal permitting had been completed.
4:29:26 PM
CHAIR MCKAY stated that the State of Alaska is currently funded
60 percent through government savings and 40 percent through
resources, which is primarily oil production. He opined that
all projects that contribute to the state treasury, the
permanent fund, and the permanent fund dividend (PFD) should be
seriously considered by the legislature. He stated his belief
that the legislature should prioritize revenue sources that do
not involve taxing Alaskans. He thanked the presenters.
4:31:29 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 4:31 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2024.1118 WM AGDC Alaska LNG Phase 1 vFinal_Legisture Summary.pdf |
HRES 11/19/2024 1:00:00 PM |
|
| 2024 11 19 HRES DNR Cook Inlet Update Presentation.pdf |
HRES 11/19/2024 1:00:00 PM |
|
| AGDC Resources Presentation for Nov 19 final.pdf |
HRES 11/19/2024 1:00:00 PM |
|
| Gaffney Cline HRES Slides - Cook Inlet Royalty Analysis.pdf |
HRES 11/19/2024 1:00:00 PM |