Legislature(2025 - 2026)BUTROVICH 205
01/26/2026 03:30 PM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| Presentation(s): Key Issues and Recommendations: Alaska Lng & Phase 1 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
JANUARY 26, 2026
3:31 P.M.
MEMBERS PRESENT
Senator Cathy Giessel, Chair
Senator Bill Wielechowski, Vice Chair
Senator Matt Claman
Senator Forrest Dunbar
Senator Scott Kawasaki
Senator Robert Myers
Senator George Rauscher
MEMBERS ABSENT
All members present
COMMITTEE CALENDAR
PRESENTATION(S): KEY ISSUES AND RECOMMENDATIONS: ALASKA LNG &
PHASE I
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
NICK FULFORD, Senior Director
Gas, LNG & Energy Transition
GaffneyCline Energy Advisory
Houston, Texas
POSITION STATEMENT: Co-presented: Key Issues and
Recommendations: Alaska LNG & Phase I, continued from January
23, 2026.
ANDREW DUNCAN, Director
Facilities and Costing Engineering
GaffneyCline Energy Advisory
Singapore
POSITION STATEMENT: Co-presented: Key Issues and
Recommendations: Alaska LNG & Phase I, continued from January
23, 2026.
ACTION NARRATIVE
3:31:25 PM
CHAIR GIESSEL called the Senate Resources Standing Committee
meeting to order at 3:31 p.m. Present at the call to order were
Senators Dunbar, Kawasaki, Claman and Chair Giessel. Senator
Wielechowski arrived immediately thereafter. Senators Myers and
Rauscher arrived thereafter.
^PRESENTATION(S): KEY ISSUES AND RECOMMENDATIONS: ALASKA LNG &
PHASE 1
PRESENTATION(S): KEY ISSUES AND RECOMMENDATIONS: ALASKA LNG AND
PHASE I
3:32:06 PM
CHAIR GIESSEL announced the presentation: Key Issues and
Recommendations: Alaska LNG & Phase I, continued from January
23, 2026.
3:33:50 PM
SENATOR WIELECHOWSKI joined the meeting.
3:34:15 PM
NICK FULFORD, Senior Director, Gas, LNG & Energy Transition,
GaffneyCline Energy Advisory, Houston, Texas, co-presented: Key
Issues and Recommendations: Alaska LNG & Phase I, continued from
January 23, 2026. He moved to slide 8: Canadian Pacific Coast
Projects.
3:34:45 PM
MR. FULFORD moved to and narrated slide 9. He said the
fundamental economic model for Canada's project is very similar
to the model for Alaska. He noted that Canadian projects
typically used [Henry] Hub-based gas pricing at a discount with
feed gas costs projected around $2.50 to $3.00, whereas Alaska's
gas costs had been estimated lower, around $1.00 to $1.25.
However, Alaska faced the added expense of building a large gas
processing facility. The speaker emphasized that examining
Canadian projects provided valuable insights due to these
parallels.
[Original punctuation provided.]
Similarities between Canadian LNG projects and Alaska
• The Canadian and Alaskan business model and
economics are similar; thus, many lessons can be
derived from projects in BC
• The competitive features of the project stem from
low-cost gas and low-cost shipping
• Core infrastructure includes a costly long gas
pipeline across varied terrain.
• Canada and Alaska are both seeking to meet demand
for Eastern Pacific LNG sources (perceived as
adding to supply diversity, and absence of
security risks)
• Targeting major growth in Asia Pacific LNG demand
[Slide 9 includes a graph titled: Western Canadian
wholesale Natural Gas Price History/Forecast for the
years 2015 - 2035.]
"What is particularly attractive about LNG Canada? is
the differential between AECO and Henry Hub, not to
mention the proximity to Asia,.."
Shell CEO Wael Sawan June 2025
MR. FULFORD highlighted that LNG Canada had been operating for
over a year, with expansion underway, and mentioned that one
stakeholder, PETRONAS, had partially sold its equity stake to
other investors. This illustrated that ownership structures
could evolve over time, suggesting that similar flexibility
might apply to potential state participation in an Alaska LNG
project.
3:39:33 PM
SENATOR CLAMAN asked for clarification on the location of the
LNG project in Canada and the length of its pipeline. He noted
that while the projects appeared comparable to Alaska's, having
more specific geographic context would help better understand
the similarities.
3:39:55 PM
MR. FULFORD explained that the LNG Canada project was in
Kitimat, along the central coast of British Columbia. He stated
that the pipeline, constructed by TransCanada for the project,
was just over 400 miles long, shorter than the proposed Alaska
pipeline, but built across more challenging terrain.
3:40:44 PM
MR. FULFORD moved to and narrated slide 10. He highlighted the
Ksi Lisims LNG project due to its similarities to Alaska's
project stage and its geographic proximity to the Alaska border,
near Ketchikan. He said the project had secured preliminary
offtake agreements with Shell and TotalEnergies and was
primarily led by First Nations, with participation from a
Houston-based infrastructure company and regional gas producers.
With a planned capacity of about 12 million tons per annum, it
was comparable in scale to the proposed Alaska project. He
emphasized that global LNG demand, currently around 400 million
tons annually, was expected to grow significantlypotentially
reaching 700800 million tonslargely driven by Asian markets.
This made Pacific Coast projects particularly advantageous due
to shorter and more economical shipping routes to Asia.
MR. FULFORD emphasized that global LNG demand, currently around
400 million tons annually, was expected to grow significantly,
potentially reaching 700800 million tons, largely driven by
Asian markets. This made Pacific Coast projects particularly
advantageous due to shorter and more economical shipping routes
to Asia:
[Original punctuation provided.]
LNG Summary
Canadian Pacific Coast
Ksi Lisims LNG 12 MTPA
• Fiscal support but no formal stability mechanism
• Offtake:
• Shell 2 MTPA
• TotalEnergies 2 MTPA + equity
LNG Canada 14 MTPA
• Fiscal support and stability mechanism
• Up to 28 MTPA with Phase 2
• Train 1&2 now operational
3:43:33 PM
MR. FULFORD continued to narrate slide 10, noting that LNG
Canada had recently brought both of its production trains
online, and was actively exporting LNG, primarily to Asia but
with flexibility to redirect shipments to other markets such as
Europe. Additionally, he said smaller projects like Cedar LNG
and Woodfibre LNG were progressing further south in British
Columbia, though with fewer development parallels to Alaska LNG.
Cedar LNG 3.3 MTPA
• Fiscal support but no formal stability mechanism
• Petronas 1MTPA tolling capacity
• ExxonMobil/ARC 1.5 MTPA
Woodfibre LNG 2.1 MTPA
• Under Construction, expected completion in 2028
Over 30 MTPA under development or operating plus
additional 14 MTPA from LNG Canada Phase II
[Slide 10 includes map: Approximate Locations of
Upcoming and Proposed LNG Facilities - British
Columbia]
3:45:16 PM
CHAIR GIESSEL asked for clarification of the phrase, Formal
Stability Mechanism.
3:45:28 PM
MR. FULFORD explained that fiscal stability, a dependable
government tax framework for investors and lenders over the long
term, was a critical consideration for large LNG projects. He
said the LNG Canada project had undergone extensive discussions
with the Canadian government over several years leading up to
its final investment decision (FID). The government granted the
project "nation building" status, broadly assuring that the
fiscal framework would remain unchanged. While this did not
constitute a formal fiscal stability agreement, the project's
developers, primarily Shell, and its major lenders regarded it
as sufficient to reduce investment risk. He said other LNG
projects in the region had not yet established similar
frameworks.
3:47:31 PM
SENATOR CLAMAN observed that the discussion of fiscal stability
for LNG Canada referred specifically to the government tax
framework, rather than internal company analyses or financial
assessments of project viability.
3:47:54 PM
MR. FULFORD concurred. He said fiscal stability referred to the
tax framework governing both upstream and midstream aspects of
the project. He noted that investors remained fully exposed to
market risks, such as LNG and oil price fluctuations, risks they
are comfortable with, as opposed to the risk of changes in
government tax.
3:48:35 PM
SENATOR CLAMAN asked whether, from the investor perspective
rather than the tax framework, LNG Canada provided more
disclosure to local or provincial governments compared to what
was being shared [with the Alaska legislature] by Glenfarne.
3:48:57 PM
MR. FULFORD explained that the level of disclosure by LNG Canada
was not generally public. However, over the five-year evolution
of the project's fiscal framework, the provincial government had
significantly adjusted the tax regime, reducing front-loaded
taxes in favor of long-term revenue. Given this extended
dialogue, he suggested it was likely that substantial modeling
and discussion regarding project economics had taken place.
3:50:21 PM
MR. FULFORD moved to slide 11. He explained that the British
Columbia provincial government initially assumed LNG projects
could sustain significant additional taxes, based on the spread
between low gas prices in the Montney region and higher LNG
prices in markets like Japan. As a result, new LNG-specific
taxes and framework agreements were introduced but were
ultimately repealed after further evaluation:
[Original punctuation provided.]
Lessons from LNG Canada
• Discussions commenced in 2013 but final fiscal
package agreed March 2018 with FID October 2018
• Key features of enabling legislation:
• Natural gas tax credit for LNG development in
British Columbia.
• Repeal of the Liquefied Natural Gas Income Tax
Act
• Discounted electricity prices
• BC carbon tax exemptions
• A natural gas credit against corporate income
tax
• Deferral of provincial sales tax on
construction
• Federal tax breaks / accelerated depreciation
• Fiscal stability
• Estimated benefit for the project: Federal C$1.8bn
Provincial C$2.16bn*
*https://canadian-accountant.com/content/business/lng-
risks-public-purse-report
MR. FULFORD said the fiscal regime evolved substantially,
shifting away from high upfront taxation toward long-term
revenue collection. This included reducing corporate income tax
rates through credits, deferring provincial sales tax,
effectively creating a long-term, interest-free payment
structure, and implementing accelerated depreciation at the
federal level to ease early financial burdens. He noted that
property taxes in Canada were also significantly lower than in
Alaska, with gradual increases over time.
3:54:31 PM
MR. FULFORD noted that British Columbia maintained a carbon tax,
but it was capped at a relatively low level for the project,
limiting its impact. He concluded that these adjustments
illustrated how fiscal terms were modified to improve project
viability and suggested that a more detailed analysis could
provide further insights for Alaska.
3:55:11 PM
SENATOR WIELECHOWSKI noted that potential property tax changes
might be requested, though no formal legislation had yet been
presented. He anticipated that the issue of sales tax changes
would require significant attention from the legislature if it
arose. He asked several questions about the Canada LNG
experience:
• whether the gas pipeline and LNG export facility were
developed by an independent entity like the Alaska LNG
proposal
• who initiated the request for [Canada LNG] tax concessions
• what specific constraints drove those requests and whether
the requests were related to gas production, pipeline
construction, or the LNG facility itself
3:56:00 PM
MR. FULFORD explained that in 2013, PETRONAS pursued a separate
LNG project in Canada, while LNG Canada was led primarily by
Shell and Mitsubishi. Both groups communicated to provincial and
federal governments that the existing tax regime, particularly
additional LNG-specific taxes, made the projects economically
unviable. This led to a prolonged impasse, during which
developers insisted that tax arrangements for LNG export
entities needed substantial revision before investment could
proceed. Around 20172018, increased federal support for LNG
exports to the Pacific and a more favorable stance from the
provincial government resulted in tax concessions. While there
were minor adjustments over time, the upstream royalty framework
in British Columbia (BC) remained largely unchanged; instead,
reforms focused primarily on corporate income tax and carbon
tax. He said, ultimately, PETRONAS, which had already secured
upstream gas assets in Canada, abandoned its standalone project
and joined LNG Canada by contributing its equity alongside
Shell, Mitsubishi, and Korea Gas Corporation (KOGAS).
3:58:32 PM
SENATOR MYERS arrived.
3:58:50 PM
SENATOR DUNBAR asked about the total cost of LNG Canada and how
it was financed. He noted that LNG Canada spanned roughly 400
miles and the Alaska LNG pipeline would be significantly longer.
He inquired whether LNG Canada was primarily funded by private
investors, led by Shell, or whether governments also contributed
direct capital in addition to tax incentives.
3:59:24 PM
MR. FULFORD said the pipeline was built primarily by
TransCanada, which entered an arm's-length contract with the LNG
Canada sponsors, led by Shell, to build the pipeline and recover
costs through tariffs. He said there was no meaningful
government involvement in LNG Canada, nor were there specific
guarantees or concessions from provincial or federal
governments. Cost escalation risk, significant in the case of
the Coastal GasLink pipeline, where construction costs nearly
doubled, was absorbed by TransCanada and Shell, with the
handling of overruns having been pre-negotiated.
4:01:05 PM
SENATOR DUNBAR asked what the cost of the project was after
doubling.
4:01:10 PM
MR. FULFORD agreed that it was $40-50 billion. He said it could
have been $11 billion to $22 [billion] Canadian dollars.
4:01:30 PM
SENATOR DUNBAR asked whether the $22 billion was just for the
pipeline and did not include an LNG facility.
4:01:40 PM
MR. FULFORD affirmed that it was just the cost of the pipeline.
The cost for an LNG facility would have been more.
4:02:15 PM
SENATOR KAWASAKI referred to a Wood Mackenzie presentation,
which indicated that typical property tax rates in Louisiana and
Texas ranged from 0% to 0.5%, while Alaska's LNG project was
estimated at about 0.2% (20 mills). He also noted that property
tax rates in Alberta and Saskatchewan appeared higher, ranging
from roughly 0.5% to 2.5% (50 to 250 mills). He questioned
whether those comparisons were inaccurate or whether specific
changes to the tax system had been implemented for the LNG
Canada project.
4:03:05 PM
MR. FULFORD asked that the question be repeated.
4:03:11 PM
SENATOR KAWASAKI explained that he had been reviewing tax rate
data because he expected a future proposal to reduce [property
tax] rates to zero. In doing so, he observed that oil property
tax rates in Saskatchewan and Alberta appeared to range from
about 0.5% to 2.5% (50 to 250 mills). He questioned whether his
understanding or source of that information was incorrect.
4:03:44 PM
MR. FULFORD said he was not familiar with how property tax
systems function in [Alberta and Saskatchewan] or how mill rates
are applied. He noted that in British Columbia, property tax
revenues in his example went solely to the City of Kitimat,
which helped explain the lower rates.
MR. FULFORD clarified, in follow-up to Senator Dunbar's question
that the estimated cost of the Coastal GasLink pipeline had
risen from about $6.6 billion CAD initially to approximately
$14.4 billion CAD.
4:04:46 PM
SENATOR KAWASAKI clarified that the current petroleum property
tax rate in [Alaska] was 20 mills, or 0.2%, and explained that
he had been comparing that rate to what he understood to be oil
property tax rates in Saskatchewan and Alberta, which he
believed ranged from about 0.5% to 2.5%.
4:05:13 PM
MR. FULFORD said he was not aware of property tax arrangements
in those provinces. He offered to follow up on that.
4:05:34 PM
CHAIR GIESSEL agreed that follow-up would be helpful.
4:05:40 PM
SENATOR MYERS sought clarification on whether, at the time of
the final investment decision (FID) for LNG Canada, the initial
planned capacity of roughly 1415 million tons per year was
correct, and he asked how much of that capacity was secured
under take-or-pay binding contracts at that time.
4:06:08 PM
MR. FULFORD explained that all of LNG Canada's initial capacity
was effectively covered, as the project operated under an equity
marketing arrangement. Each equity partner, Shell, Mitsubishi,
Korea Gas Corporation (KOGAS), and PETRONAS, or their affiliated
LNG trading entities committed to taking 100% of their
respective shares. As a result, the project's credit risk was
effectively transferred to the parent companies' balance sheets,
which in turn enabled lenders to offer relatively low-cost
financing due to the strong creditworthiness of those entities.
4:07:28 PM
MR. FULFORD stated that LNG Canada was perhaps the example to
consider.
4:07:48 PM
MR. FULFORD moved to slide 14:
[Original punctuation provided.]
SB 138 Concept vs. Current Structure
• The MOU governing the original AK LNG project was
based on an "integrated model", from gas
production through to LNG disposition.
• The current structure is understood to be closer
to a "merchant model"
• Equity participation can differ along the
LNG value chain
• Implications for Tax as Gas (TAG) and Royalty in
Kind (RIK)
• State equity participation no longer directly
linked with its entitlement to gas
[Slide 14 includes diagrams illustrating an
"Integrated Structure" vs a "Merchant Structure.]
MR. FULFORD compared the earlier Senate Bill 138 (2014) project
concept with the current structure, emphasizing a fundamental
shift in design. He explained that the Senate Bill 138 concept
had envisioned a fully integrated project in which all parties,
including the state, were aligned across the entire supply chain
from production through LNG export. Under that model, the
state's participation, via Royalty in Kind (RIK) and Taxes as
Gas (TAG), could have resulted in roughly a 25% equity stake,
with proportional capital contributions and no upstream transfer
price; the gas would only have been valued at the point of LNG
export.
4:08:23 PM
SENATOR RAUSCHER joined the meeting.
MR. FULFORD said in contrast [to the Senate Bill 138 concept],
the current concept was described as a merchant structure, where
gas is sold into the project by various stakeholders,
introducing an upstream transfer price. He noted that this price
had been estimated at around $1 to $1.25 for illustration
purposes in the Wood Mackenzie analysis. This structural change
had important implications, including the generation of tax and
royalty at the upstream point and a shift in how government
revenue depends on where profits are allocated within the
project. He concluded that, unlike the earlier model, the
allocation of profitability between upstream and downstream
components would now materially affect the state's overall tax
take and would require ongoing consideration.
4:12:49 PM
SENATOR WIELECHOWSKI stated that slide 14 and Mr. Fulford's
testimony highlighted a key issue for the legislature: whether
the [Alaska LNG] project had evolved into something materially
different from what was originally contemplated under Senate
Bill 138 in 2014, and whether that change required updated
legislative direction. He asked what Mr. Fulford would recommend
if such changes were warranted.
4:13:22 PM
MR. FULFORD acknowledged that the question was complex and would
require further discussion but agreed that there was a material
difference between the structure envisioned under Senate Bill
138 and the current project concepts. He noted that changes in
how profits are allocated between upstream and midstream
components would affect government revenue and concluded that
this likely warranted a fresh review of the state's taxation
approach, with potential updates to how the project is
structured compared to a decade ago.
4:14:38 PM
MR. FULFORD moved to slide 13:
[Original punctuation provided.]
Formalising Governance Structure for LNG / Gasline
• Project appears to be moving to a more active phase
of development.
• A formalization of project structure and governance
will be needed
• Heads of Agreement and other documentation from 2014
may provide guidance:
• Key questions include:
• Who are parties to any project framework
agreement?
• Is Enabling Legislation envisaged?
• Other enabling agreements?
• How is gas to Alaskans priced and other key
terms
• Jobs for Alaskans/Alaskan Hire Agreement
• State revenues and tax framework
• Drivers for other industries based on "low
cost natural gas"
• State participation
• Supply points for Interior
MR. FULFORD stated that, given the structural changes discussed,
it was useful to reconsider the key questions and comparisons
arising from Senate Bill 138. He noted that Senat Bill 138 had
envisioned a Heads of Agreement (HOA) followed by more detailed
arrangements among defined stakeholders, but that it was now
unclear which parties should be included in any updated
framework, including whether it should involve only the LNG
development company or also upstream producers. He added that
these structural changes could significantly alter the required
enabling legislation and warrant renewed examination of
production tax and royalty impacts, particularly in relation to
how state revenue would be generated.
MR. FULFORD explained that earlier agreements included
provisions such as in-state gas pricing, Alaskan hire and local
job commitments, and potential gas supply arrangements for
Alaskans, including Interior Alaska. While some recent
commitments addressed local employment, they were less
comprehensive than those in the original Heads of Agreement
(HOA). He concluded that these elements, along with questions of
state participation and domestic gas supply, would need to be
revisited and potentially reintroduced under the new framework,
which would shape forthcoming contractual and policy decisions
affecting both the state and private investors.
4:18:30 PM
CHAIR GIESSEL commented that recent statements from Glenfarne
raised questions about how agreements with buyers and
contractors could have been reached without clarity on what the
State of Alaska would require. She noted that public
announcements did not address key issues such as a project labor
agreement or the supply of gas to Fairbanks, including how a
potential pipeline from a takeoff point to the city would be
financed. She concluded that these unresolved issues remained
important and relevant concerns for the public.
4:20:20 PM
MR. FULFORD explained that the WoodMackenzie report, page 13,
included a detailed economic analysis of Phase I gas line
tariffs, incorporating several assumptions, particularly related
to taxation that would ultimately require state input. One key
assumption reduced the property tax rate from 20 mills to 2
mills, representing a 90% decrease applied throughout the
projections. The speaker noted that, although this assumption
had been referenced by Glenfarne and others, there was no known
analysis or indication from state or municipal governments
supporting its validity. They emphasized that it appeared to be
a hypothetical input for modeling purposes rather than an
established policy expectation. He said the issue of taxation
would likely need further discussion, referencing the potential
payment in lieu of taxes (PILT) agreement under Senate Bill 138
which had been explored but never formally enacted or proposed.
4:22:50 PM
MR. FULFORD noted that the Wood MacKenzie analysis also examined
the pipeline's depreciation period, which extended to 2071,
creating sensitivities around potential early economic
termination and its impacts. He emphasized that the most
influential assumptions affecting pipeline tariffs were property
tax levels, cost sensitivities, and related factors. Another key
uncertainty involved the potential availability of a federal
loan guarantee, which could significantly affect project
economics but had not been confirmed.
4:24:09 PM
MR. FULFORD concluded that the Wood Mackenzie analysis was
robust within the context of its stated assumptions, while
noting there was no known alignment between those assumptions
and any formal agreements or indications from the state
government.
4:25:19 PM
ANDREW DUNCAN, Director, Facilities and Costing Engineering,
GaffneyCline Energy Advisory, Singapore, moved to and narrated
slide 16:
[Original punctuation provided.]
FID Pre-requisites
Significant announcements were made by Glenfarne on
January 22nd regarding the Phase I Gasline
development.
As these announcements are assessed in the coming
days, further insights may become available.
The following slides were prepared prior to the
announcements, but are still considered useful
background and understanding.
4:26:41 PM
MR. DUNCAN moved to and narrated slide 17:
[Original punctuation provided.]
FID Pre-requisites
To take FID, key aspects of the AKLNG project must be
considered:
• Phase 1 will comprise the pipeline transporting gas
to the state domestic market
• Subsurface (gas availability) risk is low
• Facilities capital costs are large and a dominant
part (84%) of the overall cost of supply
The FID decision package must provide coverage of all
project work streams to demonstrate readiness to
proceed.
4:28:23 PM
MR. DUNCAN moved to and narrated slide 18:
[Original punctuation provided.]
Project Management Framework Pre-FID
[Slide 18 includes a graphic illustration of the
Decision Gates of Pre-FID Project Management]
Large projects are typically managed within a "Stage-
Gate" process where project phases are controlled at
"Decision Gates" (DG). FID is normally taken at DG4.
The DG support package will address:
• Project technical scope (project specification, key
design documents)
• Cost and schedule- base, risk analysis,
contingencies, and allowances
• Project execution plan- staffing, contracting,
procurement, logistics, etc
• Legal, permits, and regulatory framework
• Commercial framework, economics, and business case
• Financing- phasing, coverage, risk management,
assurance, etc.
• Stakeholder management
4:32:01 PM
SENATOR WIELECHOWSKI referenced a news report that Alaska LNG
expected to begin pipeline construction as early as December and
questioned whether that timeline was realistic. He noted that
final investment decisions (FID) were said to be imminent and
asked for an assessment of the likelihood of that timeline.
4:32:25 PM
MR. DUNCAN observed that the Glenfarne announcement contained
significant conditionality, including provisional commitments
and conditional awards, which he noted was typical in early-
stage large projects. He explained that developers often build
momentum through relatively low-cost preparatory activities,
such as site works, securing long-lead materials like steel, and
establishing early contractual relationships with construction
firms, while managing risk through mechanisms like cancellation
clauses.
MR. DUNCAN assessed these actions as prudent steps to support
scheduling and resource mobilization while limiting exposure if
the project did not proceed. He cautioned that determining
whether pipeline construction could begin by December would
require deeper analysis. He emphasized that, more important than
meeting a specific start date, was ensuring a clear, structured
pathway to successful project completion before making major
financial commitments.
4:37:41 PM
CHAIR GIESSEL compared the outlined project management framework
to that of industrial megaprojects, noting the presence of
decision gates. She asked which decision gate Glenfarne was
currently at within that process.
4:38:10 PM
MR. DUNCAN said he thought Glenfarne was between Decision Gate
Two and Decision Gate 3 with a forward plan through to the
development phase.
4:38:54 PM
CHAIR GIESSEL asked whether, based on prior industrial
megaproject presentations, the final investment decision
typically occurred at Decision Gate Four, when Class 3 cost
estimates had been sufficiently developed. She sought
confirmation of that understanding.
4:39:23 PM
MR. DUNCAN concurred.
4:39:28 PM
SENATOR KAWASAKI said there had been mentions of a notice to
proceed. He asked at which stage gate such a notice would be
issued.
4:39:47 PM
MR. DUNCAN explained that a notice to proceed applies to
specific project activities and can be issued early to protect
the schedule, particularly for long-lead or preparatory work, if
those activities contribute to the final project. He noted that,
in some cases, such notices are issued even before the full
project scope is defined, when developers are confident the
project will move forward. In this instance, he highlighted that
substantial project definition, permitting, and regulatory work
had already been completed and made publicly available. He also
observed that Glenfarne had continued advancing the project by
securing construction resources and engaging gas suppliers,
reflecting an underlying assumption that the project would
proceed. He stated that these actions appeared appropriate and
aimed at building execution momentum, though he cautioned that a
detailed scope and readiness review would be necessary to assess
the feasibility of initiating full-scale construction in
December.
4:44:21 PM
MR. DUNCAN moved to and narrated slide 19:
[Original punctuation provided.]
Cost Estimation Framework AACE 97R-18
The American Association of Cost Engineers (AACE)
provides Recommended Practices covering a range of
industrial and infrastructure projects
AACE 97R-18 addresses Pipeline Transportation and
Infrastructure Projects
The document covers:
• Cost Estimate Classification
• Characterization of estimate class (Class 1 to 5)
• Estimate input checklist and maturity class
• Supporting references and appendices
AACE International Recommended Practice 97R-18
COST ESTIMATE CLASSIFICATION SYSTEM - AS APPLIED IN
ENGINEERING, PROCUREMENT, AND CONSTRUCTION FOR THE
PIPELINE TRANSPORTATION INFRASTRUCTURE INDUSTRIES
4:45:18 PM
MR. DUNCAN moved to slide 20, which consists of a table titled:
AACE 97R-18 Cost Estimate Classes. The table illustrates the
characteristics of each of five classes. Slide 20 also includes
a graph titled "Illustration of the Variability in Accuracy for
Pipeline Transportation Infrastructure Industry Estimates"
MR. DUNCAN described the range of cost estimate classes, from
Class 5, representing rough, screening-level estimates based on
general rules of thumb, to more advanced classes (4 and 3)
supported by increasing levels of detailed engineering. He noted
that final investment decisions (FID) are typically based on
Class 3 estimates. He said the question of the [Alaska LNG]
project's current position within this framework would be
addressed in the next slide. He explained that as estimates
mature, uncertainty in cost and schedule decreases, along with
the level of contingency required to manage project risks
through completion.
4:47:29 PM
MR. DUNCAN moved to slide 21, consisting primarily of a table
with detailed analysis of the project according to the cost
estimate and maturity classes and including the following
points:
[Original punctuation provided.]
AACE 97R-18 Input Checklist (1/2)
AACE 97R-18 addresses Pipeline Transportation and
Infrastructure Projects: Estimate input checklist and
maturity class
Reviewing data from the Alaska LNG website
Note that the Glenfarne website provides limited
additional information
Key question is whether the Alaska LNG project
description can be confirmed as the FID basis?
MR. DUNCAN explained that, using publicly available information,
primarily from the Alaska LNG website, he had assessed the
project's status against a standard project input checklist. He
noted that substantial work had been completed on pipeline
routing, right-of-way, and permitting, and considered this work
thorough and valuable, assuming the project proceeds within its
current scope. Based on this preliminary review, he estimated
that the project aligned with a robust Class 5 to early Class 4
cost estimate. He observed that the referenced framework focused
mainly on technical project definition, with less emphasis on
commercial and financing considerations.
4:50:09 PM
MR. DUNCAN moved to slide 22, continuing the table analysis from
slide 21 and further comments:
[Original punctuation provided.]
AACE 97R-18 Input Checklist (2/2)
Based on a screening of the information available in
public domain (i.e. not a comprehensive review of
current project progress documentation), I would
assess the Alaska Gasline Development project as a
robust AACE Class 5 estimate
This does not address the LNG project, compressor
stations, or gas supply and treatment scope
Pegasus-Global "Open Questions" and "Recommendations"
are endorsed
Project commercial and financing basis is not covered
in the AACE structure, but forms a critical aspect of
any FID
4:51:23 PM
SENATOR MYERS expressed concern that the projects reported
progress did not align with expectations for reaching a final
investment decision by the stated timeline, March 2026. He noted
that, if such a decision were imminent, the project would be
closer to a Class 3 estimate, whereas the presentation suggested
it remained largely at Class 5 with some elements in Class 4. He
questioned whether the discrepancy stemmed from inaccuracy in
the analysis presented assessment or from Glenfarne overstating
the project's level of advancement.
4:52:30 PM
MR. DUNCAN acknowledged that his assessment was based primarily
on publicly available information from the Alaska LNG website,
much of which reflected work completed before Glenfarne assumed
control of the project. He expressed confidence that Glenfarne
had since advanced and further developed that work, noting that
a review had been conducted with Worley, a reputable engineering
and project management firm, although its results had not been
publicly disclosed. He emphasized that his assessment was
neither comprehensive nor current, but rather a backward-looking
approximation based on limited public information.
4:54:00 PM
SENATOR WIELECHOWSKI referred to the tables on slide 22. He
asked for clarification of the percentages for the estimate
classes.
4:54:29 PM
MR. DUNCAN explained that zero to 15% referred to the percentage
of engineering definition as opposed to the percentage of
project completion.
4:54:52 PM
SENATOR WIELECHOWSKI asked for further clarification.
4:55:04 PM
MR. DUNCAN explained that a full project typically includes
three main phases: an initial engineering phase to define the
scope, a procurement phase to acquire materials, and a
construction phase to build the project. He noted that the
engineering phase generally represents about 5% to 10% of total
project cost, depending on the level of completion. Although
described sequentially, he emphasized that these phases overlap
in practice, with engineering continuing alongside early
procurement and construction activities. He added that effective
project management ensures these overlapping phases remain
aligned with the final scope and that early-phase deliverables
are completed in time to support subsequent work.
4:56:40 PM
SENATOR WIELECHOWSKI asked for definitions of abbreviations and
acronyms used in the presentation.
MR. DUNCAN explained that P indicated preliminary, NR indicated
not required, P-C or C indicated that the deliverable was
completed, and S indicated started or that the work had
commenced.
4:57:36 PM
CHAIR GIESSEL noted that slide 20 provided some detailed
explanation for the coding in the presentation. She suggested
that assessing the progress of the Alaska LNG project was more
complicated than press releases communicated.
4:58:20 PM
SENATOR MYERS questioned the project's current stage relative to
an anticipated final investment decision (FID) and expressed
concern that, if the project were less advanced than believed
but still proceeded to FID, it could face significant risks. He
identified major cost overruns as the primary concern and asked
what additional risks should also be considered.
4:58:56 PM
MR. DUNCAN explained that, alongside cost overruns, schedule
delays were a closely related risk, particularly when project
definition was incomplete. He noted additional risks tied to
expiring or time-limited elements, such as permits that might
require renewal and conditional agreements for materials or
construction services that could lapse if timelines slipped.
These factors, he emphasized, ultimately compounded cost and
schedule pressures. He highlighted project credibility as a key
concern, explaining that if a project stalled, significant
effort would be required to rebuild confidence and restart
execution.
5:01:36 PM
SENATOR DUNBAR asked for clarification on the meaning of Final
Investment Decision (FID) in the context of upcoming slides. He
questioned whether FID referred to a specific moment, such as a
formal investment decision and public announcement identifying
investors, or to a stage in which a proposal and support package
are presented to potential investors. He also inquired whether
FID should be understood as a process rather than a single event
and asked how long that process typically takes.
5:02:30 PM
MR. DUNCAN explained that the nature of a Final Investment
Decision (FID) varied significantly depending on a project
sponsor's management approach. He noted that, in some cases, FID
was a clearly defined moment marked by a formal, detailed
document such as a letter to joint venture partners indicating a
definitive commitment to the project. In other cases,
5:04:34 PM
MR. DUNCAN moved to slide 23 and continued to describe some of
the ways projects arrive at a final investment decision. He
explained that, particularly with fast-tracked projects, FID
functioned as a gradual process involving a series of
incremental commitments over time, with full project scope and
implementation potentially finalized years after initial
activities began. He added that such extended processes could be
influenced by external factors like geopolitical or commercial
changes and required careful project management to ensure early
decisions aligned with long-term objectives. He concluded that
FID could be either a single event or an extended process and
emphasized the importance of clearly understanding the specific
process and current project stage:
[Original punctuation provided.]
Factors Affecting Pre-FID Schedule
The time required for the "Select" and "Develop" (or
Define) phases can vary widely, depending on:
• Project economic attractiveness- highly profitable
projects can take FID quickly, marginal projects
often require better definition and may have to
recycle back to through concept selection
• Project non-technical aspects (regulatory,
stakeholder, financing) are affected by external
influences
• Project scale, complexity, and innovation
Upstream mega-project Pre-FID phase can vary from less
than 4 years to over 50 years
5:08:07 PM
CHAIR GIESSEL reflected on slide 18, noting that the pre-FID
framework highlighted stakeholder management, including
engagement with the State of Alaska. She observed that the
project appeared to be advancing without securing such
stakeholder alignment, which could have implications for
regulatory frameworks, legal matters, and cost factors such as
taxes. She concluded that, while the project seemed to be
proceeding as a process, doing so without firm stakeholder
engagement seemed risky.
5:09:09 PM
MR. DUNCAN moved to slide 24. He said that, alongside
stakeholder management and transparency, uncertainty management
was a critical component of project execution. He explained that
at any stage of a project, cost and schedule risk analyses could
be conducted to quantify uncertainties and assess their
potential impact on outcomes. These analyses typically produced
probability distributions for cost and schedule, which project
sponsors and developers used to determine appropriate financial
provisions. A technical cost estimate provided a base cost for
known elements, after which contingencies were appliedoften to
reach a 50/50 estimate, or higher levels of assurance when
required by lenders. He emphasized that such techniques were
standard within project management frameworks and were designed
to systematically address uncertainty:
[Original punctuation provided.]
Measures to assure FID
FID timing can be defended with:
• Robust FID decision support package subject to
readiness review(s
• Probabilistic cost and schedule risk analysis
• Project risk analysis and risk allocation in place
(e.g. loan guarantees, tariff and volume
commitments, EPC contract scope and terms tendered
and prices received, gas supply and marketing
agreements matured, financing structure in place,
etc.)
• Contingency (cost and time) allocated (Base to P50
or P90) consistent with risk analysis findings
• Transparency and involvement of key stakeholders
5:12:48 PM
SENATOR DUNBAR acknowledged that a final investment decision
(FID) could be both a singular decision and a broader process.
He then focused on the key issue of financing and questioned
whether, if FID were reached in March, there would be clear
disclosure of funding sources. He asked whether financial
commitments such as secured loans or private investments would
be identified at that stage.
5:13:49 PM
MR. DUNCAN said there would typically be clear guidance on the
sources or guarantees of funding. He explained that financing
arrangements were closely linked to the FID process,
particularly when projects relied on borrowed capital, whereas
projects funded from a proponent's own balance sheet allowed
greater flexibility. H emphasized that FID should clarify who
bears the risk of cost overruns and how risks are allocated,
noting that various risk management mechanisms are usually
defined at that stage.
5:16:12 PM
SENATOR KAWASAKI asked how a company could determine actual
project costs without clarity on the state's tax regime. He
asked whether such uncertainties would be incorporated into the
risk assessment considered during the final investment decision.
5:16:41 PM
MR. DUNCAN explained that project costs and viability depended
in part on fiscal stability, including tax arrangements within
the overall commercial structure. He noted that developers might
accept some level of fiscal risk, as seen in the Canada LNG
project with partial stability assurances. He emphasized that
the final decision depended on the developers' tolerance for
those risks.
5:18:32 PM
SENATOR CLAMAN said that much of what the developer was doing
with private lenders was confidential and not visible to the
legislature. He noted that, unlike federal loans or guarantees
and tax changes, which could be seen through public processes,
private financing seemed to present the same challenge of
limited transparency, where key details were not disclosed. He
asked if he was missing something.
5:19:40 PM
MR. DUNCAN explained that confidentiality and disclosure ranged
from full public disclosure to strictly company-confidential
information, with multiple levels in between. He noted that, in
loan agreements, certain project details could be shared with a
limited group under non-disclosure agreements, often through an
intermediary such as a law firm or consultancy that evaluates
the information and reports to interested parties. He added that
such mechanisms were commonly used to provide assurance to
lenders while protecting commercially sensitive information and
suggested that similar approacheslike those used to develop
Senate Bill 138 [in 2014] could allow information to be shared
with the legislature without compromising the project
proponents.
5:22:42 PM
CHAIR GIESSEL thanked the presenters.
5:23:12 PM
There being no further business to come before the committee,
Chair Giessel adjourned the Senate Resources Standing Committee
meeting at 5:23 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 1.23.26 SRES Presentation, GaffneyCline, LNG Key Issues and Recommendations.pdf |
SRES 1/26/2026 3:30:00 PM |
|
| 2024 WM AGDC Alaska LNG Phase 1 Final Legisture Summary.pdf |
SRES 1/26/2026 3:30:00 PM |