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.