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Vol. 23, No.28 Week of July 15, 2018
Providing coverage of Alaska and northern Canada's oil and gas industry

Legislators get update

Quarterly report from AGDC, departments of Natural Resources, Revenue

Kristen Nelson

Petroleum News

The Alaska Legislature’s House and Senate Resources committees heard a quarterly update July 11 on the Alaska LNG project from the Alaska Gasline Development Corp. and the departments of Natural Resources and Revenue. The three have statutory responsibilities for the project to liquefy Alaska North Slope natural gas and ship it to Asian markets as liquefied natural gas.

AGDC was represented by Dave Cruz, chair of the AGDC board, Frank Richards, senior vice president, program management and Lieza Wilcox, vice president, commercial and economics.

Gov. Bill Walker, a long-time LNG project proponent, budgeted AGDC to accept unlimited third-party financing in the current budget, but legislators first restricted the amount the agency could accept and then eliminated the provision entirely.

While it was not discussed in the presentation, AGDC’s slide pack from the meeting includes 2018 and 2019 funding targets, and states: “Current fund balance will cause project delay due to inability to advance engineering and Lump Sum Turn Key (LSTK) negotiations,” with $53.4 million of funds remaining as of June. Those funds are what remains from earlier legislative appropriations for the project.

A “spend profile” in the packet showed a minimum spend of $53 million for 2018 and 2019, but a maximum of $797 million, were the funds available. The majority of the $797 million, $700 million, was listed as LSTK FEED (ramp-up).

Richards said the project is at the de-risk regulatory stage, with the next step lump sum turn key FEED, front-end engineering and design. The project completed pre-FEED in 2016. A final investment decision is projected for 2019, followed by project execution and first gas in 2024-25.

A slide on technical actions says AGDC has completed a construction execution plan and has a lump sum turn key contracting strategy.


Wilcox said AGDC is progressing negotiations on anchor capacity with the Joint Development Agreement parties - Sinopec, China Investment Corp. and Bank of China. It is also advancing definitive agreements and optimal sale and financing arrangements for the entire project.

In May AGDC announced that BP Alaska had agreed to key terms of a gas sales agreement, including price and volume, with plans to finalize a long-term gas sales agreement this year. Wilcox said AGDC is working diligently to reach gas supply agreements with the other North Slope producers and is nearing completion on a level similar to that achieved with BP. AGDC is also looking at detailed gas sales agreements or sections of them and negotiating them, Wilcox said.

She said AGDC doesn’t expect partial production but expects all the North Slope resource - including the state’s interest - to come into the project; to close the deal for financing, 100 percent of the gas would be required.

Wilcox discussed the modeling AGDC is doing with a full investment model planned for completion in 2018-19.

A tolling structure still underlies the modeling, she said, which has a commercial structure with gas purchase and LNG sale.

Model inputs include 75 percent debt, $32.6 billion, and 25 percent equity, $10.8 billion, for total capex of $43.4 billion.

In the past AGDC has talked about a $1 per million British thermal unit price to natural gas suppliers on the North Slope but is now pegging the wellhead gas purchase at between $1 and $2, Wilcox said, and the market price of LNG delivered to Asia, which AGDC has put at $8, is now shown as $8-$9 delivered to Asia with 80 cents shipping.

The schedule in the presentation showed that the project would ramp up one train at a time, with Train 1 operational in the fourth quarter of 2024; train 2 in the fourth quarter of 2025; and train 3 in the fourth quarter of 2026.

Department of Revenue

Deputy Commissioner of Revenue Mike Barnhill and Maria Tsu, Alaska Gasline Project financing specialist, presented for the Department of Revenue, with Tsu speaking to the department’s modeling efforts, focused on calculating equity returns and net revenues to the state depending on its level of equity ownership and how it is financed. An Alaska LNG project module models economics of project and fiscal impacts, Revenue’s slide pack said. Greengate LLC is advising on development of the model and will provide validation. The module is still under development.

A royalty and tax fiscal module uses the department’s existing fiscal model to analyze implications for oil and gas royalties and taxes, which is being adapted as data needs are assessed. DOR is coordinating with DNR on analysis of upstream impacts.

Barnhill called the modeling effort foundational to Revenue’s work on the project, and said the department looks to the role it has in statute, as set out in Senate Bill 138, which includes reports to the Legislature, including recommending legislation to permit co-owner participation in the project by municipalities, regional corporations and residents; consulting with DNR on gas sales agreements; and reengaging the Municipal Advisory Gas Project Review Board.

Revenue also discussed potential risks to the state s an investor and as a resource owner and taxing authority, as well as mitigating measures.

Prior to a final investment decision, the risk level is highest, and Tsu said return is proportional to risk and the investor should be compensated for risk in a greenfield project. As key milestones are reached, she said, the project is de-risked and the level of return should then be lower than at very early stages of the project.

Department of Natural Resources

Commissioner Andy Mack, Deputy Commissioner Mark Wiggin and senior project advisor Steve Wright presented for the Department of Natural Resources.

Mack said the current project represented a paradigm shift to debt for capacity, with 75 percent of project cost borne by the debtor, not the state.

DNR is working royalty in kind vs. royalty in value issues, including eliminating switching between RIK and RIV, Wiggin said. If RIK is selected - with the state taking royalties (and probably also taxes) in gas molecules - DNR would develop and execute a gas sales agreement with AGDC. If RIV is selected, DNR would need to address the valuation process used to calculate royalty gas value. Right now, he said, the valuation method is the higher-of methodology.

Wright said DNR is looking at ways to mitigate risk. When the Joint Development Agreement team signed the agreement it kicked off a new phase for DNR, he said, with potential buyers identified.

None of the presenters had time to finish, but some issues were addressed in slides - such as a statement by DNR that AGDC had the primary responsibility for mitigating negative netback risk by ensuring that sales/purchase agreements with LNG and in-state purchasers are coordinated with gas sales agreements with the gas resource owners.

The department said it can control the amount of risk to the state “by having a minimum price provision in its gas supply agreement with AGDC or by taking its royalty in-value.”

DNR also identified AGDC’s plan for lump sum turn key contracts for major project components as addressing cost overrun risk.

The department said it “appreciates the criticality of project expandability as a means of promoting future gas exploration and development,” and noted that AGDC has said throughput could be increased by adding trains to the gas treatment plant and the LNG plant, and adding compression stations to the pipeline. With expanded compression, DNR said, the pipeline is sized for maximum gas volumes of 4.3 billion cubic feet per day, some 27 million tons per annum, as opposed to the planned project at 20 million tons per annum.

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