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Vol. 22, No. 36 Week of September 03, 2017
Providing coverage of Alaska and northern Canada's oil and gas industry

A duty to sell the gas

Meyer says NS producers must book pipeline capacity or sell gas to the state

Alan Bailey

Petroleum News

The North Slope producers can sell gas for shipment through a planned gas export pipeline and associated liquefied natural gas plant, or, if not, the state will buy the gas from the producers, to sell the gas to customers that the state establishes, Keith Meyer, president of the Alaska Gasline Development Corp., told the Commonwealth North Energy Action Coalition on Aug. 25. Either way, the project will go ahead, but only on the basis of securing firm customers for the gas, Meyer said.

“This project will not be built until we have customers secured, so it’s not going to be built on spec,” Meyer said. “The state of Alaska is not going to build this. … This takes customers to provide the foundation for the financing, which gives us money for the construction.”

However, given that the North Slope gas belongs to the state, the state can insist that the gas is monetized, if the appropriate infrastructure is made available to deliver the gas to market, Meyer said. The state grants resource extraction rights to the producers, he said.

“They’ve got somewhat of a duty to produce the gas. What we’re building is the commercialization vehicle,” Meyer said. “So they can subscribe to capacity on the system … put it into their global portfolio.”

Alternatively the state will purchase the gas from them.

“There’s not a third doorway that says I want to hold off on Alaska’s supply while I go do these other projects,” Meyer said.

The state might also invest in anything up to 25 percent of the project development cost in the form of equity in the project, he said.

Viable project

The plan is to build a gas treatment plant on the North Slope, a 42-inch gas pipeline from the Slope to Nikiski on Cook Inlet, and a three-train LNG plant at Nikiski that would offload LNG onto tankers for export. Meyer expressed confidence that the around $40 billion project is viable. AGDC anticipates operating the system on a tolling model, charging customers for the shipment of gas delivered on the North Slope.

An open season, inviting solicitation for use of the system, ended on Aug. 31. However, it was clear from Meyer’s presentation that, if there are insufficient bids to account for system capacity, the state will itself market the gas.

For success, the project needs to clear three hurdles: the global LNG market, the market for financing the project and the achievement of an adequate netback for the state of Alaska, Meyer said. And this will require alignment between all of the stakeholders, including the state and the producers, on AGDC’s mission of maximizing the value of the upstream resource for the state of Alaska, he said.

Clearing the market

In terms of clearing the hurdle of the global LNG market, Meyer said that the project’s target market is Asian countries, in particular Japan, China and South Korea. Although these markets currently enjoy a surplus LNG supply, that supply will bleed off in the early 2020s while gas demand continues to grow. Several big 20-year supply contracts end in 2026.

“So everybody in the industry, all of the sellers, are all focused on this dip,” Meyer said, adding that the about 1 trillion cubic feet of gas passing though the North Slope gas line each year would fit comfortably within the anticipated gas market. Meyer also expressed confidence that long-term LNG supply contracts, rather than spot market sales, would be prevalent in that future market, given the impossibility of building new LNG infrastructure on the basis of a spot market.

Australia is currently a major global supplier of LNG. But, having already brought its better projects on line, the next generation of Australian projects will not be as competitive, Meyer said. Instead, Alaska’s main competition in the mid-2020s will come from the Lower 48, in particular Texas and Louisiana, he said. The U.S. administration is pushing for new U.S. exports to Asia, with those exports potentially coming from Alaska as well as from the Gulf states. And, although Qatar is very competitive in the LNG trade, buyers may be looking for more diverse sources of supply. Moreover, there is likely to be sufficient LNG demand to satisfy production from both Qatar and the United States, Meyer said.

Russian gas supplies are also competitive, but people already buying gas from that country may seek supply reliability elsewhere - for gas and power utilities, the main purchasers of LNG, supply reliability comes a close second to price in supply selection criteria, Meyer said.

Gulf Coast comparison

Looking at that future competition between Alaska and the Lower 48, the Gulf Coast enjoys the advantage of an existing gas pipeline infrastructure, while Alaska benefits from a much shorter sea route to Asia and no need to transit LNG carriers through the Panama Canal. Although it would cost more to build an LNG facility in Alaska than in the Gulf region, that cost differential would be almost exactly offset by the relative efficiency of LNG production in Alaska’s cool climate, Meyer said. And, while the Henry Hub pricing of gas in the Gulf region tends to be volatile, Alaska gas pricing should be relatively stable. The Energy Information Agency projects Henry Hub pricing to range from the current level of some $3.25 per thousand cubic feet up to perhaps $5.10, Meyer said. The stranded gas on the North Slope would be cheaper: At a North Slope gas price in the range $1 to $2 the Alaska LNG could compete effectively with a Gulf Coast project, he suggested.

Financing structure

AGDC sees the $40 billion financing for the Alaska project coming from 75 percent debt and 25 percent equity. The equity portion could come from the state, but could come from other sources as well. It is also possible that the system’s customers could purchase some share of the equity interest. By characterizing the project as an infrastructure project, essentially a pipeline system, the cost of the financing drops, Meyer said.

The idea is to have a 20-year debt term, a period of time corresponding to the length of a typical long-term LNG supply contract. During that period, revenue from the system would likely generate about $1 billion per year return for the equity investors. Once the debt is retired, that return would jump to $5 billion per year, a level of return that, for this type of pipeline system, could attract a $50 billion price tag, were the system to be sold to a third party, Meyer said.

“That to me is the Permanent Fund recharged,” he said.

Netback for the state

At an LNG price of $8 to $10 on the global LNG market, the project should generate exports with a total value of $8 billion to $10 billion per year. About a quarter of that money would be used for the North Slope gas supply, with 25 percent of that going to the state. About $1.5 billion would cover operations and maintenance costs, and the payment of property taxes to local communities. The operations and maintenance expenditure would remain in the state in the form of payments to contractors and workers. Service of debt on the system would be $3.5 billion and $1.1 billion would be returned to the equity owners, Meyer said.

This analysis demonstrates that, as well as being an attractive investment for the global finance community, the project would bring a reasonable netback to the state, Meyer said. He also commented that, because the project’s cost projections include some $16 billion for contingencies and owner costs, there is the possibility of bringing the cost down a bit.

There is also the possibility of using a phased implementation, perhaps starting with just two LNG trains and then expanding to three trains at a later time. However, the system would still be best built using the 42-inch pipeline: A 36-inch pipe could handle the lower capacity but would require more compressor stations than the larger pipe. In addition, the 42-inch line, unlike the 36-inch line, could easily accommodate the expansion to three trains, Meyer said.

Given the vast amount of natural gas thought to exist under the North Slope, there would also be the future possibility of expanding the system beyond the initial three-train design. Expansion of the pipeline capacity would involve building new pipeline segments downstream of the compressor stations, Meyer said.

Meyer also commented that, with a key intent of the planned gas pipeline being the supply of natural gas within Alaska, AGDC would act as the aggregator for in-state gas supplies, buying the gas and then selling it to in-state markets.

Marketing the project

Meanwhile, since taking over the running of the project, AGDC has been actively marketing the project, raising awareness of the project both for the Trump administration and for potential customers. This would be the largest U.S. energy export project, Meyer said. The administration has accepted the project for expedited regulatory treatment and financing under the terms of the Fixing America’s Surface Transportation Act, passed in 2015. Moves for international recognition have included alerting the Chinese president to the project during his visit to Alaska, and a meeting with the president of South Korea. AGDC has also signed a memorandum of understanding with Korea Gas Corp., Meyer said.

Given changes that are happening in the global LNG business and the upcoming window of opportunity in the mid-2020s, this is the right time to move forward with the Alaska LNG project, Meyer said. And AGDC needs to move on an aggressive path. To meet that new supply window, engineering and construction must take place in the period 2018 to 2023, with a final investment decision by around the fourth quarter of 2019. There is still some current engineering and permitting work to complete, and a FERC filing that needs to be made, Meyer said.



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