One thing is clear: The state’s new point man on all things gasline has a new perspective on the Alaska LNG Project.
Self-proclaimed “gas guy,” and, as of June 15, Alaska Gasline Development Corp. President and CEO, Keith Meyer views one of the largest and complex projects the country has ever seen more simply, as the “logistics infrastructure of moving gas from the supply point to a market point,” he said in an June 21 interview with the Journal.
“When I look at this project, I look at it as an infrastructure project, not as an extension of a producing unit and I think that’s going to be a significant shift,” Meyer said.
With a low-end cost estimate of $45 billion and an 800-mile long footprint from the North Slope to the Kenai Peninsula, the immensity of the Alaska LNG Project certainly isn’t lost on Meyer.
A 35-year veteran of the energy industry, he oversaw the development of the Sabine Pass LNG terminal on the Texas-Louisiana line as president of Cheniere LNG. Sabine Pass was once the largest LNG import terminal in the country and has become an export facility after the shale gas revolution.
Former AGDC President Dan Fauske, who led the corporation since its inception, abruptly resigned last November at the request of Gov. Bill Walker, who thanked Fauske for his service at the time, but said he wanted someone with more LNG industry experience to lead AGDC as the project developed further.
Fauske’s background is in finance; he was also the longtime CEO of the Alaska Housing Finance Corp.
After the taking hold in the late 2000s, the shale gas revolution quickly became the shale oil revolution that helped flood world oil markets with supply and is now indirectly challenging the AK LNG Project status quo.
The gasline project Alaskans have come to know since early 2014 with BP, ConocoPhillips, ExxonMobil and the state as partners — now without TransCanada’s initial participation after the Legislature agreed to buy out the company’s interest last fall — moving ahead as one likely won’t be the project that is finished next decade, at least according to Meyer.
Depressed oil prices have hit the producers’ and the state’s balance sheets hard. Walker’s strong desire to keep progressing to construction, combined with the producers’ waning willingness and ability to move along at the same pace has the parties in talks about a new Alaska LNG structure.
That’s where Meyer comes in.
By separating the need to be an owner in the project from the ability to obtain pipeline and liquefaction capacity, he said the state could lead the Alaska LNG Project as an infrastructure project.
That would not mean, however, that the state would be forced to foot the bill.
Meyer said he envisions potentially numerous investors: those looking for stable, long-term investment returns in the “low double-digit” range, percentagewise, or less.
With the state in the lead the project could also reap tax advantages that, when combined with a larger pool of investors, could cut costs on the finance side.
Those investors could be pension or insurance funds, or the large Asian utilities that are the likely LNG customers. The producers would not be excluded from that list either.
“The producers are going to be welcome owners. We’d love to have them,” Meyer said.
In the event one or more of the current producer partners chose not to buy into the project further, they would then become welcome upstream customers in what he described as a “contract carrier” pipeline and LNG plant.
“When I look at the producers I first see customers,” he said. “We want to recognize that however this project goes we’re going to look at them as customers. We’re going to provide a very valuable service and we’re going to provide that service at a very reasonable price because they’re going to need to sell their product into the global arena as well.”
The prospect of the producers not wanting to sell their gas into the state’s line is an unlikely one, he said.
“My belief is that if we build a pipeline that lets them access the global market they will definitely want to sell their gas,” Meyer said.
Last fall Walker requested and got informal letters of commitment to sell gas into a project from BP and ConocoPhillips in the event the companies decide not to directly invest. ExxonMobil did not provide such an assurance.
The nine-page agreement signed last December states that the sales offer will be made to the State of Alaska if “mutually agreed commercially reasonable terms can be reached between the relevant party (the withdrawing company) and DNR (the state Department of Natural Resources).”
In an analysis for the Legislature, Janek Mayer and Nikos Tsafos, of the firm enalytica, estimated that if the state were to purchase ConocoPhillips’ 22 percent share of the 35 trillion cubic feet of North Slope gas reserves, the cost, at $4 per million British Thermal Units, would be $19.2 billion.
The structure would also open up the project to other North Slope producers with natural gas to sell. It would be an outlet that would hopefully spur new gas development, Meyer said.
Changing the investment structure does not mean changing the look of the infrastructure itself, though. The North Slope gas treatment plant, 42-inch pipeline and 20 million tons per year liquefaction plant that have been heavily studied and partially engineered is what the state would move ahead with — an export-sized project as opposed to an in-state only pipeline.
With producers as upstream customers of the project contracting for space in the pipe and capacity in the liquefaction plant, the end buyers of LNG are then customers of the producers, or the state, with its share of gas, and not direct customers of the Alaska LNG Project.
The new structure fills the first of the two major objectives that need to be achieved to make the project successful: It relieves the $45 billion-plus investment burden from the current project participants, including the state, according to Meyer.
“There’s a lot of cash sort of sitting on the sidelines waiting for a good infrastructure project. An Alaskan LNG project is a good infrastructure project,” he said. “You’ve got a U.S. project — not only U.S. — it’s in Alaska, which has a demonstrable track record of LNG and energy exports, so this will be a very good infrastructure project.”
He also doesn’t see convincing some key legislators, who have butted heads with the governor over prospective changes to the project can be successful as an issue. There are concerns about the state taking a larger role.
“What I want to see us do is shave billions off the cost and years off the in service (timeline) and I think if we do that we’ll have full support of legislators,” Meyer said. “I think there’s a misconception out there that ownership is equivalent to investment and from my background I’ve never assumed that.”
The second overarching objective is making the project globally competitive.
Alaska’s near 50-year history of LNG exports from ConocoPhillips’ liquefaction plant and export terminal, just down the road in Nikiski from where the new plant might go, is a big plus for utilities that emphasize reliability of supply as much as anything, Meyer said.
Additionally, Alaska is a direct sail to all the potential Asian markets; while Lower 48 competitor selling LNG have to go through a third country, Panama, to reach Pacific customers.
Those factors, along with the fact that the gas reserves at Prudhoe Bay and Point Thomson are very well defined and developed, combine to still make the Alaska LNG Project a good one, according to Meyer.
The established North Slope infrastructure also helps de-link the cost of North Slope natural gas from oil, easing price fluctuations.
“If you take reduced volatility, stable venue, state, location and competitive price I think we’ve got a real winner. It’s all those things that go into a large utility purchase decision. It’s not just price, but price is important; we have to recognize that,” he said.
He added that even though Lower 48 Henry Hub priced natural gas is now in the $2 per thousand cubic feet, or mcf, range, making it competitive with Alaska in Asia despite much longer shipping times, the Henry Hub market has historically been a volatile one, as well.
Market analysts vary on projections for long-term Henry Hub pricing. Some feel that fracking fundamentally changed the North American natural gas market; while others contend it will still be subject to future price spikes.
Since “fracked” gas became an established commodity in 2010, Henry Hub indexed natural gas exceed $5 per mcf once for a brief period early in 2014.
The price issue for Alaska LNG will be at least partially addressed through timing.
The current spot prices for LNG delivered to Asian ports of about $4 per million British thermal units (roughly equivalent to a per mcf price of natural gas) is nearly half of what Asian market spot prices were a year ago and nearly 75 percent less than what they were when the Alaska LNG Project was being conceived just a few years ago.
That is simply the effect of LNG suppliers responding to the largest increase in demand the world has ever seen with the largest supply increase ever, Meyer said.
The world is oversupplied with LNG. However, he sees the market imbalance correcting in the 2022-25 timeframe, which is the “demand window” the state needs to hit, he said.
“One of the good things about natural gas is it is the preferred hydrocarbon molecule. The world is trying to get cleaner,” Meyer said. “We’re going to have this consistent demand curve (growth) for natural gas.”
The current project timeline calls for startup sometime in late 2024 or 2025.
But that also means time is of the essence. Meyer said the state “needs to be out in front of customers right now,” and starting to get contracts signed within the next two years.
That will mean developing an AGDC marketing team.
“Our marketing won’t just be LNG, it can also be this project,” he said, noting a utility could buy gas from a producer and use the Alaska LNG Project as a means to move and process what it bought.
The corporation has until now filled the role of a technical body, first focused on engineering the idled Alaska Stand Alone Pipeline, or ASAP, project.
To that end, the work done to date on the project’s upcoming Federal Energy Regulatory Commission license filing — FERC’s environmental impact statement process — “far exceeds” what is typically done on Lower 48 export projects at this point in development, Meyer said.