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The deal of last resort If LNG becomes a commodity, trading companies would make logistics work, says Alaska Gas Development Authority CEO Harold Heinze, making LNG a possibility for West Coast; within Alaska, to Pacific Northwest, authority looking at possibility of compressed gas Kristen Nelson Petroleum News Editor-in-Chief
Jones Act tankers to move Alaska liquefied natural gas to markets touside the state would add to the cost of a project, but the way LNG is moved — not tankers — may solve that problem.
Harold Heinze’s estimates for the cost of liquefied natural gas tankers have drawn a lot of heat, Heinze, the Alaska Natural Gas Development Authority’s chief executive officer, told Petroleum News in a May 3 interview.
But, he said, remember that you only have to use Jones Act tankers to go from Valdez to the West Coast. Tankers for trade to the Far East are no problem, shipyards are “cranking them out now, several dozen a year, (and) the fleet’s up over 200 ships” — all foreign-flagged, there are no U.S.-flagged LNG tankers. The price has been coming down, partly because of technology and partly because more people are building tankers, and Heinze said he doesn’t think a foreign tanker would cost much more than $150 million.
U.S.-built tankers could cost three times that much — the shipyards can’t even quote a price, he said, because they haven’t built any. But the Jones Act only requires that the hull and propulsion be built in the United States, Heinze said, and “a good bit of the cost is also the cryogenic containers,” so theoretically you could build a Jones Act hull and propulsion unit in the United States which you would take to Korea to have the cryogenic units installed. That, he said, might bring the cost down to $300 million. Moving a commodity But there’s another angle, Heinze said.
“We may also be in a tremendous evolution in how gas moves.”
If LNG starts to become a commodity, “if people become smart at moving it, trading it,” Alaska LNG — which is molecularly identical to any other LNG — could be sold to the West Coast, but the LNG which physically arrives on the West Coast to fill that contract could be from elsewhere, Sakhalin perhaps. And the Alaska LNG which is sold to the West Coast physically goes to fill a contract in the Far East.
“I pay the other guy to sail the longer route and make the delivery (to the West Coast), I pay for all that, and I’m still money ahead… So at some point I just don’t build the Jones Act ship… I use the world fleet.”
That would require a world in which LNG is a commodity.
“LNG is not a commodity yet,” Heinze said, “but I see it going there.
Would the world fleet be big enough? Well, in 10 years, as larger LNG tankers are built, there will be a surplus of smaller ships, he said. There will be some 200 of these older — but well maintained — LNG tankers available. The aggregators “And if it’s a commodity that has implications in terms of transportation costs, pricing, other strategies. It also has tremendous implications in terms of people wanting to be involved.”
For the highway route, all the major oil companies involved are players in the Lower 48, in Canada and in Alaska, and have indicated they will be big players in LNG coming into the United States.
These big players, he said, “are positioned in four major parts of the thing. The only thing they don’t do is consume a lot of gas.”
In the LNG world, he said, there will be the five mega-majors and British Gas — BG, “and then probably room for one or two major Japanese trading company types as aggregators, people who buy lots of little supplies and meet lots of little demands. … that’s what trading companies do.
“And that’s why Mitsubishi is interesting, because if anybody is going to play, they’re going to play that role.” Trading companies make the logistics work The trading companies, as aggregators, have “got a little piece of a lot of things — supply — and they’ve got a part of lots of markets. And they make the logistics work.”
That’s why, Heinze said, he doesn’t get excited about the tankers.
If LNG becomes a commodity on the world market, “Mitsubishi will make it work. My only negotiation with them is how much I’m going to pay them to make it work. They will make it work at the lowest cost, and I will pay them a fee on top of that. And that’s the only negotiation, is how big’s the fee.”
Mitsubishi would place the LNG in the market in Japan and would own or lease LNG tankers.
They would do the logistics. They already have, Heinze said, “the ability to exchange cargoes, meet contract volumes. I just become a supply point for them. I don’t worry about where my gas is going: I don’t care.”
And the tradition of the trading companies, he said, is to invest in the project.
“Traditionally, in the LNG business, people — especially people like Mitsubishi — try to go as far upstream as they can. They start in the market and go all the way back. They’d like to be in the pipeline. … They want the return on investment as well as the transaction fee.” Costs, business structure Heinze said that he has used the producers’ pipeline cost estimates, and also their estimates — scaled to size for a smaller project — for the gas treatment plant.
The cost estimates Heinze has for the development authority LNG project total out at $10.5 billion, including a 2 billion cubic foot a day treatment plant on the North Slope ($1 billion); 800 miles of 36-inch pipeline ($3.5 billion); a two-train liquefaction plant ($3 billion); tankers ($2.25 billion), “a proxy for what I would actually contract for,” Heinze said; and the spur pipeline to Cook Inlet, a natural gas liquids plant, and regasification facilities on the West Coast ($750 million).
The development authority hasn’t yet decided on a business structure, Heinze said. Is it a holding company, a nonprofit, a utility? Different business structures “imply different things in terms of debt and equity and borrowing rates and security and good faith and credit of the state,” he said.
But he has prepared a comparison of what he calls “notional cost of service” per million Btu comparing commercial terms (30 percent equity at 12 percent return and 70 percent debt at 8 percent) and a utility-type structure (20 percent equity at 12 percent return and 80 percent debt at 5 percent), comparing the development authority’s LNG proposal and the highway project.
These costs of service, he said, do not include wellhead value of natural gas.
If the development authority built a project on commercial terms, its LNG project would have a cost of service of $2.51 per million Btu, compared to $2.27 per million Btu for the highway project.
Built on utility terms, the authority’s project would have a cost of service of $1.94 per million Btu, compared to $1.79 per million Btu for the highway project.
Throughput for the LNG project would be 2 billion cubic feet per day, compared to 4.5 bcf for the highway project. Total capital costs are $10.5 billion for the LNG project, $19 billion for the highway project.
Heinze said this notional cost of service is not a tariff, but “a way of trying to describe, in one number, the relative economics” of a project. Then you add the wellhead value, and “that tells you something about what you have to get in the market for it to work.”
If you add a dollar for the wellhead value, he said, that’s $3.51 for the authority’s project. “What that says is, you can satisfy those basic economic conditions — debt, equity, return on equity — if I get $3.51 in the market.”
And right now the market is more than $5. Qatar will set price floor “Well, nobody expects it to be five bucks forever. People use three and a half as a good testing point because that’s the number that people describe Qatar delivering LNG to the United States,” Heinze said.
“And at 900 trillion cubic feet, they are the 8,000-pound gorilla of this thing. What they can do starts to affect what everybody does.”
What Qatar has done, he said, is make deals with the major oil companies to sell at the wellhead and the companies make all the investment and incur all of the risk downstream of the wellhead, and also make all the profit.
And even if the mega-majors can deliver at $3.50, that doesn’t necessarily mean they will.
“I don’t think there’s going to be a ‘gaspec’ but I think the mega-majors will play a role that looks more like OPEC” in the gas business, Heinze said, just to provide some supply-demand price discipline.
And LNG out of Qatar will set the price floor because of the large supply there. “It can go below that, but it can’t stay below that for a long time, because the guy with the big supply rules the day.”
And the high end? That will be set by alternatives to gas, and if you look at the $5 price today, he said, “there aren’t a lot of people switching to oil or coal. They’re still using gas, even though it’s a lot more than it was.” Authority’s costs in range At $2.51, looking at a range of projects around the world from $2.20 to $2.60, the authority’s LNG notional cost number is at the high end, Heinze said, “but it’s in the range.”
What the authority is working on now is demonstrating that the project is feasible, “and that’s what these numbers say — we’re feasible.
“It doesn’t say it’s a good investment, it doesn’t say it’s the best investment. Those are issues that come down the road. But is there a project here that I can define that makes sense economically? And the answer is yes.”
Heinze said he knows the project is feasible by looking at Sakhalin.
“And here’s mega-major Shell doing a big arctic LNG project that involves the arctic environment, it involves a fairly good hunk of pipeline, ports …”
The Shell project costs $10 billion for 1.3 bcf a day; the authority is proposing to spend $10.5 billion for 2 bcf, he said.
“You don’t have to be quick with numbers to figure out that I can’t be any worse than they are.
“And Shell made the decision to proceed. They made the decision to proceed absent one single signed contract to sell their gas.” Producers have a portfolio Heinze says he isn’t arguing with the producers’ decision that the highway route is right for them.
“My argument is, it’s not necessarily right for us. We don’t have a portfolio. We only have one thing going for us — North Slope gas. How I get that to market is my job. And if the highway dies, if the highway don’t go, I’ve got to have some other things I’m willing to look at.”
And, he said, “given the fact that they’re not interested in LNG doesn’t scare me, because they’re barely interested in the highway project.”
Heinze takes issue with the producers’ contention that at $19 billion a highway project isn’t economic.
With a notional cost of service of $2.27 per million Btu at the feasibility level, he said, “excuse me, this is an economic project. … The risks and rewards may not balance for your investment — I’m not questioning that decision — but at a feasibility level, there is an economic project …” LNG to West Coast may be essential And even if Alaska gas goes down the highway, most of that gas would go into the Midwest, Heinze said.
And California, 10 percent of the U.S. economy, is dependent on gas pipelines that would be difficult to expand in many areas.
Not to mention, he said, that power plants in Washington and Oregon are planted on top of a major gas pipeline headed south. “What happens if they suck it dry before it gets to California?” he asked.
The development authority believes there will be opportunities in the Columbia River area, the West Coast of Washington, even the Port of Long Beach.
“Because coming in at a specific spot where you can feed power plants makes sense,” he said.
The Los Angeles area uses 2.5 bcf to 3 bcf a day of natural gas. “There is no way to expand or build a new pipeline into that area. The pipelines in that area are at maximum capacity…
“If you come into the Port of Long Beach you are a mile and a half from the major pipeline connection that feeds the LA area. We think logistical circumstances like that in the long run will dominate.”
People went into Baja because projects could be done there, but there is only very limited ability to move natural gas back into the United States. LNG coming into Baja would take care of Northern Mexico and San Diego, maybe Las Vegas, Heinze said.
“So we believe truly that because of where the population is and the communities along the coast that sooner or later you’ve got to fess up to it that the only way you’re going to have this great clean energy that you really like is to figure out this LNG deal.” Compressed natural gas In addition to LNG, Heinze said the authority is also looking at compressed natural gas. LNG is cooled to minus 260 degrees and liquefied: 600 volumes of gas becomes one volume of liquid.
Compressed natural gas isn’t chilled, he said, it’s just put under pressure to about 2,500 pounds per square inch. The volume advantage is only about 100 to one, but it takes much cheaper equipment, Heinze said, just tanks instead of cryogenic tanks, just compressors instead of complicated plants, “and it turns out that for smaller volumes and shorter distances, compressed natural gas is attractive, compared to LNG.
“So for supplying around Alaska, we’re very interested in compressed natural gas.”
The advantage is great enough to go to the Pacific Northwest, he said, but probably not to Baja, and certainly not to Japan.
A compressed natural gas facility looks like a bunch of 36-inch pipe, Heinze said, and the pressure, 2,500 psi, is the same as that in a pipeline, so the risk elements are no different than a gas pipeline.
For smaller volumes of gas, in areas such as remote Gulf of Mexico fields, compressed natural gas is a transportation alternative to pipelines.
In Alaska, you could drag a barge with compressed natural gas in 36-inch pipe to a community and leave it there.
And 36-inch pipe only requires a rolling mill. Steel plate could come to Alaska on coal barges making the return trip.
We are the tail of commercializing North Slope natural gas, Heinze said, the second or third or fourth option.
But nothing is dead and buried — it’s alive and in play, he said.
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