North America consumes about 6 trillion cubic feet (Tcf) of natural gas annually, but it produces 7 Tcf from conventional and unconventional sources, thereby setting the stage for the opportunity to export LNG.

But the amount exported, the costs of that supply, the exporters’ netbacks, are all questions still to be answered. Until that time, first-mover projects with cost advantages will win—and natural gas prices may be “messy.” This analysis comes from Brian Forbes, partner at consulting firm A.T. Kearney, who spoke at Hart Energy’s recent North American LNG Exports Conference in Houston.

At some point in the future, companies will trade LNG cargoes globally and a vibrant spot market will develop, he said. Asian buyers might buy North American LNG and swap it for African or Middle Eastern cargoes.

The price spread between supply and the cost of shipping to global markets is the key. “If you do the analysis, the landed cost of U.S. LNG compares favorably to Australia and Africa in most cases; with Russia we are pretty close. This opens up quite a bit if you allow global trading,” he said.

Location is key

However, it’s not as important how much LNG you sell, as it is where you sell it, Forbes said, although the best markets are to Asian buyers. For example, shipping LNG from the proposed Kitimat project in British Columbia to South Korea costs $1.05/Mcf, whereas from Sabine Pass off the Louisiana coast, shipping cost rises to $2.41/Mcf. Liquefaction costs depend heavily on how much infrastructure exists at a site and the cost and extent of power generation needed on site.

A big question for U.S. producers is the effect of exports on domestic gas prices. Forbes said he expects U.S. prices to rise once LNG exports start but markets will be “messy” in his words, until price equilibrium is reached.

“You could end up with $6 or $7 gas but it might take a year, or maybe six months,” he said. “It’s hard to predict. If more shale fields are in the money and thus have access to more capital, you will see us over drill for gas. This will contribute to that messy equilibrium. The U.S. stays competitive if it stays closer to 6 Tcf of exports, so you want to be one of the first projects built and with fully committed demand.”

With increased competition worldwide on the LNG production side, it is not clear how much LNG will come out of the U.S. A.T. Kearney has run various scenarios, he said.

“Our projections show that by 2020, the U.S. will be a fairly significant exporter, likely to place 3- to 6 Tcf a year. If you can process the gas and ship it at the cheapest option, you win,” he said.

Exporting 3 Tcf annually translates to about 8 Bcf/d, he said. For context, the EIA reports gas production from seven key regions now totals a bit more than 43 Bcf/d (the seven: Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica). The Marcellus Shale alone produces about 15 Bcf/d.

Point of no demand

Forbes said by 2030, the U.S. gas market will balance with both consumption and production of about 9 Tcf annually. Australia would be producing 6 Tcf and consuming 2 Tcf by then. Certainly those projects in the front of the line, with approvals in place and groundbreaking having occurred, will be competitive and likely have the lowest costs.

“When do we reach that point when so much LNG is being exported that it gets harder to build demand? I think up to 3-4 Tcf, the market isn’t at equilibrium, but once we get to 3-4 Tcf the market starts to understand and it gets harder to build demand,” he said.

Forbes suggested one way to increase LNG demand is to export it for powering gas-fired desalinization projects, as water scarcity becomes a bigger concern worldwide.

“If Australia figures out how to lower their costs, if Russia gets its act together, the cost will go lower and the economics are different,” he said. “If China figures out how to drill its shales by 2025 … well, we’ve made a lot of money in the meantime. LNG netbacks depend on the cost of natural gas supply and that’s not going to be $4 forever.”