Alaska Dispatch

Aaron Jansen illustration

According to a new report by the Energy Information Administration, the high costs, high risks and long lead times to develop Arctic natural gas supplies don't stack up well against the huge reserves of natural gas in the Lower 48, close to strong markets.

The report isn't necessarily a black mark against a natural gas pipeline connecting the North Slope resource with markets in Alberta and the Midwest. But its author, Philip Budzik, an operations research analyst with EIA, expects the huge quantities of shale gas to push an Alaska gas pipeline to the back burner, at least for awhile.

"The Alaska gas pipeline has been a gleam in the eye of producers and the State of Alaska ever since the 1970s," Budzik said in a phone interview. "But no one anticipated that the shale gas formations would be viable production possibilities."

The Lower 48 may be awash in shale gas in known fields, but that's only the start, Budzik said. There's more shale gas to be defined in any basin that produces oil, and it's all a couple thousand miles closer to markets than Arctic gas from Alaska's North Slope.

"The resource base is clearly very large (for shale gas)," the analyst said. "How large, I don't even want to begin to speculate."

In a shale formation, thin slices of rock are packed tightly together, almost like a stack of potato chips, with gas trapped between the rocks. By fracturing the tight shale structure (breaking apart the tight stacks of rock), producers can free the gas. Shale production wasn't considered economical until technologies like horizontal drilling and fracturing methods developed. By some counts, shale gas reserves in the U.S. hold more than 2,000 trillion cubic feet of gas. As a comparison, Alaska may be home to 193 trillion cubic feet, according to estimates by the nonprofit Potential Gas Committee in Colorado. The figures represent proven gas reserves as well as those considered probable, possible and speculative.

Some industry professionals question whether shale gas will produce anywhere close to the reserve estimates, while others say that if wells turn out even a fraction of the total, the U.S. will be rich in gas for a long time.

The proximity of shale gas prospects to major markets -- and to an existing or expanding network of distribution pipelines -- offers a financial incentive for producers that's lacking in the $26 billion to $30 billion, 2,000-plus mile Alaska pipeline planned by two separate entities. Those are TransCanada with partner Exxon Mobil Corp., with a state license and $500 million, and North Slope producers BP and ConocoPhillips.

The state's Alaska Gasline Inducement Act coordinator, Mark Myers, says shale gas shouldn't be seen as a deal-breaker for a pipeline. Instead, it's good news, he says. Fast and furious shale gas development will prompt greater demand, particularly from power generation plants and other large-scale users, that shale gas probably won't be able to keep supplying long-term, opening a market door for Alaska's resource.

But that assessment runs contrary to the EIA's take. Alaska's gas will still come into play, but probably not within the next 10 years, which is about how long pipeline proponents say it will take for their projects to begin operation.

"Eventually, we're going to need hydrocarbons that are in the Arctic, including those in Prudhoe Bay," Budzik said. "When does that day arrive? It may be later than we thought three or four years ago. The producers on the North Slope have a much better sense of the economics associated with North Slope gas than I'll ever have."

The EIA publishes outlooks on U.S. energy, and analysts have been steadily bumping up the estimated shale gas resource as reserves are firmed up in more and more fields across the country. A new estimate is due out at the end of the year.

"That has a tendency to push the Alaska gas pipeline further out into the future," Budzik said. "How far out into the future, I don't know."

Budzik also cautioned that the growth in estimated shale gas reserves probably won't taper off anytime soon. Where there's an oil basin, there are shale beds. Not all are likely producers, of course -- various factors like oil field maturation and pressure affect commercial qualities, and some basins have lots of clay, which makes hydraulic fracturing less effective.

Prices received for natural gas at key North American hubs will also affect shale gas development. While prices have gyrated in recent months, the gas futures market is busy.

"Even though spot prices have been pretty low, in the $4 (per million Btu) range, a lot of producers have been selling much of their production into the futures market, which in fact has a much higher price," Budzik said, warning that the futures market is unpredictable and could trip up some investors. An EIA survey of four futures contracts shows prices between $5.16 and $6.27 as of Oct. 20.

"I'm not gambling," Budzik said.

Prices don't have far to go to hit $6 per million Btu -- that magical threshold at which companies in producing oil basins see value in also turning out natural gas for market, Budzik explained.

However, as gas prices rise, companies that have slowed or even stopped production could release a flood of gas into the U.S. system, possibly triggering another price lull.

A recent report by consultant ICF International for a consortium of North American natural gas pipeline companies agreed that an Alaska gas pipeline faces economic uncertainty related to shale gas.

"What is uncertain is whether the natural gas can be brought to the U.S. Lower 48 at a cost that is competitive with other domestic, Canadian import, and LNG supply alternatives," the report on pipeline and storage infrastructure projections through 2030 states.

Contact Rena Delbridge at This e-mail address is being protected from spambots. You need JavaScript enabled to view it .