Energy leaders say Wyoming's natural gas producers shouldn't look to electric utilities to increase regional demand for their commodity.

At least not at the scale that would ease crowding at the inlet of interstate pipelines that ship Rockies natural gas to customers outside the region.

"We're building gas pipelines to bring prices back up. So if you're contemplating building an ammonia plant (for example), you'd have to ask if the prices are going to stay low. Certainly, we're not in favor of a low price environment," said Brian Jeffries, executive director of the Wyoming Pipeline Authority.

Wyoming taxpayers are the biggest losers in the Rockies natural gas price differential, which is forecast to drain an estimated $470 million in unrealized revenue in 2007, according to figures provided by the Wyoming Department of Revenue.

The estimated 35 percent price reduction is the result of regional natural gas production outpacing available pipeline export capacity.

Natural gas consumption within Colorado, Utah and Wyoming averaged 1.66 billion cubic feet per day in 2006, according to the Energy Information Administration. That's just 19 percent of regional natural gas production, which means the remaining 81 percent must find its way outside the Rockies.

Two major utilities that do business in Wyoming say they're not likely to demand significantly more natural gas for electric generation in the region, which leaves producers at the mercy of lagging pipeline infrastructure.

In addition to heating homes, natural gas is burned to generate electricity, and it's a relatively clean-burning fuel. But notwithstanding Wyoming's vast natural gas resource, coal - also plentiful in the state - remains the fuel of choice for electrical utilities here.

"If someone would sell us gas at the stranded-gas price, we'd be happy to lock down a long-term (contract)," said Floyd Robb, spokesman for North Dakota-based Basin Electric Power Cooperative, which provides power to eastern Wyoming customers.

To the ire of many environmental groups, Basin Electric recently broke ground on its Dry Fork Station coal-fired power plant near Gillette.

The co-op's involvement in coal-gasification technology has not evolved from the accounting department to the engineering department. And natural gas still primarily serves as a peaking fuel for Basin's electric generation.

Robb said Dry Fork's 385 megawatts will serve increasing "base-load," or continual, demand from rapidly growing industrial and residential sectors on the west side of Basin Electric's service territory. Already, the co-op is shifting 70 megawatts from its eastern electric generation facilities to its western customers, which includes Wyoming.

"In most places natural gas is not used for base-load," Robb said. "Fuel is the most expensive part of your operational cost - that's why coal is so attractive."

Basin Electric's counterparts at Rocky Mountain Power agree.

The cost of natural gas tends to fluctuate between $5 and $7 per million British thermal heating units, or Btus, according to Rocky Mountain Power, whereas coal trends close to $2 per million Btus.

Even though the wholesale price for Rocky Mountain gas dips to less than 10 percent of the national average, it doesn't typically stay that low.

"There's much more price volatility with gas," said Rocky Mountain Power spokesman Dave Eskelsen.

State of uncertainty

Rockies natural gas producers aren't the only ones who rely on major expansions to interstate transportation systems. North American Electric Reliability Corp. said in October that electrical demand across the United States is growing twice as fast as commitments to new electrical generation and transportation.

Closer to Wyoming, Basin Electric says it needs to add 1,800 megawatts of new electrical generation throughout its nine-state service territory by 2021. Rocky Mountain Power estimates it will have to add 1,700 megawatts by 2014.

Xcel Energy in Colorado said last week it expects natural gas-fired generation could play a significant role in filling 800 megawatts of resource that will go out for bid.

"We just don't know what percentage we'll get from renewing contracts from existing facilities (coal, natural gas and renewable), but it probably won't be conventional coal, obviously," Xcel Energy spokesman Mark Stutz said.

That nuanced answer is prevalent in the industry, because no utility really knows for sure what will fuel new electric generation.

To say that climate change and ever-increasing energy demand have thrown the industry into an extreme state of uncertainty would be an understatement, according to Eskelsen.

"It is unclear to the company right now what kind of resources might be required or prohibited, depending on energy policies as they develop in the various states" and at the federal level, Eskelsen said.

Although utilities are not planning large-scale natural gas electric generation in the Rockies, large urban areas outside the region are.

"With clean air standards in Detroit, Pittsburgh, (Philadelphia) and Boston, it's difficult to put a new coal plant there. So a gas plant gets pretty attractive," said Kobi Platt, a natural gas analyst at the Energy Information Administration.

For now, Wyoming's natural gas producers are counting on price relief to come in December when another phase of the Rockies Express Pipeline will open export capacity by nearly 25 percent.

The bad news: Rockies producers are on track to again approach export capacity by 2010 or 2011, again driving wholesale prices well below the national average, according to the Wyoming Pipeline Authority.

There's no easy fix. Decisions on what fuels to use, where to construct generation facilities and where to string pipelines and power lines - none of the choices will be popular, according to Jeffries.

"There will be a lively debate all the way," Jeffries said.

Energy reporter Dustin Bleizeffer can be reached at (307) 577-6069 or dustin.bleizeffer@trib.com.