By Mike Federman

Proponents of natural gas as a fuel source for electricity generation believe it will be vital to the nation’s energy mix for years to come.

The U.S. Department of Energy predicts 90 percent of the next 1,000 new power plants built in the United States will have turbines driven by natural gas.

Dependable, baseload generation is the most important aspect of natural gas. When weighed against other baseload fuel sources, natural gas stands alone.

Hydropower and nuclear generation are cleaner, but more expensive to build. The planning of new large hydro plants is negligible. The Watts Bar Unit 2 nuclear reactor in Tennessee is scheduled for operation in 2012. It will be the first new reactor to produce electricity in the United States since 1995, according to the U.S. Energy Information Administration (EIA).

Price volatility and, for some regions, availability of natural gas are dubious factors for utilities considering the use of natural gas.

“Although new natural gas-fired combined-cycle plants produce electricity more efficiently than older fossil-fueled plants, high natural gas prices can work against full utilization of these plants if such prices adversely affect economic dispatch,” according to the EIA annual electric power report issued in January.

While there is less price fluctuation in coal than natural gas, coal is the main target of emissions controls under proposed climate legislation before both houses of Congress.

Natural gas still produces greenhouse gases, but on a greatly reduced scale than coal. Combustion of natural gas emits 40 percent to 50 percent less carbon dioxide than coal, according to the U.S. Environmental Protection Agency. Natural gas emits no significant amounts of sulfur dioxide or ash particulants, and much lower levels of oxides of nitrogen than coal. 

Stabilizing Peak Demand

Arizona Electric Power Cooperative (AEPCO), based in Benson, Arizona, relies on natural gas as a backup to coal at its Apache Generating Station. AEPCO provides electricity to small distribution co-ops primarily in Southeast Arizona and Anza, California.

“Natural gas is a great asset to our members,” says Michael Nelson, AEPCO’s manager of power production. “It is a stable, reliable resource.”

Peak energy needs during summer is the most common time AEPCO turns to natural gas. The co-op’s primary peaking unit is a General Electric LM6000 simple cycle turbine—equivalent to a Boeing jet engine—that can be brought on line in 10 minutes, Nelson says.

Although AEPCO doesn’t use natural gas all of the time, having it available to supplement coal is more efficient and less expensive than buying market power for peak demands, unless spot purchases can be made for less than the cost of generation, Nelson says.

In the early 1990s, AEPCO converted two coal-fired steam units so they also can burn natural gas. Nelson says these conversions have paid for themselves by giving AEPCO an alternative when negotiating coal contracts.

Powering the North Country

Nowhere is the efficiency of natural gas more important than at the top of the world in Barrow, Alaska.

Barrow Utilities and Electric Co-op Inc. (BUECI) has seven small natural gas units that generate electricity for the community. BUECI’s maximum capacity is 20.5 megawatts, which is about double its peak demand.

“Double firm power” is crucial for keeping the lights on in arctic conditions, where 40-below zero is not uncommon into spring, says BUECI General Manager Ben Frantz.

“We could lose our two largest generators and we would still have enough generation to meet peak capacity,” Frantz says.

Barrow is only 15 miles from a municipal natural gas field in Alaska’s North Slope. The co-op buys natural gas “at a very reasonable rate,” Frantz says, and distributes it for heating and electricity.

Fueling Debate

The Alaska Gas Inducement Act (AGIA) proposes a natural gas pipeline similar to the oil pipeline from Prudhoe Bay in the North Slope to Valdez in Prince William Sound. Options could include branch lines that would bring natural gas into Fairbanks and Anchorage.

Who will build the pipeline, how far it will go and how much it will cost are undecided.

Two competing pipeline efforts are under way. The Alaska Pipeline Project is headed by TransCanada Corp. and ExxonMobil Corp., with backing from the state under AGIA. A joint effort by oil companies ConocoPhillips Co. and BP without state support is called Denali. The price tag on either project begins at around $30 billion.

Some expectations have the pipeline staying within Alaska. More ambitious prospects have the pipeline going all the way to Alberta, Canada, where it would connect with natural gas infrastructure leading to the Lower 48 states.

“They’ve been doing this for 40 years,” says Kate Lamal, vice president of power supply for Golden Valley Electric Association (GVEA), which serves Fairbanks, Alaska, and surrounding communities. “The volumes are pretty well known. The hard part is determining the route and what the state subsidies will be. It’s consuming our legislature.”

Because of the pipeline’s uncertainty, GVEA is not waiting for its construction. In April, the electric co-op agreed to finalize a 15-year fuel contract with Alaska Gasline Port Authority (AGPA) to truck liquid natural gas to GVEA’s service territory, where it will be regasified.

The natural gas will be ready in two years and will be used to generate electricity at GVEA’s North Pole Expansion Plant. About 20 percent of the natural gas will be used to heat homes in Fairbanks.

“With current oil prices at $70 to $80 a barrel, this project will save us about $12 million a year,” Lamal says. “This is guaranteed in two years. There is nothing else we can do in that time to reduce the cost of oil we use.” 

By becoming an anchor tenant for natural gas, the project can be financed by bonds through AGPA. It also offers opportunities to make natural gas more accessible in the Interior.

“The bigger positive is that this project will allow the community of Fairbanks to build out infrastructure for heating,” Lamal says. 

Meeting Population Growth

Public power utilities that buy most or all of their electricity from the Bonneville Power Administration (BPA) are not as familiar with natural gas generation as their counterparts in other parts of the country.

In 2008, electric co-ops in Washington that are full requirements customers of BPA received less than 1.5 percent of their power from natural gas. Compare that with nearly 83 percent from hydropower and nearly 12 percent from nuclear energy.

While power from federal hydro facilities and the publicly owned nuclear reactor near Richland, Washington, are sold at cost to BPA, the agency also buys power from other generation resources to augment its supply. These purchases can include electricity produced by independently owned natural gas plants.

The Columbia/Snake river hydro system is reaching its capacity, making new sources of baseload generation in the Northwest a necessity.

“Natural gas is likely to play a key role over time,” says Scott Corwin, executive director of the Public Power Council, a policy and advocacy organization that represents public power interests in the Northwest. “The extent to which it will be needed in the future is a function of how fast the region grows. Our members are looking for new resources for meeting increased loads. Even if your portfolio is mostly clean hydro and nuclear, the focus in the future is going to be in three areas: conservation, renewable resources and gas-fired generation.”

A case study of increased use of natural gas is Portland General Electric (PGE), an investor-owned electric utility serving more than 800,000 customers in seven counties in Western Oregon.

In 2010, natural gas accounts for about 26 percent of PGE’s energy resources for electricity. By 2015, that amount is projected to increase to 41 percent, according to PGE’s Integrated Resource Plan.

Balancing Wind Power

One of the drivers for building natural gas plants in the Northwest is the need to supplement the large amount of wind power being brought on line.

Because wind is intermittent, a baseload resource is necessary to ensure a smooth, continuous flow of electricity. Historically, that resource has been hydro, but the energy landscape is changing.

“As loads and wind capacity increase, the ability to balance that with mostly hydro will become tighter and tighter,” Corwin says, noting natural gas is the most likely candidate to be the new baseload resource.

Despite its potential for stabilizing power production, natural gas faces the same emissions restrictions as other fossil fuels under proposed federal legislation. That bit of irony is not lost on Corwin.

“Climate policy might further the need for wind and other renewable resources,” he says, “but because of the need to balance those resources, you might see increases in the use of natural gas.”

If Congress passes legislation to curb greenhouse gas emissions, significant impacts on public electric utilities in the Northwest likely will be delayed because dependence on fossil fuel generation is nominal today.

“But that doesn’t mean we will get off easy,” Corwin says. “Our greater exposure could be 10 to 15 years from now.”

Photo: Left, Barrow Utilities mechanics Pat Cleveland, standing, and Destin Smith service a coupling on a 4.75-megawatt Solar Taurus 60 natural gas turbine used for power generation at the co-op’s facility in Barrow, Alaska. Photo by Jim Stettler.