Coal's Uncertain Future

By Bridget Mintz Testa

For much of the 20th century, Americans viewed coal power plants as engines of prosperity — sources of affection and pride. Today, coal is reviled, thanks to the emissions it releases when it's burned: sulfur dioxide and nitrogen oxides, which are precursors of acid rain; mercury, which can cause brain damage; and tiny particulates that can penetrate the lungs and wreak havoc. Then there's carbon dioxide: One coal plant can produce millions of tons of this greenhouse gas villain per year.

To address these by-products, the U.S. Environmental Protection Agency established rules limiting emissions of sulfur dioxide, nitrogen oxides, particulates, mercury, other airborne toxins, and carbon dioxide from new coal plants. The latest carbon dioxide rule — this one for existing plants — was proposed this June; there is a one-year comment period before it takes effect.

Announced on September 20, 2013, The EPA's first proposal — Carbon Pollution Standard for New Power Plants — addressed carbon dioxide emissions for new power plants, specifying how many tons could be emitted by each plant per megawatt-hour. Natural gas plants could emit up to 1,000 pounds per megawatt-hour, and coal plants could emit up to 1,100 pounds per megawatt-hour. The coal limit is not achievable without carbon capture and storage technology, which the EPA considers to be commercially available. However, it is not in operation in any U.S. power plant. It is planned for Southern Company's Kemper Plant in Mississippi, but that plant has faced extensive cost overruns and its start-up was postponed from May to December.

The EPA's newest proposal, the Clean Power Plan, issued on June 2, addresses carbon dioxide emissions for existing plants, but not on a plant-by-plant basis. Instead, it assigns a target emissions rate to each state; the states can choose how to meet the goals by 2030.

Although this sounds more flexible than the first proposal, the industry claims that it, too, is unattainable. This is according to Robert Varela, editorial director for the American Public Power Association, the industry organization for municipal utilities.

For many power providers, coal plants are vital assets. Each one represents an investment of hundreds of millions or billions of dollars. They are long-term investments, too: Today's U.S. coal plants are 42 years old on average, according to the EPA. Thirty years is the typical coal plant lifetime, as calculated in the payoffs of loans used to build them. So most U.S. coal plants are old, but would be expensive to replace.

The plants' importance transcends money, though. For most of the 20th century, they generated most of the country's "baseload" power — the vital, always available kind that lets you flip the lights on around the clock. For the most part, they still do, although natural gas is making inroads as a baseload power fuel. According to the Energy Information Administration, the Department of Energy's data collection and analysis unit, coal accounted for 43 percent of the nation's electric power in 2013, while natural gas supplied 22 percent of electric power.

Coal is essentially always used for baseload power, whereas natural gas may be used for baseload, intermediate, or peaking power — and the same plant may be used for different functions at various times, depending on needs. Thus, while the precise percent of baseload power produced by natural gas isn't available, it obviously produces much less than coal does.

"Many older coal-fired plants have already shut down because of concern about the capital costs of compliance [with EPA regulations]," says Dan Aschenbach, senior vice president, global project and infrastructure finance at Moody's Investor Service, a bond credit ratings business. Thanks to strict regulations and cheap natural gas, "well over 100 coal-fired generation projects that had begun the multiyear process of plant development have been set aside," he adds.

Some municipal utilities, such as Lincoln Electric System in Nebraska, still depend on coal assets, but they are also diversifying power sources. Even energy efficiency, though not exactly a power source, plays a strategic role for LES.

On the other hand, the Los Angeles Department of Water and Power is ditching coal assets to meet California's stringent environmental regulations. Figuring out how to simultaneously comply with all the regulations was itself a challenge. With the planning and modeling tools it developed, however, LADWP can now address multiple regulations in a single project.

Keeping the lights on

In terms of customers served, Lincoln Electric Service is the 23rd largest municipal utility in the U.S. It provides power for about 132,000 customers in the 200-square-mile area of Lancaster County, Nebraska, which includes Lincoln (the state capital) and five other towns.

As with many Midwestern power providers, LES's baseload power is mostly generated by coal, and the utility plans to keep it that way. It comes from four plants scattered across Wyoming, Iowa, and Nebraska. LES owns portions of two of those plants — Laramie River Station in Wyoming and Walter Scott Jr. Energy Center Unit 4 in Iowa — and it purchases power from two others.

Sheldon Station and Gerald Gentleman Station, both located in Nebraska and operated by the Nebraska Public Power District, generate 41 percent of LES's total 1,004 megawatts of power and nearly 100 percent of its baseload. LES plans to keep using them for the foreseeable future and pay its share of the costs of emissions-control technologies.

LES's approach to coal may represent a public power trend. "My impression is that more APPA members are keeping their coal plants than are getting rid of them," says Joe Nipper, vice president of regulatory affairs and communications at the American Public Power Association (LES is a member). "They will make changes to comply with the regulations," Nipper notes.

The newest of the four plants keeping Lincoln electrified is Walter Scott Jr. Unit 4. Completed in 2007, it was built with the latest emissions control equipment. The other three plants were retrofitted with the technology, although the Laramie River Station only has mercury-capture capability. All four plants burn low-sulfur coal that produces fewer sulfur dioxide emissions: Less sulfur in the coal means less sulfur dioxide in the air. According to the EIA, "low-sulfur" coal contains one percent or less of the yellow element by weight; high-sulfur coal contains more than one percent of it by weight. The plants meet current EPA rules, so LES can focus on the long term instead of worrying about compliance.

That strategy is influenced by the combined city-county Vision 2040 Plan, which "has a goal and some policy suggestions on producing and using as much renewable and sustainable energy as possible," says David Cary, AICP, Lincoln-Lancaster County's manager of long-range planning. "LES has certainly grabbed onto it, and they have their own program going. That's in the spirit of the plan."

LES has indeed "grabbed onto it." Until last year, its total renewable portfolio comprised less than three percent of total power resources. That's changing fast.

"Just last year we signed a contract to bring a 100-megawatt wind farm online in early 2016," says Scott Benson, manager of the resource and transmission planning department at LES. "We've instituted new rates as incentives for customer-installed solar and other renewables. Proposals are out right now for installation and operation of a centralized utility-grade solar array either later this year or in 2015."

Precisely how much of LES's power will come from renewables isn't yet known because it depends both on customer take-up of incentives and on the contractor proposals that are eventually chosen for the large solar array.

LES bases much of its near- and intermediate-term strategy on energy efficiency and conservation. The utility's long-range planning tools indicate that a new power plant will be needed in 2026, but "our goal is to push that out further by using energy more efficiently and cutting back peak demand requirements," Benson says. Those actions could nullify LES's average six megawatts of annual growth in power demand.

To delay the power plant as long as possible, LES will use incentives to encourage customers to save energy by, for example, installing more efficient home insulation and air-conditioning and heating systems. A few years of such reductions could postpone the demand for a new power plant for 20 years or more.

California conditions

If you've ever seen — or imagined — a juggler keeping three working chainsaws in the air while riding a unicycle over bumpy terrain, then you have some idea of what the power side of the Los Angeles Department of Water and Power does every day.

LADWP is the largest municipal utility in the U.S., with a 2013–2014 power system budget of $3.9 billion. It serves 1.4 million residential and business customers in the city and another 5,000 in Owens Valley, located east of LA. Its service area covers 465 square miles in the city, plus much of the Eastern Sierra range in Owens Valley.

Keeping a system that big running smoothly would be tough anywhere. In California, it's a special challenge because the state legislature has enacted a long list of environmental laws.

"The principal driver was Senate Bill 1368," says Randy Howard, senior assistant general manager of the utility's power system. SB 1368, which evolved into the California Greenhouse Gas Emissions Performance Standard Act in 2006, disallows any electricity provider from operating or buying electricity from a power plant that emits more than 1,100 pounds of carbon dioxide per megawatt-hour. Coal plants produce about 1,700 pounds of carbon dioxide per megawatt-hour; the SB 1368 limit is about what a natural gas plant produces.

"If a plant exceeds [1,100 pounds per megawatt-hour], you can't procure it or extend its life beyond the expiration date," Howard says. "You can pay for maintenance and repair, but you can't put capital into extending its life by installing new equipment."

If a California power utility imports power from plants outside the state, those plants must also meet SB 1368's standards. If they don't — and none do — then the California-based utility must stop using those plants' power when contracts end, even if it owns part of the resource.

LADWP imports about 39 percent of its energy from two large coal plants: the Intermountain Power Project in Utah and the Navajo Generating Station in Arizona. Both facilities emit double the carbon dioxide volume of a natural gas plant.

"We have an ownership position in the Navajo Generating Station, and we are trying to divest that ownership by 2015," Howard says. The other seven owners of the plant, none of whom are located in California, declined when LADWP suggested converting the plant to natural gas. LADWP plans to replace the power from NGS with a combination of natural gas, renewables, short-term market purchases, and energy efficiency efforts.

The 36 Intermountain Power Project participants are interested in converting to natural gas. A proposal was made to "work on building new gas turbines there in place of the coal facility by 2025," Howard says. All participants must agree, and by the end of 2013, 22 had signed up.

By the rules

SB 1368 might have started it all, but other complex state regulations came quickly. They mandated everything from bringing the state's carbon dioxide emissions down to 1990 levels no later than 2020 to eliminating the use of water from lakes, streams, or the ocean to cool power plants.

Complying with the rules was LADPW's biggest challenge. "We had to integrate them because the policy makers were driving them one at a time," says Howard. "They weren't concerned about the impacts from a utility or customer rate approach. The regulations were overwhelming. We realized we had to pull this all together and look at the interactions, timelines, and costs to see how best to optimize [them] because there are limited labor resources and budget, and we still need to keep the lights on."

LADWP brought in outside help in 2005 and 2006 to build a modeling system "that would allow us to run various scenarios and give us options," Howard says. By 2010, LADWP's Integrated Resource Plan could forecast available power resources and demand down to the hour for the next 20 years. It could also test different scenarios and variables such as emission rates to optimize specific factors such as costs — a pretty good juggling act.

The model proved its worth when it helped the utility check off three regulatory requirements with a single project. "We had an almost 600-megawatt, 60-year-old coastal power plant that needed a lot of capital to keep it operational," Howard says. The plant in question is the Haynes Generation Station, located in Long Beach. It was also cooled by ocean water, which California's State Water Resources Control Board banned in 2010 as a violation of the Federal Clean Water Act.

LADWP replaced the 1960s-era power generation equipment with six 100-megawatt quick-start generators that can go from zero to full operation — or the reverse — in 10 minutes. "The old units took 48 hours," Howard says.

Quick-start generators can integrate the on-again, off-again power of renewables into the Los Angeles electric grid. The new units are now cooled by air instead of ocean water. They are also much more efficient than the old generation units.

Although LADWP is eliminating coal and LES is staying with it, both utilities strive for options in their power source portfolios. Every investor-owned and municipal utility wants the same thing.

"The consensus is that utilities must be allowed to have as diverse a set of resources as possible," says the American Public Power Association's Joe Nipper. "Locking yourself into one source is risky. ... There is a lot of hydropower in the Northwest because they have it. If you have a lot of coal, you use that. You use what you have. What we agree on is a diversified portfolio. What that means is in the eye of the beholder."

Bridget Mintz Testa is a Houston-based freelance writer.

Resources

Image: According to the Ohio Valley Environmental Coalition, mountaintop removal for coal has flattened 500 mountains in the central Appalachian region. The Hobet mining complex in southern West Virginia is one of the largest mountaintop removal coal mines in the region, spanning nearly 15 square miles. Photo by Vivian Stockman.