As the lights go out at coal-fired power plants, what happens to the electric grid?
Written byDANIEL CUSICK, ClimateWire
John Moura spends a lot of time thinking about summer these days, but he's no vacation daydreamer.
From his office at the North American Electric Reliability Corp. in Atlanta, Moura can watch the pavement bake on Peachtree Street and think about how a prolonged heat wave, like the ones that occurred last summer across the South and Midwest, could make his job a living hell.
That's because as the mercury rises outside, parts of the nation's electricity grid will be pushed to the limits of their capabilities. And Moura, NERC's manager of reliability assessment, will have to determine whether sufficient power can move to the right places at the right times to avoid transmission bottlenecks, brownouts and power outages.
Difficult as this job is, it will get harder in years to come as the electric utility sector undergoes one of its most sweeping transformations in a century, with hundreds of coal-fired generation units being retired or being retrofitted, mostly with natural gas.
The changes are coming as utilities and their ratepayers are being squeezed between two powerful and contradictory forces.
On one hand, Sunbelt states like Texas, California and Florida, as well as portions of the mid-Atlantic and East Coast, are experiencing rising electricity demand as population growth and a modest economic recovery lead to more power demands on the grid. To meet those needs, utilities say they need to boost all sectors of their operations -- fossil, nuclear, hydro and renewables -- as well as the transmission system that links all those power plants to end users.
Pressing from another direction are government regulators and a powerful coalition of environmental groups determined to reduce the nation's dependence on fossil fuel energy, and specifically coal-fired electricity. Doing so will reap huge public health benefits, according to U.S. EPA, and could help ameliorate a warming climate by reducing greenhouse gas emissions.
Moura and his colleagues at NERC, an agency authorized by the Federal Energy Regulatory Commission to establish and oversee reliability standards for the bulk-power system, are caught in the middle. While the agency tends to be agnostic about how utilities generate power, it cannot ignore the regulatory, political and economic ground that is shifting under coal.
Decision time for utilities
"The biggest worries I have, the ones that keep me up at night, are the [EPA regulations] that have a timing aspect to them, where the clock is ticking and the utilities have to make difficult adjustments over a short period of time," Moura said in a telephone interview last week.
Among the pending regulations are new policies targeting coal plant mercury and air toxics, carbon dioxide, and discharges of water that are used to cool turbines. Most of the rules' provisions will take effect in 2015 or later, but they are forcing billions of dollars' worth of decisions, and many utilities are already responding, by either pledging to upgrade existing plants or retiring them and opting for other energy sources.
Increasingly, utility officials and independent experts say, the rule changes will make producing electricity from coal difficult without running afoul of EPA.
"These companies don't want to break a federal law," said Moura. "But in some cases, they have an obligation to meet their customers' demand, and they also have to meet mandatory NERC reliability standards. We can't put these utilities in a place where they have to pick what federal law they're going to break. That's not fair. We need a transparent process for them to be able to say, 'How do I get from point A to point B?'"
Without a clear path to make an orderly transition from coal, many utilities will face the difficult choice of idling coal plants that provide the bulk of their customers' electricity. A shutdown of that magnitude would place the grid at much greater risk of failure, officials said.
The industry-funded Electric Power Research Institute recently concluded that the pending coal plant regulations, combined with very low natural gas prices that are driving coal-to-gas fuel switching among utilities, could result in the loss of 60,000 megawatts of coal-fired power by 2020, one-third of the existing coal fleet (EnergyWire, June 1).
For companies that choose to keep their plants operating, the suite of options for meeting the EPA regulations -- pollution control upgrades or coal-to-gas conversions -- are both capital- and time-intensive. Fleetwide projects that a utility might plan and implement over a decade are now being compressed into a few years. It's enough to leave utility executives scratching their heads.
A 'big concern' over Big Sandy
American Electric Power Co., the nation's largest coal-burning utility, recently announced it would revisit a decision to spend $1 billion in emissions control upgrades at its 1,078 MW Big Sandy coal plant in eastern Kentucky, citing uncertainty about the pending EPA regulations and economic conditions favoring natural gas.
Melissa McHenry, an AEP spokeswoman in Columbus, Ohio, said the company has been among the most aggressive in the country in terms of shifting away from coal. It plans 6,000 MW of retirements across its 11-state service territory, with plants and transmission lines concentrated in the Midwest, Appalachia and the Southern Plains.
Yet even with significant investment in natural gas-fired power generation and an unprecedented expansion of renewables like solar and wind, the company remains at risk of failing to meet customer demand without a backbone of baseload power plants, many of which are powered using coal.
"The big concern we have, especially when you have deadlines hitting in just a few years, is that most of that [coal] generation is going to go away around the same time," McHenry said. "And for the other coal units that are going to continue operating, if they haven't already been retrofitted with pollution controls, they will need to be offline for certain periods of time to do that work."
As its coal plants go offline, AEP will have to shift the burden of electricity generation to other companies and even other regions, relying more on electricity imports to keep the lights on for its 5.3 million customers.
Those shifts could stress the nation's transmission grid, which is agile enough to allow electricity to move within regions but becomes more problematic if power must be moved across long distances, where lines are owned by different companies and regulated by different regional transmission organizations (RTOs).
Within the United States and Canada, the primary links are between the Eastern Interconnection, comprising six regional RTOs east of the Great Plains and three eastern Canadian provinces; the Western Interconnection, covering all the Western states and two Canadian provinces; and the Electric Reliability Council of Texas (ERCOT), which governs the grid across 85 percent of Texas.
AEP's operations span two RTOs within the Eastern Interconnection: the PJM Interconnection, which oversees grid reliability across parts of 13 Eastern and Southern states and the District of Columbia, and the Southwest Power Pool, which governs power supply and demand in nine states in the Great Plains, South and Southwest.
Trouble could start in Texas
Moura, the reliability manager at NERC, said the coming coal plant retirements will affect grid reliability in all parts of the country, but he noted particular stress points in ERCOT, where demand growth in load centers like Dallas, Houston and San Antonio has outpaced utilities' ability to build new generation plants.
ERCOT also operates under a unique set of rules whereby electricity generators operate as independent companies outside the purview of the state Public Utility Commission. Owners of transmission and distribution infrastructure are regulated by the state, while retail electricity providers compete to provide service to businesses and homeowners.
The decoupling of electricity generation from transmission, distribution and retail service has created problems in Texas, however, because demand is outpacing supply, while generation owners are facing the same pressures to reduce their use of coal.
Luminant Energy, Texas' largest electricity generator and a major miner of lignite coal for power production, announced in September that it would close two coal-fired units at its Monticello Steam Plant in north Texas to comply with EPA's Cross-State Air Pollution Rule. A third production unit at Monticello, along with two coal units at the company's Big Brown plant near Fairfield, were to begin burning low-sulfur coal from the Powder River Basin.
Meanwhile, a recent Brattle Group report authorized by ERCOT and the Public Utility Commission determined that the state's wholesale power market was not robust enough to attract new investment, further raising the prospect of electricity rationing or rolling blackouts as the state's supply-and-demand scales tip further out of balance.
Terry Hadley, a spokesman for the Texas Public Utility Commission, said the agency is working to address the problem, in part by changing the state's wholesale power rate structure to try to attract new investment in power plants. "We're seeing some announcements from [generation] companies saying they're ready to act," said Hadley.
For example, Panda Energy has taken steps toward constructing roughly 2,000 MW of new combined cycle natural gas plants in Temple and Sherman, Texas. The two plants would rely on gas produced from wells in the nearby Barnett Shale.
And CPS Energy of San Antonio said in March it would purchase an 800 MW gas-fired power plant in Guadalupe County from Tenaska Inc., allowing it to make up for generation being lost to the planned closure of the company's 871 MW A.J. Deely plant in 2018.
Hoping for a mild summer
ERCOT, meanwhile, has said it plans to add nearly 2,000 MW of new wind power capacity in 2012, up 20.6 percent from 2011. Total installed wind power capacity in ERCOT's territory is expected to exceed 11,500 MW by the end of the year, according to the agency's reports.
In 2011, ERCOT approved more than $817 million in new transmission projects to help bring that new electricity to market and has reviewed or approved an additional $450 billion worth of transmission upgrades since the beginning of this year.
But with an average seven-year lead time to get transmission lines built, Moura said, states and utilities are trying to hit a moving target for electric reliability. "There's a lot of political uncertainty, a lot of market uncertainty and a lot of regulatory uncertainty," he said.
Officials acknowledge that such investments are an important piece of the long-term solution to Texas' electric reliability risk. Meanwhile, the state can only hope for a milder summer than 2012.
"The most positive note in all of this is that the weather does not seem nearly as severe in terms of heat and drought for 2012 as it did in 2011," the Public Utility Commission's Hadley said. "Unfortunately, that's something we can't control."