When its history is written, the Kemper County clean coal plant in Mississippi might be seen in the same light as a transatlantic liner at the dawn of the jet age: a gallant piece of engineering to be sure, but ultimately irrelevant.
The first page of the 582-megawatt integrated gasification combined cycle (IGCC) plant’s history was written 28 June.
That was when Southern Company and its Mississippi Power business unit said they would suspend efforts to start up part of the power plant intended to convert lignite into synthetic gas. Once converted, the gas would be combusted to drive turbine generators in a fairly conventional “combined cycle” part of the plant.
Indeed, that part of the plant has been burning natural gas for months to generate electricity. In late June, the companies said they expect it to continue to do so.
An engineer’s report filed with Mississippi utility regulators in May outlined a laundry list of problems with the gasification part of the plant, whose final price tag may have been around $7.1 billion. Problems included: chronic coal dust suppression issues; tube leaks in the synthetic gas cooler; insufficient process water capacity; and a too-small nitrogen plant, which required trucks to haul gas to the plant.
Those troubles point to the first of three factors that doomed the clean-coal portion of Kemper County: overly complex technology.
IGCC technology can be thought of as a chemistry set bolted onto what is now a well-established gas-fired power plant. The chemistry set exists to strip out methane from the coal feedstock along with a range of byproducts that can be sold commercially or disposed of.
The May engineer’s report hints at the complex supply chain around the plant: water supply from the City of Meridian, natural gas from Tennessee Gas Pipeline, carbon dioxide sales to Denbury Resources, nitrogen supply from Air Liquide, and sulfuric acid and ammonia sales to Martin Product Sales.[shortcode ieee-pullquote quote="Perhaps more critical to the plant's fate were "unknown startup, operation and technology risks."" float="left" expand=1]
Perhaps more critical to the plant’s fate were the “unknown startup, operation and technology risks” cited in the report. They included equipment reliability issues associated with sustained integrated operation of both gasifiers at design capacity, sustained electrical production on both combustion turbines at rated capacity, sustained production of byproducts at design rates and quality, and overall plant process control integration.
In short, with spending that could be recovered from customers capped at more than $5.6 billion and with the startup more than 550 days past a November 2014 startup date (itself a delay from an previous projected in-service date), the integrated gasification technology remained far from ready.
Rise of Natural Gas
But even as the plant’s planned in-service date slipped, a fundamental shift was under way in the economics of electric power generation. Hydraulic fracturing technology was making natural gas supplies more abundant, reliable, and low cost. For the first time in perhaps 100 years, coal’s reign as king of fuels for power generation could be seriously challenged.
What a difference from even 20 years ago. In the mid-1990s natural gas was anything but a reliable fuel for electric power generation. Periodic shortages and price spikes were unpredictable yet common. By most estimates, the United States would soon become a net importer of natural gas. As a result, investments were made along the Atlantic and Gulf coasts in liquefied natural gas import terminals.
In that context, a valid case for IGCC could be made. Coal was cheap and a 200-year domestic supply could be readily identified. What’s more, few things proved as comforting to a power plant manager as a 90-day supply of coal in the storage yard. Natural gas volatility be damned: That coal pile was money in the bank.
But environmental rules mandated by the Clean Air Act began to require power plants to install a range of technologies to capture and reduce most emissions from coal-fired generation. Nitrogen oxide, sulfur dioxide, and particulates were of primary concern, especially in light of worries in the 1970s and ‘80s over “acid rain” and its impact on forests in the northeastern U.S.
The idea behind IGCC, then, was to break down coal’s chemical components prior to combustion and turn at least some of them into marketable products (witness Kemper County’s ammonia and sulfuric acid sales). The methane could be turned into a synthetic gas for combustion in a combined cycle power plant—technology that itself was coming into vogue.
The result would be electricity produced using synthetic natural gas. Hand in hand would be a more environmentally friendly profile, plus a potential revenue stream from byproduct sales. Energy independence would be enhanced by relying on U.S. coal reserves rather than imported natural gas.
But even as ground was being broken for the Kemper County IGCC, hydraulic fracturing—fracking--was gaining a foothold, volatility was being eliminated from most natural gas markets, and long-term forecasts offered assurances of long-term price stability.
Indeed, Kemper County’s economic viability began to come into question in early 2017. Long-term natural gas price forecasts began to suggest that the coal plant may have become uncompetitive when compared to existing natural gas combined cycle units at a nearby power plant.[shortcode ieee-pullquote quote=""...we all thought that gas prices were going to be double digits."" float="left" expand=1]
In a 19 February earnings conference call, Thomas Fanning, chairman, president, and CEO of Southern, said: “When we had this plant certificated (in 2010), we all thought that gas prices were going to be double digits.” By 2016, however, that assessment had changed. The result was a “reduction of gas price forecasts of 25 to 30 percent.”
(Read “Kemper County and the Perils of Clean Coal Technology.”)
In this way, hydraulic fracturing threw a wrench into the prospects for clean coal technology like IGCC. Indeed, history may tell that the plant was already a relic even as the first shovelfuls of dirt were being turned.
To be sure, coal-fired power is not the only generating technology impacted by the rise of natural gas for electricity generation. Zero-emission nuclear power plants are under pressure, too. A handful of nukes already are being shuttered due to unfavorable economics linked to abundant and low cost natural gas.
Driving Down Cost
And in this way, Kemper County fell victim to a set of broader and more fundamental trends in the power industry. Those trends favor flexibility and technologies that simplify processes and drive down production costs.
Flexibility is increasingly desired as intermittent wind and solar resources are added to the grid. When the wind doesn’t blow and the sun doesn’t shine, generating resources need to be able to rapidly take their place.
Neither coal nor nuclear power plants are well suited to this “ramping” function. To be sure, operators are somewhat adept at cycling coal-fired power plants. But the practice takes a heavy toll on equipment and is reflected in O&M expenditures. Nuclear power plants are even less flexible: they are best suited to running flat out for two years or more between refueling outages.
By contrast, natural gas-fed power plants offer the market the kind of flexibility needed to support the large amounts of renewable generating capacity that are being added to the grid. As proof, on your next flight consider that turbines derived from aircraft engines can reach full power generating capability within minutes of being switched on.
More broadly, however, the power industry is like other process industries in its quest to drive out production costs wherever possible. Coal-fired power plants are enormously complex. They include rail and barge facilities to unload coal, conveyer belts, crushers and grinders, boilers that get fouled by coal “clinkers” (which are sometimes removed by shotgun blasts), scrubbers, baghouses and other environmental control equipment, as well as ash disposal sites for what’s left after the combustion process.
Nuclear power plants are even more complex, even though both technologies share a simple objective: boil water to generate steam to spin a turbine linked to a generator that produces electricity.
The complexities mean that coal and nuclear stations take years to plan, build, and bring online. A conventional coal-fired power plant may take seven years to build. A nuclear plant may take 10 years or more. That’s a long time to tie up capital before a single watt is produced.
The complexity also adds to the cost to maintain these assets. With thousands of moving parts and dozens of systems, the failure of any one may be enough to trip a unit offline for repairs.
A final cost-cutting pressure relates to the need to automate power plant functions and reduce headcount. A nuclear power plant may employ as many as a thousand people; a coal plant around 700 or so.
A gas-fired power plant requires perhaps half that number, at most. And renewable generating resources such as wind and solar reduce that number even more. Earlier this year, Xcel Energy revealed plans to add 1,500 megawatts of wind generating capacity in the Upper Midwest with a permanent work force of just a few dozen people. Most of those will likely be maintenance workers.
A Regulatory Flaw?
A side issue in the history of Kemper County may be the tolerance for risk-taking by players in a competitive versus a noncompetitive power market. Southern Company and its business units provide electric power in markets across the South that are largely closed to competitors.
Besides the Kemper County plant, Southern is also investing billions of dollars to build two new nuclear generating units. Those plants use technology from Toshiba’s Westinghouse business unit, which filed for Chapter 11 bankruptcy reorganization earlier this year. The construction projects are behind schedule and over budget.
Speculation exists in the industry over whether the nukes will be completed at all. In late June, Southern said that its Southern Nuclear and Georgia Power business units would take over project management at the end of July. Plenty of ink can be spilled debating whether a utility operating in a more competitive market would have taken on similar long-term investments.
As it is, Southern warned investors in 28 June filing with the U.S. Securities and Exchange Commission that recovery of some $3.4 billion in expenses at Kemper County remains uncertain. Southern and its Mississippi Power unit conceivably could take a charge worth that amount on second quarter earnings.
That’s a problem for more than just the company’s shareholders. U.S. taxpayers have a stake in the Kemper County project. Mississippi Power received a $270 million grant from the Department of Energy and $412 million in investment tax credits approved by the IRS through the National Energy Policy Act of 2005 and the Energy Improvement and Extension Act of 2008.
All these factors weighed against Kemper County IGCC. Complex technology, economic pressure from natural gas, and changing markets that reward flexibility, renewable energy, and low-cost production sealed its fate.
For now, the Mississippi lignite once destined to fuel the Kemper County clean coal plant will remain in the ground.
Contributing Editor David Wagman has been covering energy issues for three decades, focusing on all forms of electric power generation, regulation, and business models. He is particularly interested in the ongoing electrification of advanced economies and the effects that distributed generating resources could have on efforts to decarbonize national grids. Wagman, who is based in Colorado, is currently editorial director for IEEE Engineering 360, a search engine and information resource for the engineering, industrial, and technical communities.