Policy & Regulations

The Role of Coal: A roundtable of four industry executives discuss the future of coal-fired power generation

Issue 5 and Volume 119.

By Tim Miser, Associate Editor

No one will deny that the coal-fired power industry faces many challenges as it moves into the coming decades. Coal plant owners are being asked to make high capital investments in equipment upgrades and modifications to meet ever-tightening emissions regulations. These upgrades place pressures on the bottom lines of plants and create costs which ultimately must be passed along to consumers. Because of this, coal plant owners are working overtime to simultaneously meet the new mandates while remaining competitive in the marketplace.

With these issues top of mind, Power Engineering sat down with four coal-fired power executives to discuss the current state of affairs in the industry. Joining the conversation were: David Brozek, Senior Vice President, Sales and Commercial Operations, Mitsubishi Hitachi Power Systems Americas, Inc.; Dan Lee, Senior Vice President, Fossil Hydro Generation, American Electric Power; Rick Halil, General Manager and Senior Vice President, Energy Division, Burns & McDonnell; and Jacob Williams, Vice President, Global Energy Analytics, Peabody Energy.


Dan Lee


David Brozek


Jacob Williams


Rick Halil

PE: How is the coal-fired power industry doing in meeting emissions regulations?

Williams: When you step back and look at what the nation’s coal owners have done in terms of emissions, it’s nothing short of astounding. The level of coal generation today is essentially the same as it was in 1990, and yet today the total emitted tons of SO2, NOx, and particulates are down 70 percent. According to a World Health Organization (WHO) study, the United States’ air quality is in the top seven of industrialized countries in the world. Australia is number one. It’s telling that both the United States and Australia are the two countries in the world who are most reliant on coal generation. So in a very broad sense, the industry has done a tremendous job with investment in technologies that were developed from the 1970s and forward. Today those technologies have been deployed to the point that the United States’ air quality is a marvel for the rest of the world. We don’t pat ourselves on the back often; the industry is always told what it’s not doing well, but the fact is our country’s air quality is outstanding on a global scale.

Lee: And as all this was happening, the country maintained a balanced approach to our energy mix. As a result of this, rates were reasonable to customers. We avoided arbitrary swings in costs to customers because we balanced our energy portfolios with multiple fuels from multiple sources. So that’s a double win: the success that Jacob described, plus the success of controlling prices for customers.

Williams: And to add a data point to that statement: customers in the Northeast and California pay 60 percent more for their electricity than the states in the middle of the country. This middle part of the country gets 50 percent of its electricity from coal, and this coal power plays a significant part in providing low-cost energy. The coal fleet has done so well that when the American Lung Association listed the ten counties in the United States with the worst air quality, every county was in California where no coal is used. That’s a major change from preceding decades, and the industry doesn’t get enough credit for it. NOx controls, low-NOx burners, and SCRs have been installed on close to 90 percent of the country’s coal fleet. About 80 percent of the fleet now uses scrubbers, up from only 30 percent ten years ago. And particulate controls have continued to be upgraded along the way. Certain coal units could virtually dial out all sulfur if they needed to.

Halil: It started with low-sulfur coal conversion and proceeded on through SCR technology developments. We’ve continued to push the envelope for wet and dry scrubbers, sorbent injections, and carbon injections for mercury. All this is the result of the country’s innovations. Today, emissions are so low that we have to equip our testing personnel with very high-end technology to even be able to measure the levels in the stacks.

Brozek: Even with the current stresses on coal generation, we still predict that there will be 1000 units that will survive into 2020 and account for approximately 285 GW of generation-this despite the government’s push to control emissions. If you look back 10 years and beyond, the balance of coal in the country’s generation mix has remained constant. Even with all the stressors in today’s market, even with the broad attack on coal and the continued downward pressure by emissions regulations, coal continues to be a very profitable and stable generation source for owners.

PE: So where can the coal-fired generation industry improve?

Lee: In my mind, there’s still a lot of uncertainty, particularly surrounding the Section 111(d) issue. This uncertainty is far from ideal. We’d rather take a proactive posture in our response to emissions control, a response that will allow us to make the kinds of investments that will keep coal units viable while delivering low-cost power. We hope for more certainty soon. American Electric Power (AEP) will be retiring 5,500 MW of coal-fired generation at the end of May, partly due to the Mercury and Air Toxic Standards (MATS). This is a real concern for us in high-load situations. In past winters we’ve operated those 5,500 MW of power, but this winter we won’t have those resources. So there’s a need for rationalization regarding the timelines and limits of future regulations. From a planning perspective, it’s a tricky thing to have so much power come offline on the same day.

Brozek: We have seen that the MATS rule is the key driver for the most recent coal plant retirement analysis. Right now the United States has 1273 coal units that are used for electrical generation, totaling about 313 GW. Because the MATS standard requires compliance by June of 2016, we’ve seen a wave of announcements and projections about units coming offline. We worked with the National Energy Technology Laboratory (NETL) out of Pittsburg to analyze what emissions control technologies are currently in place, which units are currently operating, how they operate, and what their current emissions levels are. This helps us evaluate the impact on the marketplace. Based on this research, we estimate that 39 GW of coal will come offline in the next three to four years.

Williams: If you consider that Section 111(d) of the Environmental Protection Agency’s (EPA) Clean Air Act (CAA) proposes to fundamentally change the way in which the utility industry operates the grid and all its units, there are going to be challenges. This industry was nominally built over 80 years; it doesn’t move with the kind of speed that these new regulations require. This rush to move forward creates a climate in which investments are risky, because those investments might be entirely obsolete five years from now. Contrary to their intended effects, new regulations may actually impede emissions reductions, because companies aren’t sure how long their coal units will even be around, so they simply don’t invest in new technologies. That is not healthy. Normal replacements of coal plants should have been occurring gradually over time, but because of all the permitting challenges, replacements essentially stopped. As a result, we have to live with the units that we’ve got, even as they are getting on in age. There should be some logical plan to replace 60-year-old plants. These kinds of fleet transitions should occur, but it’s not happening because of all the uncertainty.

Brozek: It takes a lot of time for new technologies to displace what has been installed in this country for a century. The net generation capability of coal, gas, and nuclear energy make up 85 percent of our current capacity in the total U.S marketplace. Clearly, we should be looking at a balanced portfolio of technologies that make sense for this country, but this will take some time.

As of December 2014, the current average age of the nation’s coal units is 43.84 years, and these units are operating at a capacity factor of somewhere above 70 percent. If you extrapolate out and account for all the variables, that means the average coal unit will be 61 years old in 20 years. If these units are going to survive that long, they will have to invest in conversion modification upgrades. Ultimately, the data demonstrates that it makes sense to invest in these capital improvements which will enable aging units to survive longer.

Halil: The Clean Power Plan (CPP) will impose significant changes onto our generation mix and lead to greater levels of renewables and natural gas and even energy storage applications. We move with the industry, so we’re prepared to go wherever utilities need us to go. But replacing a generation fleet so quickly is going to be fairly difficult. Also, as fully depreciated units leave the grid, the cost of these losses will be transferred to customers.

PE: How will the new Coal Combustion Residuals (CCR) regulations impact the industry? Will other regulations have a greater impact?

Halil: There’s nothing in the newest CCR regulations that is technically difficult, or which hasn’t been achieved before. All we’re doing right now is trying to provide our customers with good advice regarding their options. The biggest challenge comes from the number of units that will need to make changes in a very short amount of time. This could result in supplier limitations as we work to deliver against increased demand. The best strategy is to move early in the process. There is potential in the regulation for continued use of a pond after a closure-triggering event does have the potential to extend the time of closures; however, the criteria required to justify the extensions are vague and have additional risks of citizen lawsuits and public relations issues. On our end, we’re identifying pinch points in the supply chain and working out solutions that will mitigate these potential bottlenecks. Today, most of the action by EPC firms is dedicated to CCRs.

Lee: Prudent CCR management is core to our business, and we’ve been doing it in a very deliberate fashion. We’re still trying to make sure we understand what the new requirements will be and how we’ll meet them, but we’re ready to respond. It shouldn’t be forgotten that these issues ultimately impact the customers we cherish, so we hope we can comply in a very cost-effective manner.

Williams: We understand how to store CCRs very well. You just have to spend the money. At issue for many older plants is the uncertainty of their future. If these plants are faced with investing significant capital right at a time when their future is in serious question, they may simply decide not to invest anything. Coal plants aren’t simply asked to deal with a single regulation; they’re asked to respond to a whole stack of regulations. Ultimately they may decide that the cost to do all these things is simply too high and make the decision to retire.

see four key air regulation drivers that will impact the future of coal generation in the United States, and which will impact owner decisions regarding generation mix, compliance, and the survival of units into the future. These regulations are: the MATS rule, the Cross-State Air Pollution Rule (CSAPR), the Regional Haze Rule (RHR), and the National Ambient Air Quality Standards (NAAQS).

The major impact of the current presidential administration’s CPP is something else that we are following very closely. We expect the administration to come out with its final determination for requirements and associated schedules this June, and this will require states to consider their implementation efforts very carefully.

In the 28 eastern CSAPR states, there are 285 GW of coal generation, and about 100 GW of that generation do not have any kind of advanced NOx control. Now that CSAPR is officially in effect, the owners of these 100 GW of generation will have to do something. We’re working with our developers and utility partners to support their analysis of the best approach to determine the survival of these units. We’re providing budget estimates, technology solutions, and performance analyses to help these people determine if a unit can add controls to meet the new requirements.

The same can be said of SO2 controls. As of today, about 95 GW of the CSAPR states’ 285 GW of coal generation have no advanced SO2 controls in place. To be in compliance then, utilities will have to add some sort of FGD technology or other SO2 control to mitigate these emissions.

Williams: I think the CO2 rules are the regulations most affecting future plans. These regulations may not affect construction work today, but they certainly will impact the path forward as we make plans into the next decade. When combined with all the other regulations in the industry, this will mean a significant increase in the price of electricity and natural gas, which is unfortunate for end consumers. The energy portfolio of the United States was built on a three-legged stool: oil for transportation and petrochemical operations, natural gas for home heating and industrial processing, and coal for electricity (along with nuclear and hydro). If we now rearrange this equation and place two legs of that stool into natural gas, and if we do this at the very time when the country begins to export natural gas into an international market at $10 to $15 per million Btu (compared to our current $3 to $4), we set ourselves up for a fundamental change in the price of electricity and natural gas in this country. That’s something we’re not prepared for.

Brozek: As part of our coal plant retirement analysis, due to the current and expected long term price of natural gas, we have seen a shift in the marketplace where owners are considering alternative approaches for environmental regulation compliance and fuel cost hedging. We are currently tracking up to 20GW of existing coal units that will either convert to gas or add gas as an additional fuel source to comply with MATS and CSAPR regulations. We currently have under contract five gas addition projects and are performing engineering studies for another half dozen units in support of this market shift.

Lee: The CPP is a big pressure for us in our decision making.

We are prepared to move the balance of our portfolio going forward, but it needs to be done at a pace and with targets that don’t put customer prices under pressure and don’t put reliability of the grid under pressure. Balance is a big deal.