Air Pollution Control Equipment Services, Coal, Emissions, Policy & Regulations

Executives Discuss the Future of Coal in North America

Issue 7 and Volume 118.


By Sharryn Dotson, Associate Editor

While some critics say the coal industry is on its way out, many in the business believe the exact opposite. Though new regulations will impose stricter limits on coal power plants, many say that coal is and will be a very important and necessary part of the energy mix now and in the future. Technological innovations and cleaner burning plants – such as Duke Energy’s Edwardsport, Southern’s Kemper County, and Saskatchewan Power’s Boundary Dam project – are just a few examples of how the industry is not only adapting but pushing forward.

Power Engineering magazine sat down with Ben Yamagata, executive director of the Coal Utilization Research Council; Tim Light, senior vice president of commercial operations with American Electric Power; and John Marion, director of Technology and R&D with Alstom, about the recently proposed emissions regulations, how the rules could potentially delay the release of new technologies and how the industry has changed over the decades.

Power Engineering: What role do you see coal playing in the future of U.S. power generation?

Ben Yamagata   Ben Yamagata: Despite the uncertainty caused by EPA’s rules addressing CO2 – both with respect to new plants and the existing plants – the Energy Information Administration projects a sizeable amount of electricity demand will be met by coal, now and well into the future, above 30 percent of a growing demand for electricity. On a net basis, coal use is still very significant in the U.S., not as much as it has been in years’ past, but it’s still a significant quantity of coal being used.
Ben Yamagata
Tim Light: When we get through the MATS retirements in the next couple of years, and aside from the new proposed carbon rule, I would expect the amount of coal-fueled generation to stabilize to some extent and continue to play an important role. The value of a diverse fleet is very significant, and the economics of coal-based generation have historically been extremely beneficial for customers. You would hate to lose even more of that reliable, low-cost component of our generation base. Nationally, I would expect coal to remain around 30-40 percent of our country’s generation mix.   Light
Tim Light
John Marion   John Marion: Coal has historically been the low-cost electricity base for the United States. It’s an abundant and vast and secure domestic energy source. All of the sensible forecasts show coal to remain an important part of our energy mix. We see pressure on coal with today’s total of approximately 320-GW, or about 40 percent of generation, and some retirements of smaller, older plants in the next year due to MATS regulations, but also just given their age, it could be between 40 and 60-GW. I think the question for us today is, given the promulgation of the proposed standards from EPA for both new units and existing units, what will that do in terms of ongoing coal generation, and in particular for those of us engaged in the research and the development to advance the performance and the emissions quality and the sustainable use of coal will these regulatory policies help or hurt these efforts? I think there’s a concern today that the New Source Performance Standards (NSPS) for greenhouse gases is somewhat of a moratorium on new generation, and the new EPA proposal for existing units will continue to pressure the existing fleet and may accelerate retirements.

Yamagata: I’d like to pick up on John’s last point. In our comments on the new plant rule, the NSPS rule, there was agreement amongst our membership that that rule, in fact, will not drive technology, but will actually stifle new technology development and innovation. When you put into context that rule – and by into context, I mean the projection from EIA that we’re not going to be building new coal plants, and you look at a timeline for development and recoupment of development costs from manufacturers, there is no feasible timeline that would allow for the development of these technologies because there is no projected market for new coal builds. So, we maintain the position that a new rule on new plants is not going to drive technology at all, rather, it’s going to stop it. We haven’t had time to look at the impact of the existing rule, but I think our initial judgment is there’s nothing in the proposed rule for the existing fleet that is going to incentivize the development of technologies and the adoption of currently costly CCS technology. So all in all, it doesn’t help technology development and, in fact, will impede it.

PE: You all have mentioned the carbon rules. What are your thoughts on EPA’s carbon emission limits that they just released? Do you feel the industry will be more willing to comply or are there still problems with the rules?

Marion: The rules were just issued yesterday, and while there is some perspective on that, we really haven’t had a chance to completely digest them, but we can share some thoughts. As I speak, I’m just coming from speaking at the Coal Technology Conference in Clearwater, Florida, and just coming off of a panel with several other industry members speaking exactly about the coal regulations. We know they provide for some flexibility for states to implement plans around these four building blocks. The four building blocks being that one, dispatch gas over coal; two, shift to renewables and nuclear; three, it may involve some efficiency improvements; and four, demand side reduction. But what is the consequence of that on what we can do to improve the fleet? We have done quite a bit of work to improve the efficiency of the fleet as compared to the 2005 baseline proposed by the U.S. EPA. How much further can we go? One of the things we can do is introduce technologies, such as what Alstom provides, in terms of steam turbine controls and energy efficiency and improving the boiler and the heat rate of the overall steam power plant as part of the proposed building blocks that should be specified within the state implementation proposals. I’m a little nervous about the voice in the current regulations in regards to New Source Review, we know that simultaneously yesterday with the draft rules for new plants, there’s also some information with regards to major modifications for plants that would normally considered triggering a new source review. It’s too soon to really understand their release, but we know that some of these types of projects that I just described involve improvements to the plants, improvements in efficiency, improvements in the environmental performance also results in the opportunity to generate more power which triggers NSR. This is a particular point that needs some clarity from what was released yesterday.

Yamagata: I would say on behalf of Coal Utilization Research Council, we have not had an opportunity to review either the existing plant rule or the rule that was also issued on reconstructed or modified electric generating units. Like John, I think it’s a little too early to comment on what the exact impact would be. But, directionally, I would say that both, with respect to the proposed rule as well as the NSPS rule for new plants, the question I would pose is what are we trying to accomplish here? If the objective is to address global climate change, let’s go back to the basic facts: I don’t think there’s anyone who would disagree with the notion that there are a number of countries – particularly developing countries – that are going to use a lot more coal. A second reference point is to ask what happens if we shut down all the coal plants in the U.S., which is not going to happen as we discussed earlier. But, if that were going to happen, it would decrease greenhouse gas emissions worldwide by only 3 percent. So, you come back to the question: If the primary objective of the proposed regulations is to address the role of CO2 from coal, then I think you should question what these rules do to help do that? On one level, of course, is the building block that John mentioned that’s in the proposed existing plant rule, but on another level, we’re going to use a lot more coal in the world. If we are going to address greenhouse gas and CO2 emissions in that context it will be through technology. A fundamental question in my mind is how are we looking at these rules in the context of incentivizing the development and use of carbon capture technologies? To that point, I would say almost categorically, that these rules don’t do that. There is, at least in my judgment, not necessarily speaking on behalf of CURC in total, but in my judgment, the rules are flawed in that very fundamental way. They do not do anything to support the development of technology.

Marion: I just want to personalize it on behalf of Alstom. Alstom is a large power equipment supplier, we have our equipment in something like greater than 50 percent of U.S. power plants, 25 percent of the world’s power plants. We have a large portfolio, we like to consider that agnostic in terms of our technology position, be it fossil, renewable or nuclear generation. We see ourselves as a leader in carbon capture and sequestration technology. We believe along with the Coal Utilization Research Council and the Electric Power Research Institute, the International Energy Agency and others that the costs of addressing climate change will be reduced substantially by maintaining carbon capture and sequestration for both coal and gas, i.e. for all fossil fuels, and we need to complete the effort to make CCS a viable and cost effective option. We are putting our money where our mouth is. We have completed more than eight validation programs up to scales of 60-MW, we are currently involved in seven more projects up to 425-MW. As a technologist within my company, I’m worried that the regulations that have been proposed here in the United States will block the commercialization of CCS for at least 10 years, the 10 years being the consideration of the review cycle of the Clean Air Act following this particular proposed regulation. It does not seem to give an incentive for CCS, so we wait for another 10 years. I’m not sure if a company like ours can sustain the investment through this period. So, from a national point of view, we have been a leader on this subject, been a leader in clean coal. I think that is an open question of whether we are going to give away that leadership in the next decade after these regulations.

Light: At AEP, we’re obviously still evaluating the proposal to determine the potential impact, but it is important to remember that the June 2 announcement is just a proposal. It’s the beginning of the process, and it’s going to take a long time to work through this. The real story for us appears to be the reduction requirement for each state, which will determine the impact of the program on the utility customers that we serve. It does appear that for some states where we operate, the reduction requirement will be more than 30 percent by 2030. Like the others mentioned, climate change is a global issue. AEP is retiring about a fourth of our coal-fueled generating fleet. The units we will have left are the most efficient in our fleet, and we have spent about $10 billion worth of emissions controls over the last decade or so to meet all the existing EPA requirements. The investments that our customers have made in these plants should not be prematurely lost due to a rule that ultimately will have no significant impact on global greenhouse gas concentrations. We’re going to be working with our stakeholders as we go through the process over the upcoming months and years to try to protect the interests of our customers.

Yamagata: I would underscore a couple of points that Tim made. One is that we’re at the beginning of the process, so hopefully there will be a good discussion and recommendations that I hope and believe that the EPA will take seriously, specifically as it applies to the technology piece of it. As I said before, while we haven’t made decisions about if and what and how we as an organization might participate, if we do, it will be in commenting on recommendations via the context of what’s really going to happen on the technology side here. Just to reemphasize, this is a global issue. To the extent that it is a global issue, as John pointed out, if we’re going to do it in the least-cost methods possible, that doesn’t happen without the development and utilization of carbon capture technology. We believe it’s vitally important to keep this in the discussion and to look at ways that you can incentivize and encourage the use of the technology here, and in our case, coal-based technology.

PE: John, I wanted to see if you could clarify a comment that you made a little earlier. You said you felt the rules could potentially hold back the commercialization of CCS by 10 years or so. Why do you feel that way?

Marion: I think, again, as the other speakers have mentioned, we’re still trying to decide the implication of what was proposed yesterday in terms of existing plants. Taking that at face value, the EPA has said that they don’t expect CCS will be needed. So then, we have to look at the New Source Performance Review which, of course, is very explicit, that coal with CCS is required for new plants while, at the same time, state that natural gas combined-cycle without CCS is determined as the best emission reduction system. The consequence of that situation is that because natural gas combined-cycle, even with projected slight increases in natural gas prices, has a cost of electricity that is significantly lower than that of coal with carbon capture. If we were to look at the various options to get a value of CO2 to try to offset the costs of capturing it and storing it, we look at opportunities like enhanced oil recovery, and even in looking at a high opportunity cost, the high value of that CO2 in an enhanced oil application, the EPA concludes in their own documents that the levelized costs for such is something on the order of 60 percent higher than that of natural gas combined-cycle. Given the state and maturity of carbon capture and sequestration factoring in certain risks and uncertainties in first-of-a-kind, we can even imagine the cost of electricity for first-of-a-kind plants would be significantly higher. We know today that the few examples of larger-scale pilots that have been done have only proceeded with significant subsidies, whether as grants or other tax incentives. Given that picture, we would conclude that carbon capture and sequestration would not be the choice of plant owners and they will wait until there might be some change in their regulatory policies, which I believe there is a review of the Clean Air Act on a roughly eight-year cycle, so it’s going to take a couple of years to put these proposals into place, plus another eight-year cycle, so that is the basis of the 10-year delay in CCS deployment that we should be concerned with.

PE: SaskPower launched the Boundary Dam CCS Project. We know one complaint before the recent EPA rules is that CCS is not a viable technology and hadn’t been proven. Do you think Boundary Dam will help to prove that CCS is a viable technology? Why or why not?

Marion: I think this project is good, it represents a large-scale demonstration project of a first generation carbon capture sequestration technology. I believe its 160-MW gross, 110-MW net, so it has around a 31 percent energy rating, which we would consider to be pretty high in terms of the benchmark for what could be done. The cost of the project, I believe, is around $1.35 billion, which is quite a high cost. It is an integrated project involving the transport and EOR sequestration in an oil field. On the one hand, it’s quite an important project in moving forward and gaining the experience. I actually listened to SaskPower speak yesterday, and they themselves said if they could do it again, they would wait for some return of experience and to look to get the costs lowered. What I think we need is multiple demonstrations of first generation technologies to gain the experience and the confidence and the understanding of these technologies, both in terms of capture and the operability under load dispatch of a power plant, and the transport and sequestration and the certainty and security of such sequestration, and continuing to engage in the R&D to continue to prove the performance and reduce the costs so that the cost of electricity impacted is minimized.

Yamagata: I would second John’s point, both in terms of the significant costs of a facility that’s going to generate for the grid, or for their use, 110-MW. For $1.35 billion, that’s a lot of dollars. Costs are high, obviously, because there is much learning that needs to go on and with multiple and subsequent demonstrations, we would expect those costs to come down. Second point is as we have maintained, we know how to capture CO2, we’re learning how to deal with it, compress it, and use it for beneficial uses like in EOR. We have to do a lot of work on a significant scale with respect to putting it in a formation like a saline aquifer, presumably to store it permanently. But, I think the cost of Boundary Dam speaks for itself. Even if, as we say, we know how to do this, we’ve also indicated two things. No. 1, that all of these pieces have to be put together. I think Boundary Dam, as they are successful as I presume they will be, we will learn something about integrating all of the different pieces together. The contention that is made by others, particularly in the new plant context, is that we already know how to do this. That’s commenting lightly over knowing how to do different pieces, not knowing how to put them all together. That’s a very significant challenge. So, the cost is one issue. Putting it all together is another issue. It has led us to the conclusion that this technology isn’t ready for primetime. Boundary Dam, in and of itself, is an example of why we are not ready for primetime. It is one example of the kind of learning process that is required, but, as John said, having something that uses that much power to operate the carbon capture system doesn’t pencil out on the economic side of this, and so the cost of electricity is going to be very significant. Tim can attest to what happened at Mountaineer, just because of the costs and the fact that the utility commission, or at least one of them involved, was unable to go along with the notion of incorporating very high costs on the shareholders and the ratepayers. So, Boundary Dam is going to help, but it is very definitely not the only thing we need to be doing here. It moves us in the right direction, it’s going to take time to figure out whether or not it works. We need to figure out a clear pathway to make it less expensive. One way is to do more demonstrations, as John alluded to. We have to have the funding to do more research development and demonstrations of other kinds of technologies that at least promise to be less expensive – and even significantly less expensive – and that goes back to the point I was trying to make earlier. I think you have to look at the whole proposed package of regulatory requirements here. We have a package right now that is fundamentally driven by a set of proposed regulations that, as I said before, is not going to encouraged technology development, we think it’s going to stop it. At the same time, we also know that if we are really going to develop these technologies, it is going to require a commitment from the public sector, in fact, an enormous commitment from the public sector. Until we’re able to do that, until some political decision makers adopt the notion that coal is really important, and that technology is equally important and manifests itself by providing very significant amounts of public support — by that, I mean funding support for demonstration, research and development — we’re in this terrible quandary of requiring things that we already know that we’re not yet capable of doing from the standpoint of developing and commercializing these technologies.

Light: AEP was an early mover in this space with the Mountaineer CCS validation project, which was very successful, but was at validation scale – not commercial scale. As we were seeking regulatory recovery of the costs to scale up the project to commercial scale, we learned that the support was not there for customers to pay for the development of CCS technology. Public support and funding will be critical to the development of CCS technology, and it is concerning that we don’t have any clearer means of providing that support.

PE: Do you think there is a potential global market for CCS?

Marion: I would say that, for sure, there is a market that we see in the future that’s envisioned by the various forecasts in Europe, or internationally. For example, the IEA says it needs to be part of the mix in a cost-effective sensible approach. We at Alstom are involved in projects in the United States and the emerging markets. For example, in the UK, we’re involved in a project called the White Rose Power Plant Project, a 426-MW power plant located in the UK. The project owner is Capture Power Co. It’s a big oxy-combustion project to create a concentrated CO2 stream that aids in the capture and compression and transport, which in this case will be linked with a vision on behalf of National Grid to create a regional CO2 transportation network for sequestration and, ultimately, EOR in the North Sea. This particular project is in the FEED study phase and is being supported by the UK’s one billion pound CCS commercialization program. The project also has the support from the European Unions, the so-called NER, or New Entrants Reserve fund, to help promote and stimulate CCS. We think this, like Boundary Dam, is a very important project to gain the experience of these kinds of integrated systems, integrated not only in terms of the plant, but also the operation under normal power dispatch. The saying, which is relevant, is we need to learn by doing these kinds of projects. There is important evidence and feedback that there may be a future market if we continue to learn by doing.

Yamagata: I would add one thought and that is what is your definition of CCS? Perhaps, in that regard, we should be thinking about encouraging the installation of the most efficient type of coal-based power plants that we know the technology already exists out there. If we can encourage the installation of highly efficient commercially-available technology, that’s what we know how to do today. People are comfortable doing that, the guarantee is provided for doing that and it in fact addresses CO2 emissions. That’s point one. Second is, even in that regard, and I’m saddened to say, that this administration and this president has determined that any support that the U.S. government provides to multi-lateral and bi-lateral development efforts, whether it’s the support of the U.S. Export-Import Bank or the World Bank, the U.S. is going to provide assistance and support for U.S. exporters of coal projects abroad, but only if those projects include carbon capture sequestration, which is something we’ve already said we can’t do yet. It negates the possibility of being able to take an important important step toward addressing CO2 emissions simply by allowing us to do things that we currently know how to do. Then, as John said, internationally, we need to be doing all of these things that some of the international community is doing or trying to do, Great Britain being a case in point, of trying to move in the right direction. But, as I said before, it’s very frustrating that we don’t have the right kind of public policy environment that’s required. That public policy needs to recognize how much coal we’re going to use in the world, and we should be pursuing policies that rely on better technology that we have now and we should be supporting technology that’s under development at companies like John’s and others, and we don’t seem to want to progress down that road.

Marion: Building on Ben’s point, just to put some numbers to what he’s saying. Today’s state of the art generation is at least 10 percent lower in CO2 emissions from our existing fleet, and some can be further upgraded. For new plants we are working in consortia with other manufacturers in the U.S. to try to raise the operating temperatures of plants to take this technology to at least a 20 to 25 percent improvement in terms of the overall efficiency. Those are the things that can be done prior to CCS and probably can happen in complement if we engage in CCS. Generally, it’s sensible to think that the avoidance of the production of emissions, including CO2, and the use of less fuel is more cost effective than capture and sequestration. So it’s natural to merge these two together and these are measures that can be put into place now.

PE: Are existing coal plants being operated differently now than in the past? If so, are these changes in operations affecting O&M and emissions levels from coal plants?

Light: If you look back to 2008 prior to the recession, AEP was consuming around 75 million tons of coal a year. We came out of the recession and that dropped by about 10 million tons of coal a year. A lot of that was due to industrial customers ramping down and an overall weaker economic environment in our service territories. In parallel with that, we were seeing the shale gas phenomenon develop. Coming out of the mild 2011-2012 winter, natural gas prices dropped back down as low as $2 per million BTU. This further reduced our coal requirements, so we now burn about 55 million tons or so a year. That’s obviously had a significant impact on the way our coal units operate. It forced a lot of the more expensive, less efficient older units to operate less frequently. However, we’ve seen some of that coal burn come back this year – as gas prices increased back in the $4 to $5 range after this last winter. So we’re seeing heavier utilization of those coal units this year, but many of them will be retiring next year to address MATS. So looking ahead, excluding the carbon rule, we’re expecting most of the remaining coal fleet to operate fairly baseloaded. We will now have to wait and see how the new carbon rule plays out and what kind of impact it will have on the remaining fleet of coal-fueled generating units.

Marion: I think we see a general trend. If we look at the build out of renewable energy, we know that the dominant build that has been occurring almost over the last decade has been renewable, a lot of wind and intermittent generation resources, put more demand on the fossil fleet to be flexible, to cycle more, to cycle daily and to ramp more. Some of that is being addressed by gas firing, but certainly, the data shows the coal fleet is also cycling in ways that it hasn’t in the past. Just as you would expect with your own personal car, if you were in stop and go traffic, it puts more wear and tear on the equipment. Certainly, the industry is experiencing that and dealing with that. In terms of the specification for coal going forward, we will certainly see this is part of what we need going into the systems, and we can take some learning experience from Europe, which is also experiencing a growth of renewable energy, but also a commitment to baseload fossil to back the intermittent renewables, to make sure there is secure electric production. But for sure, it’s a technical and operational challenge that requires a lot of attention and maintenance, and organizations like AEP who is participating in today’s roundtable are really world class in these activities along with the support of equipment and service providers who together are giving attention to maintaining reliable power generation even with these new demands.

More Power Engineering Issue Articles
Power Engineerng Issue Archives
View Power Generation Articles on