Coal, Combined Cycle

Special Report: Executive Roundtable on Natural Gas Plant Development

Issue 5 and Volume 113.

By Steve Blankinship, Associate Editor

Five executives discuss current issues affecting natural gas power plant development and future prospects in the gas sector with Power Engineering magazine. The five are Dave Fiorelli, president and CEO of Tenaska Business Development Group; Jeff Schroeter, managing director of power project developer Genova Power Solutions; Frank C. Michel, vice president-projects for independent power producer Colectric Partners; Kevin Geraghty, vice president of power generation for NV Energy; and Larry Seibolt, senior vice president, Black & Veatch energy business.

Power Engineering: Twelve months ago, many were predicting a second big gas construction boom. Now a full-blown recession has affected projected demand growth. What has the recession done to your base load projections, including your thoughts on natural gas capacity expansion?

Dave Fiorelli, president and CEO of Tenaska Business Development Group
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Dave Fiorelli, Tenaska: Our market analytics group sees new capacity will be potentially delayed about two years. That’s an average based on reduced demand from general projections based around different regions of the country.

Larry Seibolt, senior vice president, Black & Veatch energy business
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Larry Seibolt, Black & Veatch: We’re keeping a close eye on our clients’ integrated resource planning for the future and what Dave says is pretty much in line with what we’re seeing. Prior to the recession we saw a second wave of combustion turbines with the idea that we had greenhouse gas issues out there and increased capital costs of coal plants were driving people back to them. With the economic downturn we’ve seen the volume of projects remain constant but people aren’t spending money at this point. We see it coming back in two years and a boom in the area of gas supporting wind and solar.

Jeff Schroeter, managing director of power project developer Genova Power Solutions
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Jeff Schroeter, Genova: You see the RFPs (request for proposals) and CEO comments recently about delaying gas projects. They say they still want wind and the solar right now and some peaking, but they really don’t want the gas combined cycles right now. So I think we’re seeing baseload plants being delayed and even some intermediates, but it’s a function of the current economic situation.

Frank C. Michel, vice president, projects, Colectric Partners
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Frank Michel, Colectric: We’ve seen gas prices come down substantially in some areas and have even seen combined cycle plants dispatching ahead of coal units in some areas on some days. That’s because coal prices have gone up substantially and might continue to go up. And any kind of cap and trade will send it higher and be another thing that will push the combined cycles closer to the top of the pile. We’ve seen oil drop and we want to see where that trend is going.

PE: The natural gas industry says there’s enough gas in the U.S. to keep it as a viable fuel for power production for many decades to come. Some in the gas industry are trying to increase natural gas use for electric generation and even expand its use in the transportation sector. Your thoughts?

Schroeter: So far as all the stuff that’s coming out about the transportation sector, the technology sounds good. But as a practical matter that demand will not materialize anytime soon—not in five or eight years, if then. You can’t build 300,000 big rigs (trucks) tomorrow to use natural gas and put up 4,000 natural gas (filling) stations. Beyond that, I see all the shale gas as giving us a really big bubble that appears will be around for the next five years. But for developers over the next five years, the availability will not be a factor in building new projects.

Fiorelli: I agree with Jeff. While we all want to reduce oil use, I don’t see that happening so much by shifting gas to transportation fuel use, but more indirectly over time through the increased use of electricity from plug-in electric vehicles. And I think that’s a distant effect. So far as the U.S. gas (drilling) rig count, it’s down significantly over what it was a year ago, but there’s a time delay between when people stop deploying rigs and when you actually start seeing material reductions in production. So the demand reduction happened very quickly while the drop in production is lagging. We’ll see a return to prices in the long run that are much higher than we are seeing right now.

Michel: I’m not sure we’ll see long-run prices quite as high as what you gentlemen are talking about. If you go back and look at gas history and where the big hurricanes are, you take the big hurricanes out of it and gas prices have classically been relatively low and production and consumption have not substantially increased through those years. I don’t think it will get all that high. I do agree that transportation will not be a major player in this. And we’ve got to work through the whole housing inventory thing because a large part of gas goes to home heating and commercial heating and those markets are going to be depressed for quite some time. Both demand and prices will go down. And a lot of gas is being discovered and there are new supplies coming on line or about to. Altogether (drilling) rig counts are down, but if the price jumps back up they’ll get right back into it. It doesn’t take that long to put one up.

Schroeter: That’s a good point. If gas makes sense at much higher prices it makes sense at much lower prices too.

PE: What attributes and abilities do you want to incorporate into your new or existing combined cycle or simple cycle natural gas plants?

Seibolt: For new generation gas plants, what we’re seeing is load flexibility for peaking and cycling, minimum startup times and minimum emissions. Lots of people out there are looking at different fuels so they want fuel flexibility. They also want to minimize water issues that we have in certain parts of the country. On existing assets, we see power augmentation to meet their peaking demands, advanced emissions reductions and control cycles. There are a lot of studies on converting simple cycle to combined cycle. And we are seeing a lot of work in using gas to back up wind and solar projects.

Work is underway on the first two units of a planned 1,250 MW, three-unit natural gas-fired combined cycle power plant by Florida Power & Light.<br>Photo courtesy Black & Veatch.
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PE: What about various cooling technologies for gas plants?

Schroeter: Forget the term once-through cooling because I don’t think we’ll ever see once-through cooling in North America again; not on a new plant anyway. We just did an air-cooled project in New Mexico and for anything north of the Sun Belt, air cooled makes a lot of technical sense. You get south into the hot lands and you have lost capacity in the summertime so you supplement that with inlet chilling if you’re going dry, which adds a lot of capital cost. But in some regulatory areas like the Desert Southwest, there are states like Arizona that require, in effect, that you use air cooling. It used to always be cheaper and easier than wet cooling but that’s not necessarily true now with water costs up and water less available.

Then you have the liquid disposal requirement on cooling tower blowdown that involves a lot of volume. So I’m much more a fan of air cooling than I was five years ago. But it raises your parasitic load so you have to balance that with the air emissions side. Somewhere the environmentalists need to find balance with what they want.

Kevin Geraghty, vice president of power generation for NV Energy
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Kevin Geraghty, NV Energy: We currently operate 2,500 MW of combined cycle on dry cooling and the technology makes perfect sense for the Southwest, especially due to water availability. Ours have performed very well. Our newest 500 MW combined cycle will also have dry cooling. With respect to other water issues, even with facilities with dry cooling and their water demand we’ll look at expanding the use of recycled water. We have one 550 MW combined cycle that uses recycled water and to the extent recycled water becomes more available in populated areas we’ll look at it.

Michel: In the projects we have in the Southeast we’re using a lot of reclaimed water or have the plants designed to take it as soon as it becomes available. And I can see the day in the Southeast when—due to the abundance of sea water there—we would consider running cooling towers with sea water.

Fiorelli: We’re a big fan of using reclaimed water, too. We have done it in Texas. This water can be made very clean.

A Siemens Energy SGT6-5000F engine at the company’s manufacturing facility in Hamilton, Ontario. Photo courtesy Siemens Energy.
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PE: Gas plants produce roughly 60 percent as much CO2 per kilowatt generated as coal plants. That might become an issue since capturing CO2 from natural gas streams is more difficult than from coal streams. Have you looked into carbon capture and storage for gas-fired generation or even considered building such a facility?

Michel: The only thing we’ve done to date is on our most recent project we set aside some space for something that might look like a sequestration plant. But right now there’s nothing commercial you can rely on and I’m not sure anyone has ever contemplated one for a combined cycle plant. No one knows where all this CO2 is going to go or how much it will cost.

Seibolt: I see that Siemens is developing a process for some of their European combined cycle plants. We see the European market leading the way on that.

Fiorelli: We have talked with one of the carbon capture technology suppliers and they are working with two combined cycle projects that would have post combustion capture: one in Vietnam and one in Norway. It’s probably true that once the capture has been completed, storage costs would be about the same as from coal. Compression costs should be about the same as well. But the low-hanging fruit is likely to be post-combustion capture on coal plants for a long time. The other thing is that the bulk of the combined cycle fleet has a substantially lower capacity factor than the coal fleet and as a result you have a lower capital utilization on the carbon capture, which is an economic drag. If CO2 emission allowance prices get high enough, capacity factor disparity goes away.

Seibolt: What I worry about is the EPC contractors taking on the risk of performance with guarantees and the owners having to finance their projects when you can’t get a good handle on how they will perform.

Fiorelli: And the other huge factor out there is if you see substantial amounts of post combustion capture, there will be a significant change in the capacity demand balance because there is a very substantial energy penalty for capture. Every unit you add carbon capture to means 25 percent less power you can put on the grid.

Schroeter: And what I could see happening is that as allowances are passed out, then perhaps the big fleet operators of coal plants will back their coal units down a bit and sell their allowances to the intermediate load combined cycle plants that don’t need a lot of (allowances). So you go into an economic system reaction for a while before getting into a true capital expansion mode.

Geraghty: One way we see of reducing carbon with combined cycle is integrating solar thermal directly into the cycle. That’s what we’re doing with our fleet. We have a plant under construction that has that capability designed in as an add-on and also at one of our 1,100 MW combined cycle plants. We’re working on integrating and replacing a significant amount of duct firing with solar thermal injection. So instead of turning a steam turbine, as at Nevada’s Solar One, you’re displacing heat input from your gas stream and getting more power from the steam turbine using a similar size (64 MW) thermal solar plant.

PE: There has been some talk about how the supply of domestic natural gas through shale extraction has the ability to sustain low gas prices and allow it to replace coal. What do you think?

Fiorelli: Anyone talking seriously about displacement has to mean short term. It will also be a localized occurrence. It happens and Frank mentioned he is seeing some of that in the Southeast now. You may see it periodically, but I don’t think it will be a major factor over the long term in replacing coal unless we ever have very high CO2 emission allowance prices.

Michel: I would agree with that, unless something happens with methane hydrates.

Schroeter: But you need a lot of energy and a lot of water for that. But don’t forget that in some places with lots of wind generation you have wind replacing coal now, too. But this is on an hourly basis or very short term. It certainly does not mean long term or routine replacement.

PE: If the economy rebounds rapidly, might we see a renewed dash for gas?

Michel: We spent some time looking at that and we think combustion turbines and perhaps some reciprocating engines might be the only things we could bring on line quickly if the economy comes back.

Fiorelli: We agree. Some of the potential mitigating factors are the potential for increased energy conservation and demand-side management (DSM), which didn’t help much the last time around in the 1980s. But there are some things that could make it different this time around. One of them is a very clear and significant flow of funds at federal and state levels from the stimulus bill into energy conservation and DSM. Secondly, I think there will be a greater opportunity to realize reductions brought about by technology that can aggregate DSM. So we have not bought into the idea this will be one more time we talk about conservation and demand-side management, but don’t see much effect. The other mitigating factor is mandated growth in renewables. The wild card there is, will anyone ever figure out an economic way to develop storage projects like compressed air energy storage?

Schroeter: I think what is different on demand-side management this time around is the advent of the smart meter and now we finally have state commissions authorizing expenditures of $200 per meter to install them. With just a few exceptions around the country, the retail customer and the retail load have never experienced time-of-day pricing and now they will. And once that infrastructure is in, that will help slow demand growth and flatten it for a while. About a year ago we were seeing combustion turbine pricing getting back to list prices again, but if you want one today delivery times have gotten shorter (and) manufacturers are starting to move a little bit on pricing. That’s a sign of the economic world we live in, as well as all this demand reduction potential.

Editor’s Note: This is the third in a series of regularly-occurring Executive Roundtables. Our Coal Executive Roundtable appeared in the September 2008 issue. Our Renewable Energy Executive Roundtable appeared in the January 2009 issue. And our Nuclear Power Executive Roundtable is slated for our November 2009 issue. To read previous Roundtables, visit and use our search tool.