Markets, capital, regulations top OEM execs’ concerns

Pam Boschee, Managing Editor

We’re all waiting for a turnaround in the economy for personal reasons, and for most of us, for business reasons as well.

EL&P’s interviews with two leaders of OEM companies—a provider of solutions for decentralized power generation and a provider of multi-pollutant controls—found similar concerns. Each exec discussed their business, sharing insights about what lies ahead.

Frank Donnelly
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Frank Donnelly, Wärtsilä North America’s vice president of power plants, is responsible for the company’s power plant business in North and Central America including Canada and the Caribbean.

Frank Alix
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Frank Alix, chairman and CEO of Powerspan, cofounded Powerspan in 1994 and is co-inventor on several of Powerspan’s patents.

EL&P: Wärtsilä delivers power plant solutions from 1 MW to 300 MW. What type of application do you identify as your greatest growth area in the electric industry in the near term?

Donnelly: We see the peaking market, and in our technology case, the intermediate dispatch market as being the overall market that we’re most focused on. It is true in this 1 to 300 MW area that we see a movement from centralized to decentralized power generation. Distributed generation is one definition of that. We have increasingly changed that label to one that fits our technology better, which is dispersed generation—the distinction being somewhat along the new FERC guidelines that distributed generation is the smaller units, say under 2 MW, [located] very close to small loads, and the dispersed generation would be above 2 MW. FERC is currently saying 20 MW—we think it’s more like 2 to 60, 70, 100 MW. These would be small power plants that are also close to the loads as opposed to the large, centralized power plants. Inside of those general areas, we see market segments that have remained strong during the past year despite of all the downturn—[for example,] municipal utilities. Investor-owned utilities (IOUs) are coming back and becoming stronger [as a potential market]. Those would then be followed by the industrial/institutional cogeneration market, which is waiting in part to see how FERC might go forward with the NOPR (Notice of Proposed Rulemaking) concept. Finally, the real question remains in the market of ESCOs (energy service companies) and IPPs (independent power producers), the market that was the leading market a year ago. Those markets clearly have been slammed shut today; there are few players. The question is how many players will there be in the future and where will that market end up.

EL&P: Everything seems to hinge on the NOPR.

Donnelly: A lot of it does, although the market that has continued strong through this period is the municipal utility market, which is not dependent upon the NOPR. IOUs are an interesting market as well. We’re starting to see some activity there that we didn’t see before.

EL&P: Can you give us an example of the activity in the municipal market?

Donnelly: Just recently, we signed an order for the city of Chambersburg, Penn., to provide 20+ MW of power. There are a large number of municipal utilities throughout the U.S. and they are very focused on providing their communities with energy independence. They see that as their duty and they’ve stayed solid, they have money, and they are interested in serving their population—and I think are doing a good job of it. There are small communities all over the U.S. that see it as their job to make sure that they are independent from the types of activities that are happening in all types of markets—deregulation, no deregulation, merchant, no merchant.

NEG’s Plains End facility is the largest U.S. gas-fired reciprocating plant, composed of 20 5.7 MW Wartsila units. Photo courtesy of Wartsila.
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EL&P: How has your business changed over the last year given the economic slowdown? Have you seen a decrease in new generation installations in your U.S. markets?

Donnelly: Definitely the market has slowed down, and it’s not just the economic slowdown, but it’s the many other aspects of the “perfect storm”: the recession; the fact that last year the California summer crisis never occurred the way it was imagined to; we have 9-11; the Enron/ESCO collapse; merchant market fears characterized by market manipulation fears; and a drop in gas prices from last year. All of this has occurred on the back of a very intense period of expansion in the generation market, which therefore has resulted in an oversupply. In our case, fortunately, we are not involved in any projects that were started and then stopped. From our perspective, we see fewer projects on the horizon. All of the projects that were being driven by the deregulated or the merchant market are dead now. Today, it’s driven by the ability of an investor to obtain some type of power purchase agreement, so those agreements are important to investors and the merchant concept is one for which we’ll have to [wait and] see if it comes back.

EL&P: Does Wärtsilä have a particular plan in offsetting the fact that fewer projects are on the horizon? Do you have a game plan?

Donnelly: Yes, in part the game plan is to focus on where there is business, and those are the areas I mentioned before; it’s also to look inward to see how we can improve our competitiveness in a broader area of those markets that are still alive. We feel this is really becoming a hyper-cyclical market, so just as quickly as we see it going down, we will see it turn and go back up. Unfortunately, the industry is like that today. We’re in the market for the long term—we’re making sure we do things right, have our plants running properly, look to where we can improve our competitiveness, and get the word out about our benefits in the dispersed generation market.

EL&P: Most distributed generation being used in conjunction with utility operations is based on reciprocating engine technology. Utilities are often concerned about system protection. How is this issue being dealt with in terms of grid connection standards?

Donnelly: A very important part of dealing with this is the FERC NOPR, and we’re participating in that and in fact our view is that the FERC administration headed by Pat Wood has really good insight into the market. We support the direction that they’re going and participated again this week in some of their discussions. That’s one avenue to deal with issues like standard grid connection agreements, which will facilitate small power generation. Also, we’re expanding how we view and how we offer ourselves in the market. We’re incorporating benefits from what we call ancillary services. These are services associated with our technology that create benefit for an owner, such as the period of time to ramp up the power and ramp down, the ability to follow load, and load cycling. We’re including [the ancillary services] into our financial models and lifecycle and cost analyses. We’ve tried to focus our marketing efforts with those companies who are today providing some opportunity for power generation—those that are not caught by what we’ve often called the deer in the headlamps approach. So many of those that might be participants in the market today are concerned—on the equity end, the debt side, the investors and the lenders—because of the general market situation. There is some inaction, for the moment, in some market segments, so we’re trying to concentrate on the others where there is activity and where people are inclined to invest and continue business as usual.

EL&P: But you see that as temporary inaction?

Donnelly: Yes, we do. Again this is hyper-cyclical business. It’s unfortunate that it has been this way, and I’m hoping and believing that the actions FERC is taking will help to regulate in such a way that results in more steady growth and with a view of the market that is more balanced.

EL&P: Many utility companies are struggling under serious financial constraints. Return on investment (payback period) is often a deal-breaker. What is the average payback period for a reciprocating engine?

Donnelly: It’s difficult to answer because it’s not really equipment driven. It’s investor-driven. What we’re seeing today, whether it’s reciprocating engine or any type of prime mover or style of power plant that is involved in the peaking or intermediate load arena, is that short payback periods are still being looked at. That’s just the nature of the investor appetite in the market today. So, we’re seeing short payback periods desired, three- to five-year time frames, and we’re seeing the returns coming down—but it’s very difficult to say what one investor’s return hurdle might be. It depends not on the technologies, but on the investors’ requirements. There are such varied investors—from municipals whose driving force for installing power might be not return-driven as much as service-driven, to the few ESCOs that are still in the market that are more return driven, to the IOUs that have their own views of the markets.

EL&P: What is the average cost per installed kW?

Donnelly: In general, you still see investments for power plants running somewhere between $450 and $600 per kW. It’s greatly dependent upon the type of plant that you’re installing—is it a peaking, an intermediate, is it a dual-fuel, is it a gas plant, is it a plant with special environmental needs, what’s the altitude of the plant. We have a huge area of the western U.S. that has power production at some altitude. These factors all affect power plant pricing.

EL&P: What do you identify as a top priority item for power producers in the near term? What hurdles do you see looming ahead?

Donnelly: The top priority for companies like our own is deal flow, to get power plants and get the mindset of the investors turned around. We believe there’s been a shock to the system and that slowly and surely—and more rapidly we hope in the next year—folks will be coming back to power plant investment, both on the investor side and the lender side. There needs to be some kind of turnaround in the economy, investor confidence must return, people need to stop looking internally and start looking externally again, looking at what they need to do. A new business model is certainly today being born. It’s going to replace the model that existed a year ago, the merchant model. We believe this is going to be a dispersed generation model with some distributed generation—smaller and mid-size generation that is decentralized. It’s pretty clear that in the near term the only investments that will be made will be those on the back of some type of power purchase agreement. New players will probably enter the market in order to provide the capital, because there is no capital today. We expect that oil and gas companies will eventually come back into the market quite strongly, particularly those companies that have gas to offer. We have to, in any case, work through the inventories of the hardware, the power plant equipment, that’s already in the market today [in order] to have the business come back in the near term.

EL&P: Do you see the pure merchant concept as a dead issue these days?

Donnelly: Certainly dead today. We saw it at the time as a good position for competitive power, that if it were regulated properly and if there were the correct constraints on how this could be done and not manipulated, that it’s good for a market. Our company has, in general, believed in the merchant model. Unfortunately, it’s one that had its own problems, and there’s a huge reaction against it. Might it come back some day? It might. Are there other models that can work as well? Yes, there are other models. We believe the model will be somewhere in between: it will be neither one extreme—back to the utility environment, nor will it be the merchant extreme. At the end of the day, that may prove to be the best model, [regardless of how] painful it has been to get there in this experimental way.

EL&P: Please provide a brief description of the ECO (Electro-Catalytic Oxidation) system.

Alix: ECO was developed as a multi-pollutant control technology for coal-fired power plants. We were aware, years back, of not only pending limits on acid rain constituents like SO2 and NOx, but additional regulations coming for ozone, which would constrict NOx, and then further regulations on air toxics and mercury. We looked at that as requiring, by today’s conventional technologies, three separate systems: FGD (flue gas desulfurization) or a scrubber, an SCR (selective catalytic reduction) unit typically for high-level NOx removal, and some type of activated carbon for high levels of mercury removal. We thought we could do much better than that. We set out to develop a system that could achieve the removal levels of a scrubber, an SCR system and activated carbon and do it in one integrated package that was much less costly and much less operationally constraining on the power plant. One of the hidden costs that isn’t discussed very well in the literature is that there are tremendous operational constraints placed on the power plants by a lot of the back-end technology. We sought to avoid those constraints as well.

EL&P: Commercial demonstration of the ECO technology is scheduled to be operational at FirstEnergy’s R.E. Burger Plant in Ohio in the second quarter of 2003. What are the expected results of this installation?

Alix: Up until now, our results are all based on a 2 MW pilot unit. That will be our first commercial scale unit—it’s a 50 MW unit. When you look at components and sizing made for that unit, you can derive commercial designs all the way up to a 1,000 MW unit from that single installation, and reliably so. We expect that the 50 MW unit will serve as the model for all future commercial installations and that it will achieve equivalent or better reductions in SO2, NOx, and mercury than FGD, SCR, and activated carbon.

EL&P: How long do you anticipate it will take to have the demonstration completed?

Alix: We expect to finish construction in the second quarter of next year. We will have at least six months of solid commercial data that shows not just that performance results are achieved but also that reliability levels are achieved that are demanded by the coal-fired fleet prior to booking future commercial orders.

EL&P: What hurdles are anticipated for widespread installation of ECO? How will coal plants that have already invested in separate technologies be persuaded to invest in a multi-pollutant control system?

Alix: I think that’s a very good question. We look at the ECO target market as those plants that have not yet made most of the major investments. So, when you look at the coal-fired fleet today, you can segment it. About 30 percent of the fleet has some form of scrubber installed. After the SCRs are deployed for the NOx SIP call, somewhere around 25 percent of the fleet will have SCRs installed; in general there is a great deal of overlap between where there are scrubbers and where SCRs are going. That leaves 60 or 70 percent of the fleet with nothing but particulate controls and potentially low-NOx burners, maybe SNCRs (selective non-catalytic reduction)—but basically what are low-cost APC (air pollution control) investments. What we think will drive them to make an installation in ECO will probably be when they’re driven to put SO2 controls on or a scrubber because our costs are very close to those of a scrubber. So, if you’ve got a plant with just particulate controls and low NOx burners, and you need to put a scrubber on to get further SO2 reductions, and you anticipate or need NOx and mercury reductions as well—like most of these plants will—then ECO is a very competitive installation.

EL&P: What markers do you have available for determining return on investment?

Alix: We’ve recently submitted applications with the Department of Energy under the Clean Coal Power Initiative for a 500 MW unit at AmerenUE’s Sioux Plant [St. Charles County, Mo.]. During the development for that application, we—in conjunction with Ameren and Sargent & Lundy—developed detailed cost estimates for the ECO system and compared that to an FGD and SCR installation at the same site. It really was an apples to apples comparison. The cost estimate showed a capital savings of approximately $60 million by installing ECO in lieu of FGD and SCR systems. Operating costs were also less, although not as significantly less as the capital cost. But for a utility to put that into some type of financial return formula, the results would vary by utility. In fact, the result would vary by desk within the utility. That’s a pretty black science. Clearly, we would project the capital savings on a typical unit to be well into the tens of millions of dollars. I think the $60 million number is probably in the right ballpark, or around $100 per kW savings. On operating costs, it really depends on the byproduct markets. You certainly could reduce your operating costs by half, or if byproduct markets were at the less attractive end of the spectrum, operating costs might be 10 to 20 percent less instead of 30, 40 or 50 percent less.

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EL&P: Will you target specific regions for initial commercial rollout of ECO technology?

Alix: We have targeted in the United States what we think are the top 20 generating plant owners that are in the sweet spot of our potential market and we have met with most of them. Many of them have already asked us for preliminary designs and budgetary cost estimates for commercial units. Within the top 20 coal-fired generating companies we have identified which units are likely targets, and we are trying to work with them one-by-one to identify the units and to fit ECO into their compliance plans for 2006 and beyond.

EL&P: When do you anticipate moving beyond demonstration and into widespread commercialization?

Alix: We expect to book orders beginning in early 2004. At that time, the 50 MW unit will have run long enough to provide sufficiently stable data that the risk factor would be largely overcome, and people would be ready to step up and commit. We’re looking at deliveries in 2006 and beyond.

EL&P: Looking ahead, what do you identify as a major environmental issue for U.S. coal-fired plants?

Alix: I think the most obvious one is mercury MACT (maximum achievable control technology). A mercury MACT standard would be very difficult to implement, particularly in the 2007 or 2008 time frame as it has been discussed—both from the technology standpoint and deployment of the available technology, whatever that is, throughout the fleet. I think that is a difficult thing for utilities to get their hands around, and I think they’re aware of that. The second issue is CO2. Should the momentum continue in the direction it is, the United States will likely be forced to take some measures to curb the growth in CO2 that are greater than the measures taken to date. That may mean limits or caps on coal-fired generation, or at least some type of financial tax or penalties associated with CO2 emissions. That’s a tough one because we don’t see any real, economically viable technology for removing and sequestering CO2. When we’ve studied it, we’ve concluded that economically you would burn less coal before you would actually try to capture and sequester CO2. In terms of new coal-fired generation, that uncertainty is a very big one.

Kathleen Davis, associate editor, assisted in researching and interviewing for this article. Please visit and for additional information about these companies.

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