R. Daniel Brdar - Chairman, President and CEO Joseph Mahler - SVP and CFO Lisa Lettieri - VP of IR and Corporation Communications

Sanjay Shrestha - Lazard Capital Markets Pearce Hammond - Simmons & Co. International Walter Nasdeo - Ardour Capital Mark Seigel - Canaccord Adams Pavel Molchanov - Raymond James Rob Stone - Cowen and Company Anthony Reilly - RBC Capital Market Michael Molnar - Goldman Sachs

Welcome to the FuelCell First quarter 2008 earnings results conference call. Today's call is being recorded. At this time I would like to turn the conference over to Ms. Lettieri. Please go ahead, ma'am.

Thank you operator. Good morning everyone and welcome to FuelCell Energy's first quarter results conference call. Delivering remarks today will be R. Daniel Brdar, Chairman and CEO, and Joseph Mahler, Senior Vice President and CFO. Before proceeding with the call, I would like to remind everyone that this call is being recorded and this presentation contains forward-looking statements including the company’s plan and expectations for the continuing development in the virtualization of our fuel cell technology. Listeners are directed to read the company’s cautionary statement on forward-looking information and other risk factors in its filing with the US Securities and Exchange Commission. I would now turn the call over to Dan Brdar R. Daniel Brdar: Thank you, Lisa. Good morning everyone and thank you for joining us today for FuelCell Energy's first quarter conference call. Today, I will begin with an overview of the period followed by a review of our financial performance by our Chief Financial Officer, Joe Mahler. Our $29 million in orders for the period is the single best quarter in the company's history, increasing our product and service backlog to a record $84.7 million. Over the last two years, we laid the groundwork to propel our drive to profitability, penetrating key markets, continuing to bring down our product cost, and expanding our manufacturing capacity. In the first quarter, we signed 9.45 megawatts of new orders, moved our five year stack into production, produced lower cost DFC300 and DFC1500, and doubled our manufacturing run rate to 25 megawatts per year. I will go into more detail on these activities in a few moments, but first we will turn the call over to Joe Mahler for a look at the company's financial performance during the quarter. Joe?

Thank you Dan and good morning everyone. I am pleased to report that the Company's first quarter 2008 financial results improved over the prior year. Total revenues for this first quarter were $15 million, more than twice the $6.8 million reported in the similar period last year. Product sales and revenues doubled to $9.8 million, from $4.9 million, driven by increased orders for megawatt class power plants. Research and development contract revenue totaled $5.3 million, up from $1.9 million last year. Our order volume for the first quarter was strong. We booked $29 million of new product orders in the quarter and increased our backlog to $84.7 million, a 131% increase over the last year’s $36.7 million and a 47% sequential increase over fourth quarter 2007 levels. Our product backlog today stands at 21.6 megawatts, driven by megawatt class orders from customers in South Korea and California. As we look ahead, we expect the Connecticut Project 150, 16.2 megawatt projects to add an estimated $43 million to the backlog. Our product cost to revenue ratio improved 27% on a year-over-year basis coming in at 1.99 for the 2008 first quarter compared to 2.73 in 2007. This resulted from increased sales of megawatt class power plants and reduced unit cost across all product lines. This continues our trend of improving cost. While the year-over-year improved significantly, the cost ratio compared to the fourth quarter was up from 1.57. There are several factors causing this. Increased revenues from higher cost sub megawatt sales came through in the quarter. We recognized revenue on older 250 kilowatts and older 1 megawatt units in the quarter as we transitioned to the megawatt and multi megawatt model, inventory increases to support the growing backlog, inventory increases that are adjusted for fair value. Ramp related costs were an impact as we brought our annual production rate to 25 megawatts and continued planning for further expansion. Service costs compared to the prior quarter were higher due to timing of the replacement cycle for our three-year stacks. In the quarter, we moved our five-year stacks into production. The key driver for reducing the cost ratio continues to be the multi-megawatt and megawatt volume. We see the Korean, Connecticut, and California markets providing this. The first quarter net loss to common shareholders improved to $19.7 million or $0.29 per basic and diluted share from $20 million or $0.38 per basic and diluted share last year. Due to improving product margins we were able to double revenue while reducing net loss. The loss on products sales increased to $1.2 million and was offset by a margin improvement of 800,000 on research and development contracts. Administrative and selling expenses were approximately $400,000 higher due to increased marketing cost. Research and development expenses were lower by $1.4 million over the prior year, as certain development objectives were met in the quarter. Cash used was $15.1 million for the first quarter, in line with our expectations. At January 31, 2008 total cash and investments were $138.6 million. In the quarter, capital expenditures totaled about $1.5 million and depreciation expenses $2.2 million. In summary, 2008 begins with strong quarter growth. Dan? R. Daniel Brdar: Thanks, Joe. As I review the highlights of our first quarter, I want to underscore the progress we've made building on our leadership positioning in key markets, continuing to make gains in our product cost-out program, and continuing to put in place the operational capabilities we need to sustain and expand our growth going forward. Let me discuss each of area separately. First, in market leadership; Asia and California are leading the way to a greener future by demanding new sources of clean, reliable power. Because of their low emissions profile, 24/7 advantages, and affordability on our target markets our direct fuel cell products are highly competitive. Very simply, DFC power plants meet the worldwide need for ultra-clean energy generation. During the first quarter, our partners in South Korea, POSCO power, ordered 4.8 megawatts of DFC power plants, bringing the total orders from POSCO to 12.6 megawatts during the last 12 months. We believe these orders are just the beginning because of the increasing power needs of the Asia-Pacific region, and because POSCO Power is uniquely positioned to help meet that need. Electricity consumption in South Korea and across Asia is booming. During the last 15 years, South Korea's electricity consumption has grown 9% a year, and strong demand is anticipated to continue during the next decade. To meet the demand for power generation equipment, POSCO Power is currently building a balance of plant manufacturing facility. This facility will be completed later this year, with an initial BOP production capacity of 50 megawatts per year growing to 100 megawatts per year by 2010. POSCO Power will order fuel cell modules from FuelCell Energy to integrate with its balance of plant. POSCO is primarily focused on megawatt class sales in South Korea and worked with the Korean government to develop an incentive program that encourages grid support fuel cell applications. To further this enterprise, POSCO Power formed a marketing alliance with KEPCO, South Korea's only utility company. In California, we continue to see increasing demand for our DFC power plants. The renewable biogas market is especially strong. Over half the power plants in our installed base and backlog in California are renewable fuel applications. Similarly, worldwide 25% of our installations in backlog are renewable fuel applications. The Eastern Municipal Water District in Southern California recently ordered three DFC300 units that will operate on the renewable biogas generated by their waste water treatment facility. The Water District expects to reduce its carbon footprint by over 10,000 tons annually, and, because our power plants are of 80% efficient in combined heat and power applications, they'll use less fuel to make the same amount of energy, resulting in meaningful energy savings and emissions reduction for the municipality. Our first quarter sale of 3.9 megawatts of DFC power plants to the Linde Group, the world's largest industrial gas company, is a very interesting new business model for customers using our products. These power plants are run on biogas that Linde transports from where it is produced to the customer’s site where Linde will generate renewable ultra-clean energy using FuelCell energy power plants. This model allows Linde to leverage their existing infrastructure and investment in gas cleanup technology and transportation equipment. More importantly, it also allows end-user customers to have economical onsite renewable power generation, while avoiding fuel price volatility. This unique model is the first time that biogas will be delivered to distribute to outside customers that want power from renewable sources and can lead to greatly expanded markets for us. In the world's move to renewable energy, we are seeing increased use of anaerobic digesters to manage waste by-products, and increasing focus on using the methane produced. We see a large existing market. For example, there are more than 550 municipal waste-water treatment facilities across the United States and hundred's of anaerobic digesters installations worldwide; enough to generate enough methane to power our fuel cells. Looking to the future, we are seeing industry and municipalities take a much more strategic view of these renewable biogas resources, as they incorporate anaerobic digestion into their development and construction plans. Turning to Connecticut, the States Department of Public Utility Control approved 16.2 megawatts of projects under Project 150. These projects will incorporate six of our DFC3000 power plants. By the end of the April, all approved projects are evidence of firm commitments for project financing to the DPUC. Once this is complete, the projects are free to enter into power purchase agreements, equipment supply contracts, and to begin construction. We also received contingent approval for an additional Fuel Cell project, the 19.6 MW Danbury “Triangle” project. We will keep you up to date in these projects as we convert them to orders. The DPC also called for the next 25 MW projects to be under contract by October of this year. Beyond project 150, Connecticut still has another 650 MW of clean energy to get under contract by 2020, as part of the state's renewable portfolio standard mandate. Under the recent bidding, there is considerable debate as to the availability of sufficient biomass fuel and whether wind and solar are viable options for the state. Connecticut is typical of many states in the regions of the world that have limited biomass resources, no meaningful wind resources, and inadequate solar profiles for cost effective solar power. Fuel cells make sense in these markets because they are not dependent upon limited sources of fuel, such as biomass, or intermittent sources for power. We believe that their fuel flexibility, the ability to operate on a variety of renewable and readily available fuels, and base-load operating characteristics will make them a cornerstone of any RPS strategy. The success that we are seeing in Connecticut and South Korea demonstrates that fuel cells can play an increasingly important role in fulfilling RPS mandates. We expect other locations will follow their lead as we demonstrate our products in larger applications. Let's shift now to our cost-out program. As many of you know, we consider it critical to attain grid parity, so we can sell our power plants without subsidies and compete effectively against other sources of power generation. To that end, we substantially reduced our product cost every year since we began shipping our DFC power plants in 2003. Last year, we reduced cost of our DFC300 by 14% and our DFC1500 by 24%. In 2008, we are targeting cost reductions of 20% for our megawatt-class DFC1500 and DFC3000 power plants through a power output increase strategic sourcing and continued manufacturing improvements. Also, our new five-year stack went into production during the quarter, extending the life of the DFC fuel cell's core technology by two years and that as a result reducing the operating cost of our units. A large part of the savings for our next round of cost reduction will come from our next power upgrade of approximately 15%. The full size stack testing was completed in our test facilities last year and we're now operating a unit with the technology improvements at a customer site. We except the new higher power output units will be put into production in the middle of next year. Improvements like these, along with increased volume that we're already seeing, will move us to profitability at a production rate of 35 to 50 megawatts per year. We expect to become gross margins positive, and at a production of 75 to 100 megawatts per year, we should be cash positive. The exact level depends on the product mix running to the factory, but the more megawatt class products in the mix, the lower the run rate needed. As our recent orders growth demonstrates, there is ample evidence that the market for megawatt class solutions is growing. It is with our megawatt and multi-megawatt systems where we can capitalize on manufacturing and sourcing economies of scale to produce our lowest cost per kilowatt products in our best margins. This is good place to address the operational capabilities FuelCell Energy needs to sustain growth. In January, we brought our manufacturing production rate to 25 megawatts per year, more than doubling our previous run rate to meet demand from South Korea and California. With 22 megawatts of backlog, we're well matched to current demand. As additional orders from South Korea, California, and Canada are added to backlog we will also need to further ramp up our production. In preparation for continued growth, we are increasing our equipment and production capacity to 60 megawatts annually from 50 megawatts to better meet demand from megawatts class products. This includes adding additional final assembly, test, and conditioning capabilities, as well as manufacturing equipment and process improvement. Beyond this modest capacity increase, we've completed ramp planning for the operations enhancements required to successfully ramp the business to 60 megawatts, 120 megawatts, and then to 240 megawatts. So, we are ready as demand wants. This planning includes a detailed supply chain evaluation incorporating new vendor qualifications and global sourcing. We are also planning facility layouts, equipment additions, and optimal manufacturing process configurations for the business as we reach these higher production volumes. Before I open the call to take your questions, let me give you a quick update on the legislative environment for energy. Nationwide, the significant momentum for renewable and ultra-clean sources of power shows little signs of slowing down. The number of US states with renewable portfolio standards continues to increase. As of the latest count, there are now 28 states, plus the District of Columbia, which significantly expands our addressable market. The renewable energy and energy conservation tax act of 2008 is back in the spotlight. We are watching this progress closely because it extends the investment tax credit for fuel installations till 2016 and increases the incentive to $3000 per kilowatt. This bill is the same that was passed by the House last year but failed to pass in a close vote in the Senate. With energy prices at record levels, and increasing pressure to produce greenhouse gases, we are cautiously optimistic that the House and Senate will see the need to continue to invest in clean energy. At this point operator, please open up the line, so we can take questions from our listeners.

Thank you sir. The question-and-answer session will be conducted electronically. (Operator instructions) And our first question comes from Sanjay Shrestha with Lazard Capital Markets. Sanjay Shrestha - Lazard Capital Markets: Great. Good morning, guys. First of all, congratulations here on a good backlog front and the outlook. Couple of quick questions, first can you remind us in terms of the timeline that would be required for you guys to go from 60, 120 to 240 megawatt and the CapEx required for that? R. Daniel Brdar: On 60 -- to get to 60 we have $14 million that we're going to spend this year to have that capacity in place. To ramp to 60 is really a matter of bringing people on board at that point. So, with the design work already in process, equipment already under procurement, we could actually be at 60 megawatts by late summer. To go from 60 megawatts to 120, takes $30 million to $35 million in capital, and will take us about 18 months from the time we pull that trigger to actually have that equipment in place, operational, and then people on board to operate it. Sanjay Shrestha - Lazard Capital Markets: Okay, terrific. And, also then, another question: one more on the backlog. Obviously, you guys have done a great job from this cost-out program, it's getting better every year, year-over-year. And, as the increasing mix of megawatt class product in this backlog, if you were to look at cost of product ratio in your existing backlog right now, what would that look like?

Yeah. Sanjay, this is Joe Mahler. Sanjay Shrestha - Lazard Capital Markets: Joe, how are you?

In the backlog right now, we have about 4 megawatts of sub-megawatt, and we have about 10 megawatts of 1 megawatt, and it's about 7 megawatts of 2 megawatt plant. The backlog, we still have some older units coming through. So, in effect, the sub-megawatt would be somewhere in the high one, approaching two, maybe slightly higher, the megawatt plants were about probably 1.5 range. Sanjay Shrestha - Lazard Capital Markets: Okay.

We range around it, and the megawatt should be -- at this point we really haven't either -- we've all anticipating the Connecticut orders coming through; we're anticipating multi-megawatts activity out of the Koreans and we haven't been able to really launch that. It is coming, and so we are trialing on that, but the megawatts as we talked, the cost is around $3200 a kilowatt, should be in a 1:1 to 1:0.1 the point one kind of range in '08. Sanjay Shrestha - Lazard Capital Markets: Got it. Now, we are finally at the point where as more and more of this multi-megawatt class product comes in, with the increasing revenue, you would also start to get the benefit of the decreasing cash?

That’s the model, sometimes it takes a little slower than we'd like, but that is clearly the model and certainly the 15 megawatts out at Connecticut will fill that model. Sanjay Shrestha - Lazard Capital Markets: Exactly. One last question, then guys, as it relates to the backlog, how should we think about, how is the backlog going to hit the P&L and how should we think about that?

In timing? Sanjay Shrestha - Lazard Capital Markets: Timing, yes.

I mean in that we are actually at 25 megawatt run rate and we have 21.6 megawatts in backlog, it should take less than a year. Sanjay Shrestha - Lazard Capital Markets: Perfect. That’s terrific. I'll hop back in the queue. Thank you.

Our next question comes from Pearce Hammond with Simmons & Co. International. Pearce Hammond - Simmons & Co. International: Thank you. Good morning. R. Daniel Brdar: Hi Pearce. Pearce Hammond - Simmons & Co. International: Joe, the guidance for '08 for product cost of revenue ratio, could you provide any color for the full calendar year, I mean for the full fiscal year?

I don’t think - we haven't really done that task, Pearce, it's really a function of coming off where we are driving to this multi-megawatt model. The real driver to getting costs out is putting the two megawatt to multi-megawatts in as well as more megawatt plants, the newer megawatt design. The newer megawatt design probably comes in the third quarter, so getting those into the production plant really starts to drive this thing into that. That multi-megawatt plant should be at that 1:1, 1:1.1 ratio, and the 1 megawatt plants will be a little bit higher than that and that's really what we are driving to. In the meantime, we are transitioning the older inventory out, the older units out, and it's just going to -- it will come to that model pretty quickly once you put those new orders in. Pearce Hammond - Simmons & Co. International: Okay. And, then a follow-up on Sanjay's question; so would you expect over the course of the next 12 months to realize that backlog?

Yes, I mean we now have -- we are in pretty good shape and we have 21.6 in backlog. At this point, we really believe we are going to get the 16.2 out of Connecticut. So, you really have a 38 megawatts backlog. So, there is no reason to be holding back or anything. We got a 25 megawatt run rate, it is full bore and so we expect to be pushing that out. Pearce Hammond - Simmons & Co. International: And when would you expect the Connecticut order to actually hit the backlog?

We'd hope, I mean the technical period is the 90 day period from January 23rd. So, you are talking about having absolute go-ahead around April, if I'd say April, end of April-May is when we would expect that to hit. Pearce Hammond - Simmons & Co. International: Sure, and then one final question. When the POSCO plant is up and running, how should we model the sales, how should we think about that?

I think what you'll see from us is evidence of course. Pearce Hammond - Simmons & Co. International: Right, but from what sort of revenue would you receive, you are obviously just selling the stacks at that point. Would that ratio be obviously a positive ratio for the stacks that you would be selling, a positive gross margin on those stacks?

The answer to that is that our initial thinking would be that whether or not it was a stack or a full power plant, that the same cost ratio impact should be achieved, which means that as we push, I think we have been saying as we push volume of the multi-megawatt through our facilities then, we should start to. So, for example I think we've talked in the past about a full power plant costs $3250. As we push volumes through we should be able to get that number below $3000. On these stacks, we would expect at this point the same results. Pearce Hammond - Simmons & Co. International: Okay. So, just think about it in the same way, just obviously.

It’s not 100% of the total cost, but the module -- that relationship should be pretty similar. Pearce Hammond - Simmons & Co. International: Should it have a better margin profile because you're just essentially selling the stacks?

It can, but what our initial thinking is, is that we are high -- we are still driving our cost down. Okay, to achieve that, I mean we are right on target in terms of if you have an incremental margin opportunity, because it's our proprietary technology, we're the only people in the world making it. But, we're still in that transition, that we still have $3200 going to $3,000 stacks, I'm not sure you'll accomplish that in the first bulk order process, but I think that model opens up as you start to get your cost down further, I think that model, that differential will occur. Pearce Hammond - Simmons & Co. International: Okay. Great thank you so much, guys.

And we'll move on to our next question with Walter Nasdeo with Ardour Capital Walter Nasdeo - Ardour Capital: Thank you. Good morning. R. Daniel Brdar: Good morning, Walter. Walter Nasdeo - Ardour Capital: I just want to follow-up a little bit on some of the stuff that's already been thrown around by the previous call and kind of going back to the Connecticut order. What's the effect of the reduced order on your cost out program and the velocity of that? R. Daniel Brdar: Yeah, it's really pretty straightforward; getting 16 megawatts is really what we want, and what we have is a series of triggers. What we're looking to do at this point in time is to expand the capacity and get this model, get more capacity, and get more volume through the facility to get the cost out faster. With the Connecticut order, what we were looking for originally was to use, say, at 35 megawatt order, which is still potentially there if we can pull off the triangle and use that as a potential trigger to expand capacity, move to 32 megawatts of production, move to 45 megawatts production. And, then, that combined with the Korean orders there we would expect as we build their facility there, we trigger the capacity expansion. I think it delays, it slows it, I think we're still making very good progress on cost out, I think we have the continued design changes, design work we are doing to reduce costs, but I think it doesn't allow us to, at this point, expand our capacity to capture all of the volume cost out. So, I think, yes you're going to see improvement, I think we are on the right track, I think you’ll see these megawatts plants, multi-megawatt models, start to kick in once the Korean and the Connecticut process move solid and I think we will be right there. Walter Nasdeo - Ardour Capital: Okay. Now other than Korea, California, and Connecticut where are you looking at to see other significant orders coming from? We haven’t really seen much out of Germany lately. Is there anything going on there? R. Daniel Brdar: Yeah. We actually have been working joint partner over there, now that they have come through this, the sale of their parent company. I should be meeting with them again next week and the focus really is for us to collectively figure out, how do we do more in Europe more quickly because if you look at the level of orders that we've gotten from Asia, from California, and now from the North East, it's significantly higher than Europe. And Europe is the market that we believe should be producing significantly more. So, we are continuing to work with the senior management of our partner over there, to figure how we accelerate that process for Europe. Walter Nasdeo - Ardour Capital: Right. And, then obviously I can't stop my question without asking you how the turbine fuel cell hybrid is coming?

Actually, we've got the unit that we had put at the customer’s site; we brought it back to do some modifications to it, because we intend to send it over to a location in Asia. There are some controls that we need to revise and some configuration changes we need to make to have the unit meet some of the codes in Asia. We hope to be able to have that thing under an agreement here in the next couple of months, then ship it off to site where the efficiency actually makes a pretty important impact in what we're trying to do in the market. So, hopefully we'll have an announcement here coming forward about where it's going to be going. Walter Nasdeo - Ardour Capital: Very good. Thank you. And Dan, did you say it's going to take between $15 million and $30 million to go from 60 to 120 megawatts, $15 million to $30 million? R. Daniel Brdar: No, it's $30 million to $35 million to go from 60 to 120. Walter Nasdeo - Ardour Capital: Okay, thank you.

And we'll take our next question from Mark Seigel with Canaccord Adams. Mark Seigel - Canaccord Adams: Hi, good morning guys, just a couple of questions. First, regarding POSCO, do you see them as continuing this pace of order-flow ahead of their balance of plant facility coming online? Is there anymore sort of preordering to be done there? R. Daniel Brdar: Based on what we were seeing from them and discussions we have with them recently, it looks like they are about to shift to module orders. We'll probably see maybe another order out of them, where they buy components to assemble one of our designs themselves. But, it looks like they are ready to start to make that transition to order just modules. Mark Seigel - Canaccord Adams: Okay, great. And then on the cost-out program, are you guys seeing any inflationary head winds there, I guess, whether it's in metals or any other materials? R. Daniel Brdar: We actually already have seen it. If you look at what happened with nickel and stainless steel, they all peaked last year. We've seen those prices soften now, particularly nickel has softened considerably. So, we have continued to drive the cost down despite the pretty significant spike that happened, particularly in the nickel side. And, fortunately, we have a product that's pretty early in its lifecycle. So, there is still a lot of ability to offset those commodity price increases. Mark Seigel - Canaccord Adams: Okay, great. And then, lastly, do you guys have plans to bid into around three-year Project 150? R. Daniel Brdar: We are working on that right now. We are going to participate and we are figuring out what projects we want to put in, we'll probably see some of the projects did not get selected in this last round, but we are also looking at what some new and created projects will look like as well. Mark Seigel - Canaccord Adams: Okay. And will those be bid for the full 25 megawatts that are outstanding or something less? R. Daniel Brdar: I suspected the 25, because it’s not a big number, is going to be, probably significant over subscribed in terms of what totals go in from a bidding standpoint. Mark Seigel - Canaccord Adams: Okay, great. Thanks a lot.

And moving on to our next question from Pavel Molchanov with Raymond James; please go ahead. Pavel Molchanov - Raymond James: Hey, good morning guys. I wanted to get an update on your Enbridge opportunities, we haven't really heard about that recently; any update on that? R. Daniel Brdar: Sure. The Enbridge unit that is going to go into Toronto, which will be the first FuelCell turboexpander combination, is under construction now. The turboexpander is in, they're finishing up some of the side work, and the unit that we are going to install in FuelCell side is being built. It's ready to be installed. They have to get through some last permitting issues they are dealing with up in Toronto. We expect the FuelCell turboexpander to be operational this summer. And, then Enbridge is also a participant in the 9 megawatt project that was selected in Project 150 for the Milford side. So, that will be the first multi-megawatt installation we will see in the US, and the discussions with that project in terms of the participants are pretty far along. So, it’s really getting through to middle of evidence of financing in April and that project will be able to start moving forward and get under construction. So, getting those two installed and operational are pretty important. I think gas companies want to see units operate, but, in the meantime, we're seeing Enbridge work with our guys to identify other sites here in the US. So, we think it would be a good application both in the Northeast and in California. Pavel Molchanov - Raymond James: Got it, thanks very much. R. Daniel Brdar: You're welcome.

We'll take our next question from Rob Stone with Cowen and Company. Rob Stone - Cowen and Company: Hi, guys. A couple of questions if I may; first, the biogas opportunity sounds particularly intriguing. Could you answer me, you mentioned the number of municipal waste facilities around the country, could you answer me how many megawatts of installations that number of sites might ultimately support?

Yeah, it is, I don't think you can get off 550 of those sites. I'd say there are probably 200 to 600 megawatts and then kind of a play. R. Daniel Brdar: What's interesting that we are seeing in California is, we always thought that the targets for us were going to be places where they were either flare in the gas or potentially burning in a boiler. But, with some of the California solutions once you start to see engines get replaced with fuel cells. So, we think there is also an opportunity as part of this natural equipment replacement cycle of these Wastewater Treatment facilities. And, then what's turning out to be also a pretty big market for us that we are really just starting to get our arms around is, not just Wastewater Treatment, but the food and beverage processing. If you think about what we did at sewage and breweries, the Gills Onions orders, and what we did with Kirin Brewery in Japan. It's turning out that food and beverage processing companies are increasingly turning to those anaerobic digesters because they are trying to find better ways to deal with the waste that comes from preparing prepackaged foods and as they installed digesters, it turns out it produces a great fuel for the fuel cell. So, I think we are going to see more of the food and beverage application as well.

Plus, the other thing to add is that, that number that we talked about at the beginning is really a mini wastewater, which is a one slice of the market. If you are going to look at the Asian-Japanese market, the Japanese market is over 2000 megawatts. They have been very focused on anaerobic digestion. So, United States is really just catching up in terms of new construction and new strategy at using this waste stream to produce -- and in fact renewable solids and fertilizers plus this renewable biogas that comes off the backend. So we think this is actually going to be significantly growing markets. Rob Stone - Cowen and Company: What percent of the sites do you estimate are just layering the gap at this time? R. Daniel Brdar: We've been having a tough time getting good data on that. There are quite a few that flare up but we are finding of that most of them are using it some capacity, most of them are typically putting in a boiler to generate steam and we're finding that particularly in places like California they are getting a lot of pressure to stop doing that because of the pollution that increase, if you just burn it. So I think it's more going to be function of what shifts from being burnt in a boiler and turn into power generation use, particularly using fuel cells. Rob Stone - Cowen and Company: Okay. A related question with respect to the Linde opportunity at delivering biogas besides beyond the waste water or other treatment facility, how does that call us of delivered biogas in that kind of a set up, compared to natural gas and is it a straight forward economic trade or sites like that counting on some additional credits because they are using a renewable source. R. Daniel Brdar: Now most of the installations that Linde is looking at or what they are looking to do is to go into the site and they’ve identified in part of their own business model, how far they can economically effort to transport the gas. And they want to go in and basically be able to make a pitch to a customer that they can save money versus what they are paying there are electricity utilities. So it's really an economic play is what they are trying to offer to the end user customers. And the end user customer also gets the benefit of being able to say that they are now generating their own power using a green resource.

And the other interesting -- the very other very interesting aspect of that of the Linde business model is that they in effect they're producing a gas. It's the cost of the clean up and the transportation less then what the commodity cost in the market place. But what you eliminate over a 10 year contract is the commodity risk. So if you were comparing yourself to natural gas, there is really no natural gas commodity risk that comes into play because you know what the cost of producing the gas and transporting the gas is. You may have some inflationary factors but you certainly don't have a commodity play on it. So it is actually a very interesting model. Rob Stone - Cowen and Company: Yeah. that’s that caught my attention because of the risk of natural gas as you feel first going higher in the future. Final question, more-more of a financial one. How much does the switch to a 5-year stack impact the life cost of electricity for the customer over the life of the system? R. Daniel Brdar: On the customer-end they are not going to see much difference because what we were really doing in most cases is putting in place a 5-year service agreement. So for us it's an opportunity to improve what the margins look like on our service business. What we've done with the service agreements is really to make sure the end-user customer doesn’t take any kind of technology risk by adopting fuel cells. There was really a chance for us to continue to improve what our own economics look like on the service business. Rob Stone - Cowen and Company: Okay. So putting it that way, how much of a difference percentage wise. Is it, is it a simple sort of [5, 1, 3] ratio or…? R. Daniel Brdar: It's pretty close to it because the biggest factor in our operating maintenance cost is that stack replacement. So if you go to 5 years from 3 year, you get a pretty close to a corresponding improvement in terms of what you see on the service margins. Rob Stone - Cowen and Company: Great. Thanks very much. R. Daniel Brdar: You are welcome.

(Operator instructions). And we'll take our next question from Anthony Reilly with RBC Capital Market. Anthony Reilly - RBC Capital Market: Hi. Good morning. R. Daniel Brdar: Good morning. Anthony Reilly - RBC Capital Market: Question on your balance sheet. You have $81.9 million in cash and cash equivalent. Can you kind of breakout what that's actually invested in, in light of, we've seen some of these options rates, in the city market kind of implode recently, do you guys have any exposure to that? R. Daniel Brdar: No. Our policy is extremely conservative. It's basically the money markets that invest in US treasuries or US treasuries our investment policy is absolutely backed by the United States government at this point. So, we actually have the $81 in cash and the $54 in investments in the short-term category, and then, you have the investments US treasury long-term is all in those types of instruments. Anthony Riley - RBC Capital Markets: Okay. Thanks for clarifying that. R. Daniel Brdar: Yeah. Anthony Riley - RBC Capital Markets: Second quick question, OpEx, can you kind of talk about how you see that trending for the rest of the year if you could? R. Daniel Brdar: CapEx? Anthony Riley - RBC Capital Markets: OpEx, operating expenses. R. Daniel Brdar: Operating expenses, in effect, so are you talking about specific categories of OpEx or the total -- you're talking below the margin line or… Anthony Riley - RBC Capital Markets: No, just basic SG&A stuff like that, how should when combined that remaining. R. Daniel Brdar: SG&A is, we don't -- from ramping the business we don't see that has an impact or a significant impact. We've been incrementally adding some selling into our numbers as we are getting more and more opportunities to sell product, we need to be able to respond to that. We have little bit there, but nothing really significant there. Our R&D costs will actually come up. We're actually in this quarter transitioning from completion of some major projects that we've accomplished in the fourth quarter to our and then transitioning to our 2008 objectives, which the major one is the power output increase. So, we would expect that, that number would increase over the 5 point, that more inline with where it was in the previous quarters. Anthony Riley - RBC Capital Markets: Okay. Thank you. R. Daniel Brdar: Yeah.

And our next question comes from Michael Molnar with Goldman Sachs. Michael Molnar - Goldman Sachs: Hi, good morning every one. R. Daniel Brdar: Good morning. Michael Molnar - Goldman Sachs: If I can just ask you some questions on some of the rough numbers a few years out, and I fully understand it's hard to know where that might go. But let say, get to a run rate of about a 150 megawatts at some point, however, many years out. There is a lot of uncertainty in terms of product mix etcetera. But if we would assume an ASP of 2500 hours of kilowatt and getting down to a cost of 1800 hours of kilowatt, is that makes sense in very rough comps or with that be way off base?

No. I think you're right. I think we would expect 20% or better margins with that kind of volume. We would expect the product mix to actually stabilize at that point into the multi-megawatt and megawatt. Most of that would be coming through the system. As we push volume through the system we don't see a significant difference in costs between, what it really now is down to it, there is a difference in the costs between the multi-megawatt is really the fixed costs differential in the balance of plan. On the two megawatt plant you're running more power to achieve, you really get a fairly, probably a 10%, maybe a 10% -- probably a 5% to 10% differential in the costs of that. So, those should both be very opportunistic from a margin standpoint. I don't see it is way out of whack. Michael Molnar - Goldman Sachs: Okay. And just one other question on this topic -- from some of the slides, the costs, your current costs are trending down to sort of 3,500 or 4,000 a kilowatt. Does that imply that your ASP is roughly around $2,000 a kilowatt, is that the kind of right thinking?

No. our ASP should be -- I think it is fairly public information. It is around $3000 a kilowatt. Certainly the Connecticut project is $3000 a kilowatt. So it's more like $3000 a kilowatt is where we are at. Michael Molnar - Goldman Sachs: Okay. Perfect. Thank you very much.

There are no further questions at this time. I would like to turn the conference back over to our speakers for any additional or closing remarks. R. Daniel Brdar: I’d just like to thank everybody for participating in this morning's conference call and we look forward to speaking with you in next quarter as we continue to update on our progress. Thank you everyone.

And that concludes today's teleconference. Thank you for your participation. Have a good day.