燃料電池能源 (FCEL) 2005 Q3 法說會逐字稿

At this time I would like to welcome everyone to the third-quarter earnings and company update conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be question-and-answer period. (OPERATOR INSTRUCTIONS) I would now like to turn the call over to Mr. Eschbach, Director of Investor Relations. Thank you, Mr. Eschbach, you may begin your conference.

Good morning. This is Steve Eschbach, Director of Investor Relations at FuelCell Energy. On behalf of the executive management team here at FuelCell, I would like to welcome you to our third-quarter 2005 conference call. Delivering formal remarks today are Jerry Leitman, CEO, and Joe Mahler, Chief Financial Officer.

Before proceeding I will read the following Safe Harbor disclosure statement. This presentation contains forward-looking statements including statements regarding the Company's plans and expectations of development and commercialization of its fuel cell technology. Listeners are directed to read the Company's cautionary statement on forward-looking information and other risk factors in its filings with the Securities and Exchange Commission. I would now like to turn the call over to Mr. Jerry Leitman.

Good morning. Thanks, Steve. I also would like to welcome everyone to the call. Let me first turn to Joe Mahler to review the financial results. Joe?

Thanks, Jerry, and good morning, everyone. FuelCell Energy reported a net loss to common shareholders for the third quarter of fiscal 2005 of 18.6 million or $0.38 per basic and diluted share, compared to 19.2 million or $0.40 per basic and diluted share in the same period of the previous year. Cash, cash equivalents, and investments as of July 31 totaled approximately 192 million.

Cash used in the quarter was approximately 20.5 million and included approximately 3.4 million for plants being built for power purchase agreements, and cash dividends of approximately 1.5 million on convertible preferred stock. Our cash use during the quarter before PPAs and preferred dividends was about 15.6 million, within the range that we have discussed in previous conference calls.

FuelCell Energy's consolidated revenue for the third quarter of fiscal 2005 was 8.7 million, compared to 8.1 million for the third quarter of fiscal 2004. FuelCell product sales and revenue increased in the quarter to 4.9 million for the third quarter of fiscal 2005, compared to 3.6 million in the same period of a year ago. Product sales and revenue included sales to Marubeni, Caterpillar, LOGANEnergy, and MTU. Our product backlog at July 31 totaled approximately 23.3 million, compared to 25 million on the same date a year ago.

Cost of product sales and revenues were 13.8 million and 9.7 million in the quarters ended July 31, 2005 and 2004, respectively. The ratio of cost to product sales and revenue in third-quarter '05 was 2.8 to 1, versus 2.7 to 1 for the same period a year ago. Both periods included PPA activity.

R&D revenue for the quarter was 3.9 million versus 4.4 million for the same period a year ago, and we are lower with the completion of the PDI contract and Bath Iron Works contract. Revenue for the quarter was primarily related to the DOE's SSECA program and combined cycle DFC/T development under the DOE's Vision 21 program. As of July 31, 2005, our research and development sales backlog totaled approximately 19.2 million of which Congress has authorized funding of 15.1 million, compared to 19.5 million, 13.5 million funded as of July 31, 2004.

Research and development contract costs were 3.7 million for the third quarter of '05, compared to 7.4 million in the same period last year. The improvement in the cost of sales ratio from 1.7 to 0.95 and lower total cost is attributable to the completion of the King County and Clean Coal megawatt projects, which had significant cost share obligations.

Admin and selling expenses for the three months were 600,000 higher than the same period of the prior year, primarily related to higher proposal activity for projects and higher costs related to Sarbanes-Oxley compliance. Internal R&D expenses for the third quarter of 2005 were 5.7 million compared to 6.7 million for the same period of the prior year. This was due primarily to the reduction of Canadian SOFC expenses, partially offset by higher DFC product development costs for MA and megawatt class powerplant.

Loss from equity investments was 0.5 million for the quarter and is attributable to the Company's 42% ownership interest in Versa. The increase in interest and other income to 2 million is due to higher yields on higher cash and investment balances than the prior year and approximately 0.5 million of state research and development tax credits.

For the nine months ended July 31, FuelCell Energy reported a total loss to common shareholders of 54.7 million or $1.14 per basic and diluted share, against a net loss of 66.4 million or $1.39 per basic and diluted share for the prior year. This is due primarily to reduced Canadian operations.

Cost of sales ratios improved for both commercial products and government R&D in the year-over-year nine-month comparison. Commercial products moving from 3.5 to 1 for the nine months ended 7/31 to 2.9 to 1 for the nine months, showing positive results of cost-out programs. We continue to target our core products' quarterly cash consumption at the approximate $15 million target. PPAs that we finance ourselves will add to this quarterly consumption. Multimegawatt RPS projects and the investment tax credit for fuel cells are generating significant interest for project financing and third-party financial institutions.

With over 190 million in cash, cash equivalents, and investments, our financial footing remains strong to execute our strategy. I will now turn this call back to Jerry.

Thanks, Joe. My remarks will focus on recent developments that we believe will increase sales of our Ultra-Clean Direct FuelCell powerplants and on progress in executing our business strategy. The Energy Policy Act of 2005 was signed into law earlier this month, and for the first time ever we now have a federal financial incentive -- 30% investment tax credit, up to $1 million per megawatt -- that we believe will stimulate the sales of our DFC powerplants.

The purpose of the law is to encourage end-users to purchase ultra-clean distributed generation. Fuel cells can provide firm 24/7 power, and this Bill establishes a level playing field for funding with the intermittent sources such as wind and solar. I might add that we set a very high target for ourselves in our efforts in Washington, by trying to persuade Congress to pass a production tax credit in addition to the investment tax credit. While we would have loved to get both, the ITC is significantly better for us, as it provides an upfront monetary benefit based on purchase price of the equipment, as compared to a per kilowatt-hour offset based on energy delivery.

We believe this tax credit will increase the sales of our products as it takes effect. Less than a month since its passage, we have seen increased interest by our distribution partners, by prospective customers, along with increased interest in project financing for large-scale projects by third-party financing companies. We are analyzing the ITC language and how it will be eventually included in the tax code to better understand how the financial benefits will apply.

In addition, the Act includes authorizations of approximately $4 billion over the next five years for R&D and demonstrations around fuel cell and hydrogen initiatives. While these still require presidential budgeting and appropriations by Congress, these authorizations do point to an increasing political commitment to fuel cells.

We are seeing near-term opportunities based on Renewable Portfolio Standards. Currently 19 states are establishing RPS to mandate that utilities provide a certain amount of their electricity from clean energy sources such as fuel cells, solar, and wind. Over time we see this as a very significant opportunity, with a Primen/EPRI study estimating more than 10,000 megawatts potential by 2010 in the six states that qualify fuel cells on natural gas -- California, New York, Connecticut, Maine, Pennsylvania, and Hawaii. Two states, New York and Connecticut, have issued Requests For Proposals, and we have responded with bids for 14 megawatts of fuel cell projects through August. We expect the Long Island Power Authority to have its decision by the end of September and Connecticut to identify finalists later in 2005.

The opportunity in Connecticut improved as legislation was passed in June that modifies the 2004 RPS bill to allow for the pass-through of fuel cost, which removes the fuel price risk from the developers. Because of this we have accelerated proposal development for larger projects, when Project 100 commences Phase II in January of '06 and Phase III towards the middle of '06. Between New York and Connecticut we see a near-term opportunity for 30 to 40 megawatts of our megawatt class powerplants.

While Connecticut's Project 100 is only focused on 100 megawatts, it is significant because this legislation sets a viable plan that is economically feasible for developers to install multimegawatt Direct FuelCell power plants to meet RPS goals. We believe that if this program is successful, other states will follow this template. Recall that in November of last year, New York announced its RPS goal of 3,700 megawatts of power generation by 2013 from renewable technologies, such as our products. A program like Connecticut's Project 100 could be the model for New York and others to adopt to achieve their RPS mandates.

We believe these RPS developments in Connecticut and New York provide us with a near-term opportunity that exceeds our successes to date in California and Asia. Since the 2003 introduction of our commercial DFC products with the Los Angeles Department of Water and Power units in California and the Kirin Brewery unit in Japan, installations and repeat orders have resulted in 5.25 megawatts and 8.25 megawatts of our product in California and Asia, respectively.

Further, in California we have seen a solid move to megawatt class plants that we expect to also see in Asia in the near future. This is because of strong government financial support in both regions for ultra-clean power. The main driver in California is the self-generation incentive programs that provide subsidies up to $4,500 per kilowatt for our fuel cells on wastewater treatment gas, and $2,500 per kilowatt on natural gas, as well as the CARB 2007 emission limits on power generating equipment. Our DFC powerplants are the largest distributed generation technology that is certified to meet these strict air emission requirements.

In Japan, the main driver is the Kyoto Protocols. Our DFC products are the distributed generation technology with the highest electrical efficiency in its size range and, as a result, affords excellent opportunities to reduce carbon emissions and operating expenses. Top class industrial companies are motivated to install ultra-clean and highly efficient on-site generation in compliance with the Kyoto Protocols. In addition, Japan has a strong ministry incentive for wastewater treatment plants. We see this trend emerging in Korea as well, and we expect overall Asian sales to increase.

Enbridge and FuelCell Energy introduced the DFC-ERG, a new ultra-clean megawatt-class hybrid product specifically designed for the natural gas pipeline market. This combined-cycle generation system that matches our DFC powerplant and an expansion gas turbine, using the waste heat from the fuel cell in lieu of a gas-fired boiler to prevent freezing of the gas during pressure letdown, will achieve an electrical efficiency of 60% or better. Natural gas pressure letdown stations are typically found in large urban centers where the demand for clean and reliable power is needed to resolve air pollution and grid congestion issues. We estimate the near-term potential for this new application in California, the northeastern U.S., and Ontario, Canada, to be greater than 250 megawatts.

We continue to demonstrate the diversity of our products with the Air Products subcontract for a Next Generation Hydrogen Energy Station. The HES is designed to generate electricity for baseload power and heat, as well as hydrogen for vehicle refueling or other industrial applications. Depending on the size of the fuel cell powered vehicles, each 250 kilowatt Hydrogen Energy Station can support a fleet of up to 400 cars. This tri-generation product can provide an overall energy efficiency of 80% to 85%. The logical near-term market for this application is in support of the hydrogen highway initiative in California.

Our DFC products continue to meet customer expectations. We now have generated over 78 million kilowatt hours of electricity at customer sites, with fleet availability now approximately 90%. We expect that will continue to move toward our target of 95%. Performance improvements continue to come from the increasing operating experience from our PL-fala (ph) unit to customer sites.

Contributing to better availability are design and manufacturing changes to improve ceramic seals within the fuel cell stack; new components to improve fuel control valves and heat transfer; retrofitting gasket seals for improved recycle buller (ph) performance; and process enhancements to reduce software errors. In addition the establishment of our 24/7 call center and regional service teams has significantly reduced the time between system disturbance notification and problem resolution.

Our rolling three-year cost-out program continues on course and meeting its targets. We are on target for a further 20% to 25% cost reduction for our sub-megawatt product by the end of this calendar year. While the initial focus has been on sub-megawatt product, as this represents the largest part of our fleet at customer sites, all cost-out initiatives translate directly to our megawatt products. Once we verify the cost-out initiative on our sub-megawatt product, we extend these initiatives to the megawatt product.

Our product cost reductions have and will continue to come from five key areas -- value engineering of the module and balance of plants; sourcing and supply chain management; process improvements relating to manufacturing and service; and technology enhancements including stack life, power output, and efficiency.

BOP testing and verification of our new DFC300MA product has been completed with successful results; and this new sub-megawatt design has been released for production and customer shipment. Ongoing testing is being performed for product certifications through CSA International and stringent air emission standards for CARB 2007 in California.

In summary, I am pleased with the progress we are making in executing our business strategy. The drivers of the investment tax credit and renewable portfolio standards in the U.S., and Kyoto Protocols overseas, as well as the new DFC-ERG product for pipelines and the increased focus on megawatt and multimegawatt plants increase the market opportunities for our products. Now, Lisa, if we could, let's open it up for any questions the audience may have.

(OPERATOR INSTRUCTIONS) Jarett Carson of RBC.

Could you talk a little bit about on the operating availability? I just saw some very good numbers there. You were close to or right around 90% for the fleet. Can you talk a little bit about new units, kind of overall? Like what really they're coming out at, and your goal being 95. Then contrast that to maybe one or two years ago, trying to give us some understanding of the clear, I think, progress that you made there; and what with that actually means in the marketplace.

I think the best way to describe it, we are right at 90% now. I have forgotten the numbers in the previous quarters, but we slice and dice it every which way -- the data on the units. We know what Japan does versus Korea versus California; wastewater versus hotels; etc. But we obviously don't publish that data.

But I think you can look at it as somewhat like a batting average in baseball. The more units you get out and the more operating hours you have, the more difficult it is to keep raising that number. On the other side of the coin, what makes it easier is the more operating experience you get -- our 24/7 call center teams out in the field, when we fix a problem on one unit, we then go fix it on all 40 units we have in the field. So we prevent that problem from occurring again.

We would expect to move -- and by the way this is not a lot different from legacy products from people like Cat or GE. They follow the same kind of tracking. We obviously measure this very closely with Cat. But we were initially probably in the high 70s on the first few units that we shipped out in '03. But the progress has been good. It just gets slower as you get more units out in the field.

Okay. Can you talk a little bit about the tax credit now? We have got the Energy Bill passed. It has had maybe a month or so of that. And maybe how that relates to that, plus the Connecticut legislation, and I guess just some general color around activity that is going on, particularly in that area; and what that might mean in terms of size of large-scale projects and so forth.

Every one of our distribution partners in the U.S. and Canada are interested now because the ITC is another million dollars a megawatt. It is like $1 million megawatt cost reduction, up to 30% of project cost. So every one of our partners is looking at it.

We also have project finance on some upcoming projects that passage of the Energy Act caused them to call back up and say the numbers started looking attractive to them. We also have people coming out of the woodwork, obviously, to see how to monetize those ITCs. Some of our strategic PPAs that we have done could be converted from PPAs to equipment sales, depending on how the ITC is eventually written in the tax code. So, Joe, you got anything to add to that?

I think we have seen some strong activity. It clearly puts some money on the table. The distributors and the project financing worlds are all analyzing that. We've had some real significant, in the last 30 days, a lot of activity in that area.

As far as Connecticut is concerned, there were a couple of things that were a problem with the RPS standards that were passed in '04. That was then modified in the June legislative session. One was that the original legislation included fuel cost; and with the volatility of natural gas prices today that became problematic for some of our project developer partners.

They also had, as a matter-of-fact, that we didn't notice much at the time, was that all renewable emissions credits, investment tax credits and all, go to the state. That has been now changed, so that the investment tax credit on a RPS project in Connecticut remains with the developer, not goes to the state; as well as one-half of the renewable emissions credit. So Connecticut fixed the legislation in a very, very, attractive way that has brought in quite a few project developers going after the Phase II, which is January's to middle. Some are even going after what they call predevelopment funding, where you get up to $0.5 million to fully develop the project prior to submitting your bid in the end of the year.

So Connecticut is very attractive. It is only 100 megawatts, but as I mentioned, it could hopefully be a template for other states that have a lot larger RPS requirements. Because states tend to follow each other; once legislation is passed, they look at -- the executing agencies look at how to do it, and the how to do would be a good model from Connecticut.

I guess probably the biggest headwind I see right now -- bit of more concern with the hurricane -- is that natural gas prices and just seem to not stop going up. You take two steps forward and that kind of knocks you back one and a half. Can you talk about that about that a little bit?

And maybe like renewable fuels, like wastewater. Clearly that should be wastewater treatment gas. I mean, (indiscernible) should be coming more important in the economic situation. So maybe address that a little bit.

There is a very strong wastewater treatment focus in Japan, Korea, and California for us, because of the incentives that are available in those three areas. There is also in the Northeast, but not as attractive because there is not as many big wastewater treatment plants that have incentive funding tied to them. The ITC will certainly help that.

From a natural gas standpoint, the high price and volatility of natural gas frankly helps us against gas engines in the markets that we participate in. So if we get a guy who is coming off the grid, we've got a better shot at him than engines. It hurts us in getting people to come off the grid, because the grid prices have a lag between the price of energy and the cost of electricity to the user, because they have to go to the PUCs and gets rates increasing.

Everything we see, everything we read, in every state electricity prices are going up. Because as we have seen before, everything becomes dollars per barrel of oil equivalent, whether it's coal-fired power or natural gas-fired power, or even nukes and things like that. So it will help us over time, but there is a lag cycle with a short-term (multiple speakers).

Just finally, with the Enbridge, the recovered energy unit, does that clearly -- it is not using fuel per se; so is that something that could squeeze in under -- you know, Connecticut and some places fuel cells qualify as renewables on natural gas. But is that something that would be more applicable to just the broad renewable standards? Is that something you guys have looked at yet?

It does operate on natural gas, but it is even cleaner than a fuel cell because about 30 or 40% of the power has no emissions whatsoever. It is just taking the pressure drop and using that pressure drop to generate electricity. The other way to look at it is it takes our fuel cell from about 48% efficiency or 50% to 60%-plus efficiency. We see it as an excellent product for Renewable Portfolio Standards in Connecticut and others. We see it also in California as an ultra-clean to ultra-clean.

So we have got very high hopes for that product. We think that Enbridge will end up having additional partners, being the local gas distribution companies. So we are pretty excited about it. The first task is to get the first one built, and then to look at the target states where we want to take this to. The big gas pressure let-down stations are near the bigger urban areas, which have troubles with air emissions and grid congestion. So it is an excellent product fit, we believe; and Enbridge is an extremely strong partner, as you would imagine.

Okay, thank you.

Sanjay Shrestha from First Albany.

A couple of quick questions here. First now generator (ph), this is for Joe. Joe, talking about your cost to revenue ratio here, I understand that there was some -- the year cost related to the powerplant or the power purchase agreement. Excluding that, what would that ratio look like on a year-over-year comparison basis?

I think it drops it down to like 2.3, 2.4.

Okay. That is also just on some of the initial work that you guys are doing. And things that you're doing this year will be implemented in the next batch. Which means that number would go down to what during 2006 fiscal year?

If you are looking at the -- if you take the '04 and of year -- this is MA product, so this is a sub-megawatt product. It's $6,000. If you've got a selling -- let's say your selling price is $3,000 a kilowatt, you have a ratio of 1 to 2. As you get down at the end of '05, that product should go to approximately $4,800; and do the math on the -- that's where your ratio would be 1 to less than (multiple speakers) 2.

So it is clearly going in the right direction. I think what we're capturing, as you can see in the nine months' results, is a lot of the supply and some of the purchasing issues, even those -- the MA, what we're going to ship out is really the result of the value engineering. But you are seeing some of the volume and purchasing cost reduction coming through. So it is all in the right direction.

Okay. That is great. Just kind of a follow up on that. I guess this is for both of you guys here. When we are looking at $6,000 per kilowatt, that's going to be down again by the end of this year. Now all of a sudden you've got $1,000 per kilowatt or $1 million per megawatt tax credit from the passage of the Energy Bill. So when we look out into next year, I mean, you know, $3,000 being the market fair in (ph) price, what kind of a bit of a hold up here, or what is it? Or you guys said that the level of activity had picked up; so in the next 12 months, is it unfair for us outsiders to assume that the magnitude of the order bookings should increase pretty dramatically for you guys?

We believe it will and not just in the U.S. ITC; but we see it in Asia also, Japan and Korea. I think the one headwind I think somebody mentioned earlier is the natural gas volatility.

But that is more of a short-term, though, right?

We read it as a short-term trend. I will give you another example. We have a backlog of proposals and potential in Japan that are being delayed because Japanese are putting in a lot of LNG stations. Rather than transporting LNG to these industrial centers along the coast, they're running pipeline. So from an LNG location they will pipeline the gas to the industrial user. We have got several major industrial orders that are waiting on the completion of an LNG pipeline to place the order. So there are some headwinds and delays due to gas pricing and volatility, but it is a short-term phenomenon.

Okay. Jerry, is there a way that you may be able to quantify that for us in terms of, let's say, maybe your bidding activity is up X% year-over-year now since the passage of the Bill? Or is it a little early to do that?

It is a little early to do that. Interest level is certainly there. RPS I think we mentioned in the press release, that we quoted 14 megawatts. You know 10 megawatts was Long Island Power, the other 4 megawatts is for Connecticut RPS through our distributors. By the January -- I think it is early January into December '05, the middle for what is called Phase II of Project 100, we have developers, as I said. We said 30 to 40 megawatts. We've got three developers we're working with today who have multimegawatt proposals going into Connecticut for Project 100. Some are even applying for predevelopment funding.

We are also looking at the DFC-ERG with Enbridge for pipeline let-down stations in Connecticut. So, yes. We see a significantly increased trend of proposals.

So that is kind of how you guys get to that 30 to 40 megawatt kind of for near-term opportunity, including Connecticut and New York?

We don't know who else will be going after that 100 megawatts. It is not just fuel cells. I know the state hopes to get about half of it in fuel cells. But solar and wind are also potential. There will be a preference for fuel cells made in Connecticut by the state of Connecticut as you would imagine. Since we are in Connecticut, we think we have got some tailwind there.

One other question, staying with that 14 megawatt or the Long Island Power 30. From what I can tell, your focus of the Company has been kind of establish the market, while it might mean a slightly higher cash burn in the near term, including strategic market or the power purchase agreement. But with the tax credit in place now, and continued reduction in your cost, is it possible, even in case of some of this near-term order opportunity, that you might be in a much better position to get an external financing to do the project finance for this situation? Has there been any evolution there after the passage of the Bill?

We have been contacted by several, including our existing partners, distribution partners, as well as non distribution partners who are looking at our PPA portfolio that is existing today, as well as what we're looking at going forward, and trying to pencil some numbers on seeing what the ITC does to them, and their interest level in acquiring our PPA assets today.

Whether that will happen or not is hard to say. Because again, that is where a lot of the interpretation of the tax code -- if it is placed in service, it has got to be placed in service January 1 or later. What happens to an existing unit that a financial player buys as an asset? Is that considered a new placement in service? Those are the kind of things that the tax and accountants and lawyers are looking at today.

One last question. Any update on the hybrid powerplant opportunity for you guys? Anything new there to share with us?

The fuel cell turbine? Not the pressure let-down. The fuel cell turbine is sitting out back right now in preliminary testing -- the BOP, the module, and the electrical balance of plant. We expect to ship it by end of year to the Montana, to the Deaconess Billings hospital. It will be placed in operation there. Obviously we will run it here first, but then we will ship it up there for (multiple speakers).

So everything is on track with that?

Everything is on track.

Okay, that's great. Thanks a lot, guys.

Pearce Hammond of Simmons & Company International.

Just a couple quick questions, I think kind of following up on what Jarett had asked about natural gas. But basically the pace of order development has been sort of frustratingly slow, despite a definitely more positive backdrop when you look at RPS. I know the Energy Bill just went through. But when we look at the opportunity, fuel opportunity, especially in wastewater treatment plant, how come we're not seeing that really if we look at the product backlog? Where do we kind of get that tipping point and start to see substantial orders?

A couple points. On wastewater treatment, the incentive funding for that is in California. We're calling on every one of the California wastewater plants between ourselves and our partners. There is a cycle. All these guys are doing something with that gas right now, running it through engines or turbines. As their existing equipment gets older then they look at coming off that equipment and into fuel cells. But there is a cycle for doing that.

The second part of that same equation is if we were doing PPAs we would see a lot faster order flow on that. Because it is very easy for a municipal owned wastewater treatment to buy electricity and heat from a supplier. If it goes for buying the equipment itself, you get into the single sourcing. There is nobody out there bidding against us, and that makes it difficult to get municipal purchasing.

So those are the two things that are slowing down our process, the cycle of the wastewater treatment plants themselves. I will tell you there are some privately managed companies that run wastewater plants for the municipalities. These are privately held entities who are now interested in the investment tax credit. So that could be another source of them buying the equipment on a plant they're managing and selling the electricity and heat to the municipality as part of their service. So that is where we are with it, Pearce.

So essentially the factors that you mentioned there, like the single sourcing and so forth, that is really not going to go away in the near term. That is just going to be something you're going to have to deal with as we move forward.

That and the cycle. I think you will see more pickup of activity in Japan for sure, as well as Korea. Keep in mind, the first municipal wastewater plant was Fukuoka, City of Fukuoka, at Kyushu Electric. That has been operating a little over a year now. They have just published a report on it, or they're publishing a report. Then that goes into the government bodies, who then bless it; and that opens the door for the municipalities in Japan to do more. So there is a cycle there, okay? It is still an important market for us, but there is a cycle.

DO you see that sort of cycle turning into more of a sweet spot and would it be in '06 time frame?

Definitely.

Okay. On your commentary regarding natural gas, obviously there's definitely a lag between where gas prices are now and where it actually gets reflected in the grid. And as you were saying, certainly it hurts efforts to attract new customers away from the grid. But were you also stating that from a switching someone who is already off the grid, it actually benefited you?

Yes, because we are the most efficient machine out there. We're much more efficient than an engine or a turbine. So the higher the fuel cost, the more valuable that efficiency is.

But if you were to kind of lay out sort of the one step forward, one step back, given the amount of customers that could move off the grid versus the ones that are already off grid that could switch, on the balance would you argue that near term it would be a negative? Near term meaning, say, six months.

Within six to 12 months, because every PUC has rate increases in front of it. If I look at what is happening in Connecticut, California is going the same way, the industrial activity there. I will tell you, as a result of the dedication of the Sierra Nevada Brewery, we have got four interested parties that we're talking to right now that say, gee, I want to look at doing the same kind of thing. They are in that same PGA service territory that Sierra Nevada Brewery is. So that is the way it goes when you are -- the early adopters tend to bring in the broader market, and we're starting to see that happen.

Any refresh on gross margin breakeven numbers on megawatts shipped from the plants? Is it still in that --?

We're still saying 35 to 50 megawatts for gross margin breakeven; and somewhere in less than 100 megawatts for cash flow breakeven. Obviously that number goes down as costs come out of the product.

Sure.

Assuming market clearing prices stay where they are, which we expect them to do that.

The last question is related to the Air Products announcement. Essentially I find the announcement interesting, would it be fair to say, because this is a little prior field (ph) from distributed generation fuel cells for distributed generation power, with essentially serving the hydrogen highways with the hydrogen generation system. Is this an opportunity for you just to get some more experience in testing around your fuel cells? Or does this sort of represent a little bit of a business divergence?

It is not a divergence, because there is very little design change we have to do. Okay? There is some, obviously, to let the anode gas be taken out and split out of the hydrogen. A couple of valid points here. First, Air Products is driving the hydrogen part of it. If you look at every truck stop having a fuel cell delivering electricity and heat and hydrogen for refueling vehicles, it paints a very pretty picture as far as how to enable or facilitate these hydrogen fuel cell cars. We're not in the car business at all. That is, Air Products will take our hydrogen, clean it up, pressurize it, and do all the refueling.

But there are quite a few advantages that come out of it. Because one of the things you have to do is dewater the gas. If we can dewater the gas through this development, we would have a fuel cell that does not need to be hooked up to city water. That is an operating cost savings and it saves us a wastewater treatment plant. So there are some good things that come out of it beyond just the hydrogen. But it well could be an enabler for this chicken and the egg problem that fuel cell vehicles have.

Great, thank you very much.

Ben Sun of Adams Harkness.

First question, looking at the R&D sales backlog here, at 9, 10 million-ish, but comparable to the last year, but in terms of the Congress authorized funding level it has gone up a bit. I am just wondering how do you see that going forward, particularly in light of the Energy Bill.

Well, obviously, the ITC is a big win that is immediate. The authorizations that are in the Bill, which are significant, still require the President to submit a budget and Congress to convert that budget into actual appropriation. Then it's real money in our pocket. When it is 4 billion of it, we think there is a lot of areas of opportunity there for us, but it will be worked on during the '06 congressional year or the next calendar year, which is I guess the '07 congressional year. So we will be going after that, as will the whole fuel cell industry, to sort it out and get the various pieces to where it has benefit to stationary fuel cells like our own.

Yes. Second, just on the cost side of the R&D, the ratio .95 to 1 versus 1.7 to 1, project related but looking at our current backlog here, I guess, what do you see this ratio to be, or how shall we look at it?

The ratio went down significantly because the Clean Coal project, which is our first two megawatt plant, and the King County project, which was our first megawatt commercial or leading to commercial plant, had 50% cost share. So in the '05 numbers, you're seeing basically very little cost share. I think just parts of the Navy contract have cost share. What will change going into '06 is the DFC/T project starts to go to a higher cost share, because again, that is also the development of a product. So that is pretty much how the government works, is that as you get closer to commercialization you start to share more of the funding. So I would expect in '06 that the ratio will be a little bit higher than it is in '05.

Okay. Then a question, just we have seen a lot of potential activities out of New York or Connecticut, but I am just wondering if you can, I guess, comment on your existing large customers such as the ones mentioned significant in this quarter; the Marubeni, Caterpillar, LOGANEnergy? What are they thinking?

Caterpillar is continuing to proceed. We got that SUNY in Syracuse order through Caterpillar this last quarter. They're continuing. They have got probably 10, 12 people working full time on developing the Cat branded product. We're also looking at some activity where we combine both fuel cells and gas engines, so we have a lower capital cost. And the gas emissions are higher than a fuel cell, but lower than gas engines. So Cat's coming along fine. I personally wish it was faster, but Caterpillar moves at its own speed and does that very successful.

Marubeni, again very well positioned. I mentioned earlier the LNG plants and how that impacts the large industrial customers. The companies, the top 10 of Japanese industry are who they are going after.

When it comes to PP&L, PP&L has become very interested with the new investment tax credit. As you know, they do power purchase agreements; they do Starwood's. They are looking at Starwood's in California also to see if they want to move some operations out to California. So they are doing fine.

Enbridge is very active developing their product. LOGANEnergy was in for a review last week. Their target is megawatt class plants in California, and they have a pipeline that looks pretty full. Who am I missing? Alliance Power is our partner on a couple of Starwood's in the city of Santa Barbara. They likewise have a bunch of proposals in the pipeline.

So POSCO in Korea, there we're in the process of shipping the last two units to them and developing a joint venture further with them. MTU has been quiet over the summer. There, their finding in Europe, as I mentioned on earlier conference calls, is focused more on -- the EU funding is focused more on very large projects, demonstrations. And it is making it tougher for MTU. They did give us two orders this month, and know they're looking at half a dozen or better before the year end.

Chevron has got our last two big orders with Santa Rita Jail, and San Francisco Post Office likewise has stuff in the pipeline. So the distribution channels look very good to us.

That's all from me. Thanks a lot, gentlemen.

David Lee (ph) from Fardor (ph) Capital.

About the 300 MA model, you were able to cut your cost from 8,000 to 6,000 kilowatts. Are you still on track to get it to 4,500 kilowatts by the end of 2005?

That is what I said. At 4,800 I think; it is 20%.

4,800?

4,800 to (multiple speakers).

And you're still on track to get it down there?

Absolutely.

Okay. Can you just add a little --?

David, let me make sure you understand. That is where we would release the design, okay? That is not where we would actually realize the cost effect. There is a lag cycle there. But when we say we have a cost out, that is where we've got it verified that we can build the product with that cost. Then release the design for purchasing and all (ph) to start procuring first article.

Right, okay. Can you just give a little color on your distribution partnerships? I thank you mentioned in Korea you're seeing something with your wastewater treatment facilities.

Yes, POSCO in Korea have bought three units. The first one has been sited at a University. We will be announcing in the next 30 or 60 days the siting of the other two, which are either on the boat over that way or just getting ready to go on the boat. They likewise will be focusing as we have on the core market segments -- hospitals, hotels, universities, prisons, and the like.

Okay. Are you also exploring any opportunities right now in China at all?

We're not directly. POSCO has 18 steel mills in China. So POSCO is looking at the Korean market, but their real appetite is for China, as you can appreciate. They want to build their capability in Korea; and then when China is ready, to move into China.

Right now their -- China power demands are so strong and they're amount of power it so weak that they are throwing up everything they can to try to keep up with the electricity demand. They are not ready for fuel cells yet. They don't have the environmental concern that would drive them towards fuel cells yet. We have talked to them, but we think that will be coming. There may be some demonstrations in the 2008 Olympics, things like that, but we don't see broad rollout until several years.

All right. Thank you very much.

Neal McAtee of Redrock (ph) Partners.

Listen, I have been watching, but I've been a little out of touch too. I guess on -- I know the Energy Bill is a big help. To me the two issues have always been reliability and economics. I guess the reliability is proven, wouldn't you say? I can not believe anybody comes to you and questions reliability. Is that correct?

They really don't anymore. The other piece of that equation is we offer a long-term service agreement which takes any question about risk and warranty and all off the table. So if they have any operational concerns, we kind of remove it by saying we -- that is why we have got a big service team here and around the world.

Okay. Then on the economics, could you just say, if somebody came to you wanting one, how would the economics -- what would you run through in the economics, say, on July 15? Where were the economics compared to everything else? Then with the tax credit that you got beginning of this month, how does that change the economics?

Well, the market clearing prices in the Northeast and California are run in the 2 to $3,000 a kilowatt. It depends on whether it's a natural gas or a wastewater gas; and it depends on whether it is in the northern part of California with PG&E or the southern part of California with Southern Cal Edison, etc. It depends on whether you're competing with ConEd in Manhattan or the Mohawk Power or Niagara Mohawk up in northern New York State. So it depends on what the guy is paying for electricity. But somewhere in that 2 to $3,000 a kilowatt.

So we have been using from our cost basis the state incentives to narrow that gap between where our cost is and where we have to be. Now you have got another $1,000 a kilowatt or $1 million a megawatt coming. It is just like an immediate tax or cost reduction for us of $1,000 a kilowatt. If our costs are today $6,000 a kilowatt, going to $4,800 at design release at year-end, you can effectively take another $1,000 a kilowatt off of that.

Off the cost? Or I guess the other way to look at it is you could -- all of a sudden the market clearing price becomes 1,000 to 2,000 a kilowatt. I know, I guess you are --.

No, it in effect goes the other way. But the market clearing price depends on typically what the customer is paying to the grid. Again once we get him off the grid, we haven't lost one of those battles yet against gas engines. It is a question of having a customer think of this wild idea -- you mean I can generate my own electricity? And people like Sierra Nevada and Starwood Hotels and all have said, hey, this makes sense to us. It's getting more and more of them to do that.

Of course at the end of the day, economics do count because we are competing against a commodity, which is grid electricity, and people typically won't pay more for that commodity.

That is what I have always said. To me, people just don't pay to be green yet. Until it becomes economic they won't. So I am just trying to judge how big deal this $1,000 kilowatt is.

You can run the numbers based on -- the percentages based on what we were saying as what our current costs are costs are going to be. But obviously as our costs come down it becomes a bigger and bigger percentage of -- it becomes more and more important. When we get our cost down to $2,000 a kilowatt, then all of a sudden we are effectively $1,000 a kilowatt.

That's right.

Let me just qualify. We keep say $1,000 a kilowatt. It is up to 30% of the project cost, and up to (ph). So those are your two limits, 30% of project cost or $1,000 a kilowatt.

Okay. Where are you on capacity?

We're still at 50 megawatts a year. We're at a run rate of 5 to 7 or 8 megawatts a year.

Okay. Then you could get to 150 within, what, 18 months you think?

18 months at about 20-something million dollars in CapEx.

Which I would think, if you are looking at getting to that, you have got the orders where you're generating cash as well, probably.

The key is, do we see the clear market opportunities that we should ramp up production? Because keep in mind, all of our cost reductions are not based on volume. Volume adds another 20% or 25% just for the volume component, which we're not using right now. So we would look ahead and say, okay, if we are running at 50 megawatts a year run rate, what would be our new cost of our products? And with that new cost, what does the market potential then look? So it's a look ahead, and then you build. You don't want to build to order; you build to inventory and then move them out to order.

I guess if I wasn't the last person to ask, I am going to have to ask this. You have taken the cost from 6 to 4,800 and you're saying it is not all volume. What are just a couple other things you're working on to continue to ratchet that cost on down?

None of that. That is that at a 5-megawatt a year run rate. It is every part of the cost equation. Supplier cost, technology up-rate (ph), get more power out of the same stack, get longer stack life, value engineer it out, easier to maintain and service, easier to go through the testing condition before we ship to a customer. And it is every bit of that.

We had initiatives in all of those areas, and we obviously have more initiatives. We have more cost-out potential than we target. Okay? But then looking ahead at this, we take a three-year look ahead, and we don't see that that 20%, 25% target per year -- we don't see any jeopardy to that looking ahead three years.

Okay. Listen, I know it's been a long time coming, but you got to keep plugging away. I think you can get there.

Thanks, Neil.

Thanks, guys.

Jarett Carson of RBC.

Operator, we will make this last question if we can. Jarett?

Just a quick one. On the Clean Coal project that you talked about, the that is the cost share, could you give us an update on -- I think that was a coal gasification plant, maybe when that -- there's been a lot of more interest and clearly there's a lot of activity and subsidies in the Energy Bill for gasification and different things. Can you talk a little bit about when that might be up and running and what you have there?

We're still -- the gasification plant is still in process. So we have had our unit out there, and we are really just still waiting for that at this juncture. There is really no new news to report on that.

We have run all the components of it; and we have run coal gas before here in Danbury. We run coal mine methane up in Ohio. So the operational coal gas is not a big technical difficulty at all. What we are anxious for is our first 2-megawatt plant, and we want to get the thing up and running. But actually functioning on coal gas is not difficult at all.

So you have the -- sorry, the 2-megawatt plant is there, is that correct? But it is just not started up because of the --?

Because the gasifier is still having problems. They haven't made any coal gas, that is the problem.

Okay, all right. Okay, thanks.

I thank everyone for attending the call, and be happy to talk to you again in another few months. Bye-bye.

Thank you for participating in today's conference. You may now disconnect.