燃料電池能源 (FCEL) 2004 Q4 法說會逐字稿

Good morning.

My name is Ashley, and I will be your conference facilitator.

At this time, I would like to welcome everyone to the FuelCell energy fourth-quarter and year-end 2004 earnings results conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer period. (OPERATOR INSTRUCTIONS)

I would now like to turn the call over to Mr. Steve Eschbach, Director of Investor Relations.

Thank you, Mr. Eschbach.

Good morning, everyone.

This is Steve Eschbach, Director of Investor Relations at FuelCell Energy.

On behalf of my fellow executive management team here at FuelCell, I'm delighted to have you join us on our fourth-quarter and fiscal-year 2004 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 in the development and commercialization of its FuelCell technology.

Listeners are directed to read the company's cautionary statements on the forward-looking information and other risk factors in its filings with the Securities and Exchange Commission.

I would now like to turn this call over to Mr. Jerry Leitman.

Good morning.

Thanks, Steve.

Before I get into our accomplishments and outlook going forward, let me first turn the call over to Joe Mahler for more detail on our fourth-quarter and fiscal year-end 2004 financials.

Joe?

Thanks, Jerry, and good morning, everyone.

To begin, I want to recap the impact of our previously announced sale of the Canadian solid oxide fuel cell business to our financial statements for the fourth quarter and fiscal year.

We signed a definitive agreement with Versa Power Systems prior to the end of our fiscal year to combine our Canadian operations with Versa Power, Inc.

This transaction closed on November 1, 2004.

In exchange for stock which increased FuelCell's ownership in Versa to 42 percent, we transferred people, Canadian intellectual property, and most of the SOFC fixed assets to Versa.

No cash was exchanged, and no gain or loss was recognized on the transaction.

The impact to the balance sheet in Q4 is that all of the assets transferred to Versa are classified as held for sale of 12.3 million.

These assets will move down to the equity investments line in the first quarter.

Going forward, FuelCell will account for its investment in Versa under the equity method of accounting.

On the P&L in the fourth quarter and for the full fiscal year, the results of the Canadian operation have been classified as discontinued.

FuelCell Energy reported a net loss for the fourth quarter of fiscal 2004 of 20.8 million, or 43 per basic and diluted share, compared to 15.4 million, or 39 cents per basic and diluted share in the same period of the prior year.

Net loss from continuing operations was 37 cents per basic and diluted share.

Revenues for the fourth quarter of fiscal 2004 were 8.9 million compared to 7.3 million in the same period a year ago, including product sales of 5 million versus 3.9 million.

Financial results for the fourth quarter of fiscal 2004 included a net loss of 2.8 million from discontinued ops, or 6 cents per basic and diluted share, for the Canadian solid oxide fuel cell operations.

For fiscal year 2004, the net loss from continuing operations of 64.9 million, or $1.36 per basic and diluted share, improved compared to a net loss from continuing operations of 67.4 million, or $1.71 per basic and diluted share.

Revenues for fiscal 2004 were 31.4 million compared to 33.8 million in the same period a year ago.

Cash and cash equivalents and investments, U.S. treasuries on hand as of October 31, totaled 152.4 million.

In November, we increased this to more than 240 million, with 93.5 million of proceeds from the sale of preferred shares.

Net cash used during the quarter was 17 million.

The main components broken down -- cash used in operations, 17 million;

Canadian ops piece of that was 1.5 million; cap expenditures were 2.6 million.

U.S. operations, which represents our core DFC products, operated below 15 million.

We expect to operate at this level for the year, with the exception of additional cash required for the Sierra Nevada PPA.

Net cash use for the year was 1 million, consisting of 70 million used in operations, offset by 69 million of cash received in the global thermoelectric transactions.

Components of revenue and cost for the fourth quarter of fiscal 2004 were as follows.

Research and development contract revenue for the fourth quarter of fiscal '04 was 3.8 million compared to 3.4 million in the same period.

Key factor in looking at the cost in revenue on the R&D line is that the cost to perform these contracts are coming down as we are nearing completion of our high cost-share contracts -- for example, King County and the clean coal, the 1 and 2 megawatt projects.

FuelCell product sales were 5 million for the fourth quarter compared to 3.9 million in the same period a year ago.

Revenue was higher due to the manufacture of power plants from Marubeni and the Salt River project contracts.

For fourth quarter, the product cost to sales ratio was 2.58 to 1, which drives it below 3, which continues to improve.

We see clear direction to continue to reduce cost to our targeted clearing prices.

Product sales backlog totaled 26.3 million at the end of the year compared to 14.4 million for the same period a year ago.

Back to the Versa transaction for one moment.

By combining the Canadian SOFC operations into Versa Power Systems, we have reduced cash consumption of approximately $10 million annually.

We expect to see these cash savings materialize as early as the first quarter.

We do have some severance and consolidation cash that will come through in the first quarter.

But in effect, we have eliminated that cash burn.

To conclude, securing the additional capital via the preferred stock strengthened our financial position, giving us more flexibility to execute our business strategy.

The funding will be targeted to accelerate market penetration, and may be used to help fund aggregated equipment purchase contracts with key customers, to stimulate key markets that use power purchase agreements, or help close large megawatt projects.

This is not a change in our business model, but rather, a tactic to drive the market for our DFC power plants.

I will now turn this call back to Jerry.

Thanks, Joe.

We made good progress executing our business strategy during the last year.

We are establishing positions in large key markets.

We're expanding our distribution network around the world.

Our products are meeting customer expectations of performance.

And we are reducing product costs by about 25 percent per year.

And with our recent preferred stock offering, we strengthened our financial position to accelerate the cost-out program as well as market penetration by our products.

We received new orders of 7.5 megawatts during the fiscal year, and I'd like to review some of the highlights around those orders.

With product certifications in place and the designation of our DFC power plants as ultra-clean EG (ph) technology, we're beginning to see greater traction in California.

The sales generation incentive program operated by the CPUC is expected to continue through 2007, and our products qualify for both level 1 and level 2 funding, ranging from 2,500 to $4,000 per kilowatt.

Now that we've been through a number of projects through this program, we anticipate that we can reduce the process time from initial application to securing orders from about 2 years to 1 year or less.

2 wastewater treatment applications totaling 1.5 megawatt -- the Santa Barbara and Sierra Nevada facilities -- were received from Alliance Power.

I recently visited the King County facility where we have our first megawatt plant operating on digester gas.

And I believe it will accelerate wastewater treatment activity on both the west coast as well as Japan as we bring customers to the site to see a megawatt plant in operation and talk to the King County management.

Chevron Energy Solutions sold our first 1 megawatt DFC1500 in California for the Santa Rita Correctional Facility near Oakland.

Subsequent to the fiscal year end, Chevron sold its second DFC power plant, a 250-kilowatt unit, to the San Francisco Mail Processing Center.

We have expanded our institutional and government markets to include now prisons and post offices.

The Salt River project adds to our growing grid support applications that include units with the Los Angeles Department of Water and Power and American Municipal Power-Ohio in the city of Westerville.

Municipal utilities continue to represent significant early adopter opportunities for our product in grid support applications.

MPU placed an additional order for components for 3 sub- megawatt power plants, and a second utility began operating in Berlin for Vattenfall/BEWAG this fall.

This represents the first European dual-fueled carbonate power plant.

RWE is expected to operate the first European wastewater treatment digester gas plant using our products in the city of Ahlen, Germany early in '05.

In the hotel market, we recently shipped our third 250-kilowatt unit for Starwood to the Sheraton New York Hotel and Towers in Manhattan.

Starwood, with more than 700 properties throughout the world, is interested in our plants at other locations.

California provides the best near-term opportunity for us, and we are pursuing projects there that can be economical for Starwood with the incentive funding that's available in California.

With multiple and repeat orders in key applications such as wastewater treatment, hotels, and institutional government facilities, and grid support applications, we are beginning to see substantial markets development that will accelerate our cost reduction targets and advance towards our profitability targets.

In Asia, we shipped our first commercial field follow unit to the Kirin Brewery in January 2003.

And we've seen Marubeni's order commitment increased to 4.25 megawatt with its 3-megawatt follow-on order in August 2003 and to 8.25 megawatts with its 4-megawatt order we received last April.

To further penetrate the Asia market, Marubeni and FuelCell energy added world- leading companies to the sub-distributors and packagers of our products.

First, Kawasaki Heavy Industries, who is a leading global manufacturer of transportation equipment and industrial goods, including gas turbine powered generators, will assist in penetrating the market in Japan.

We have just shipped a 250-kilowatt power plant to Kawasaki to be used for BOP, balance of plant development, using local Japanese components and suppliers.

Wastewater treatment applications continue to receive strong ministerial support in Japan, with applications now extending to food waste streams under the Nippon Biomass program with the announcement of Marubeni's Tokyo Super Eco Town project.

METI has announced a new energy program with the goal of 2,200 megawatts of stationary FuelCell power plants by 2010.

In Korea, we and Marubeni have partnered with POSCO, a world leader in steel production and an experienced power plant developer.

Korea has identified FuelCell technology as one of the top 10 growth engines for its economy.

And POSCO was designated to lead the development and commercialization of carbonate FuelCell technology.

The Korean government's goal is to install 300 units, sized from 250 kilowatts to 1 megawatt by 2012.

POSCO has ordered 3 DFC300A power plants, with the first to be sited at its facility and use for development of balance of plant using local components and suppliers for the Korean market.

In the northeastern U.S., Connecticut recently announced its Project 100 legislation that will require utility distribution companies to purchase generation from renewable technologies.

Our DFC power plants on natural gas qualify as Class 1 renewables in Connecticut.

The Connecticut Clean Energy Fund will issue a request for proposals in January, with project selection expected in late spring.

The goal is to have 100 megawatts contracted before July of 2007.

In Massachusetts, regulation passed during this summer's NStar rate case exempts any distributed generation of 250 kilowatts and smaller from standby charges and exit fees.

Additionally, an aggregate of 10 megawatts of fuel cells can be exempted through the 3-year rate period.

Other recent markets developments include New York recently passing a renewable portfolio standard that will require 25 percent of its power generation, or 3700 megawatts, from renewable sources by 2013.

And our fuel cells on natural gas qualify for this.

Elsewhere in North America, Enbridge is actively pursuing sub- megawatt- and megawatt-class projects that are eligible for Canadian and -- provincial and federal funding in Canada.

Since we shipped our first DFC 300A to Kirin in January of 2003, we have shipped an additional 34 units, including our first 1 and 2 megawatt power plants.

The availability of the fleet is currently in the high 80 percent range.

And we're learning a great deal from these units at customer sites as operating hours are increasing rapidly.

We closely monitor the fleet's operating performance, including mechanical and electrical control systems, water treatment systems, power conversion devices, software, and fuel cell processing systems, to name just a few.

From this analysis, we're able to determine predictive patterns that will improve performance and reliability.

And we're able to optimize maintenance and service schedules and procedures.

Through mid-December of this year, we've generated more than 53 million kilowatt-hours at customer sites.

As we shipped our current 10.5 megawatts in backlog, our operating hours annually will increase severalfold, yielding valuable information to both reduce cost and increase availability above our 95 percent target.

We met our value engineering cost reduction goal for 2004 of approximately 25 percent at nominal volume levels.

Block 1 changes are being implemented in products that are being released for production now, and Block 2 changes will be incorporated in products produced beginning during the summer of 2005.

Some of the specific engineering changes that would be made include piping filter redesign; change in bipolar plate stamping; increased yields and reduced cost in tape casting for both anode and matrix repeating components; automating the test and conditioning process; and an external fuel cell module and standard off-the- shelf mechanical balance of plant container.

We have identified similar type engineering changes in our 2005 cost-out initiatives that we expect will results in another 20 to 25 percent reduction.

Again, these are value engineering changes at nominal volumes.

Volume, of course, enhances these savings considerably.

For example, at 25 megawatts, an additional 15 to 25 percent cost savings can be realized.

And at 50 megawatts, we expect we can realize another 15 to 25 percent on top of that.

Plus, as we get cost out of the products and penetrate repeatable markets, we can forward- price to reach market clearing prices in the high-electricity-cost regions such as California, the Northeast, and Japan.

We believe our DFC products can provide more reliability at less cost as we value-engineer cost out and additionally achieve volume production.

We are currently targeting customers in regions where electricity prices are 10 cents a kilowatt-hour or higher and have access to incentive funding programs to mitigate use of shareholder capital.

With our current cost in volume and incentives, we can effectively compete with grid-delivered power and conventional combustion-based BG (ph) technologies, such as natural gas recip engines for baseload power.

These incentives provide a bridge to market penetration as we continue our aggressive value engineering cost-out that will enable us to be less reliant on these programs.

Focusing on applications that will add to order volume will further contribute to reducing our product cost, and accelerate our path to profitability.

With that, operator, we're now prepared to open this call to any other participants' questions.

(OPERATOR INSTRUCTIONS) Jarett Carson, RBC.

Joe, could you talk a little bit about -- on the SOFC, the spinout -- 2 things.

I kind of wanted a little forward-looking on the revenue side.

And then on the cost side, relatively speaking, would we expect to see from this level the R&D contract revenues to decline a little bit?

I'm just trying to pencil in relative to the SECA contract -- did some revenues also go to Versa, or will that continue to flow through to you?

And should we be modeling the cost, if you will, now that you're on the equity method as kind of a noncash minority interest line?

Yes -- let me start with the revenue recognition as the prime contractor -- the contract we sub out to Versa and Versa's partners the tasks that are required for SECA.

So we in effect will be billing the government for this.

So we expect that we will maintain our revenue line as previously presented.

The second question of the cost -- will be reflected -- actually, will come through in effect as a minority interest.

And it will be 42 percent of Versa's losses.

And that will be adjusted up against the investment account that will be on the balance sheet.

Jarett, you had a third question, I think --?

Yes, so it would be noncash.

It's absolutely noncash.

Right.

So from roughly a revenue level on the R&D contract side, should we be thinking something like 17 to 20 million or something like that for '05 -- is that in range?

I would broaden it slightly.

We're still working on the congressional approvals and whatnot.

I would just range it from 15 to 20 at this juncture.

Okay.

When we see -- so it's been about the year since we started the cost-out reduction program.

And clearly, we're starting to see the gross margin improve, both from a little revenue left.

I mean, there's a lag time between the efforts that you're doing versus what we're seeing on the income statement.

Should we -- this 2.6 or something -- should that continue to trend down kind of over the course of the year?

How are you thinking about that?

Jarett, let me get in on that first.

We started a cost-out program formally in June of '03.

We shipped the first field follow unit to Kirin in January of '03.

You can't start a cost-out program until you know you've got well-performing units.

At that point, that's your baseline; you start driving cost out.

So it's been about 18 months.

When you go through the cost-out, first you come up with the initiative, develop the redesign, test it out, or prove it.

And when you prove it to yourself, you implement it in the product line.

That's called recognizing it.

But you don't realize the gain from that until you actually ship products with those changes involved in it.

So there is a lag between completion of the design initiative for getting a cost-out of a product like this high-temperature piping I mentioned, and actually shipping that into the products.

Today, we're shipping products that have a Block 1 changes.

It will be the summer, June, July, August, before we ship Block 2 changes.

So there is a lag between having the cost-out and actually seeing it in the P&L.

Joe, do you want to add --?

Yes, and I think that this is indicative of I think some trending.

I think this is 2 quarters in a row.

The PPA contracts could impact that and make it somewhat higher.

But I think this is basically the range that we're in right now.

Okay.

Finally, Jerry, can you take us through what are the -- you said you just got back from Seattle.

Where are we with the 1 megawatt unit, and what kind of testing protocol are they expecting over the course of the year, and kind of some things that are lined up?

Because that seems to be kind of a key opportunity for you.

Yes, what we have been doing, and it's been quite exciting -- that particular plant -- it seems like every wastewater plant is somewhat different.

The bugs are the same, but they operate different.

And in this case, the King County has been taking its digester gas, scrubbing it up, and selling it to the local gas utility.

So in looking at it from our standpoint, sometimes we have pure digester gas.

Sometimes we have a scrub gas.

And they were flipping or diverting one way or the other quite often.

Now what we have done is develop software algorithms where the unit can continue its operation as they go from 1 BTU content type of methane out of digester gas to another 1 out of this scrub digester gas.

We're also looking at using that same control logic in quite a few other wastewater plants around the world, because we find the gas strain varies in its BTU content.

They have been operating at a megawatt now with extremely good reliability for several months, as they are doing this various testing.

They're also in the process of putting in some gas turbines out there, so that they won't be selling scrub gas anymore.

They will be using all their wastewater gas.

The important thing from us is -- what we're doing now since the first of December is training their operators to take over.

There's about a dozen that are in the training program.

That will last for another 30 or 60 days.

And then we will gradually turn over operations, where we send back and supervise, and eventually, where we become just a technical backup.

That will happen over the next 2 to 3 months.

And then there is a testing protocol that the King County will follow (ph).

As I think we've mentioned, there's a 12-person peer review group.

This is a pretty important project.

EPA did some of the funding, so there's a lot of visibility on it.

From our standpoint, we have a program developed to bring in customers, particularly west coast and Japan, in to look at that facility because it's the first really megawatt-class plant that anybody has put on wastewater gas.

And as you know, most of the wastewater facilities have substantial amounts of gas.

I'd invite you to go out there next time you want to, Jarett, and go take a look at it.

It's quite a nice facility.

Great, thanks for the invitation.

Thank you.

Eric Prouty, Adams, Harkness.

Joe, just a follow-up question on Versa to some of Jarett's questions.

How well capitalized is Versa?

I guess, when you guys look at the burn that Versa has and its needs for cash to make it in the SECA contracts, when do you expect to have to, if ever, infuse additional capital into Versa?

Yes, Eric -- the opportunity with Versa in our Calgary operation, which is pretty advanced in solid oxide development, was to wrap it under the Department of Energy SECA contract.

So we what we believe is that, as a separate entity, Versa has the opportunity to -- they can raise some of their own capital to really supplement Phase I. There are Canadian dollars available.

The way we have structured it, we can cover it from the U.S. to a large degree.

So for Phase I, we think we are in pretty good shape.

The challenge will come in Phase II.

Phase II has a 50 percent cost share level.

So one of the strategies is to get Versa out on its own, developing its own technology, have its own management team, consolidate technologies early, not wait -- not have individual development programs, but consolidate that technology early so that, as you go to Phase II, we think we're in a leading position to capture Phase II that we can also capture, perhaps, other strategic partners.

There has been tremendous interest with Versa and with solid oxide.

Another reason that it made sense to put solid oxide into its own entity is that there is tremendous interest.

This is an early-stage, large funded Department of Energy program that this technology functions under.

So we see that all as the opportunity set.

So their challenge will be going into Phase II is raising cost- share money.

Just to add on to that, Eric, Phase II is tentatively mid- to late '06.

There will be a downselect from 16 down to fewer teams, maybe 3 or 4.

The goal of Versa and our goal is to get selected for Phase II.

But as Joe said, we go from 80/20 cost share to 50/50 cost share.

Versa is headquartered in Colorado.

Colorado has indicated quite a bit of support.

So we think the company can be able to get some state funding at all to support its activities there.

And as Joe mentioned, while Calgary had a pretty significant cash burn impact to us last year, we have since under Versa dramatically reduced staff because we pulled in key staff from our partners.

So we think that, further, there are quite a few companies that have approached us that like the idea of joining into that.

And the business plan is to look at getting selected for Phase II, and then add additional partners to generate whatever capital we need to go forward.

Great.

So beyond just public monies and partnership money, would you guys or Versa have any interest in private or public investment money?

That's certainly a possibility.

That's one of the reasons why we wanted a clean structure with all of this solid oxide know-how into one entity, so that in the event we wanted to raise public capital, we would be positioned to do that at some point several years in the future.

Or private capital, Eric -- if it's strategic partnering or private equity, would play out.

Walter Nasdeo, Ardour Capital.

Actually, Jarett and Eric hit most of my questions.

But just so I'm completely clear on the solid oxide side of things, you've moved everything out of your facility and into Versa now?

Is that correct?

No, not correct at all, Walter.

We are the prime contractor.

FuelCell Energy has the contract from SECA for Phase I, $26 million.

We have then subcontracted many of the tasks under that to our partners companies -- MSRI, GTI, and so forth -- through this Versa arrangement.

Now Versa is becoming more than a virtual company, but a real company.

So the subcontracting from us as prime contractor remains.

That doesn't change.

What we're doing is subcontracting more than we had in our original plans, because we want to support the growth of Versa, for which we have obviously a significant ownership interest.

But from a DOE reporting responsibility and for what we contribute into the contract, our know-how on carbonate high-temperature fuel cells, balance of plant and all -- that doesn't change.

We're just taking additional -- we're subcontracting more funds to Versa than our initial plan was 2 years ago.

Okay.

So there's still development going on in Danbury.

Yes.

Okay, good.

That's what I thought.

I just wanted to be clear on it.

But again, let's be sure -- the core SOFC know-how is in Versa.

We want it that way.

We don't want to have any confusion that FuelCell Energy's main focus is commercializing its carbonate technology, but serving also as prime contractor for the SECA program.

Understood.

Now if I could just ask Joe real quick -- Joe, what are we expecting to see on the cash burn going forward now?

Obviously, there have been a few things that kind of made it a little lumpy in the past couple of quarters.

But where are we getting comfortable?

And lumpy is our signature.

What we are doing is that we are driving the cash flow down.

The factors that will affect cash flow -- you know, we really see it at 15 -- the basic FuelCell business around 15 or less.

We still have Sierra Nevada power purchase agreement equipment being built.

That will affect -- that will add to that cash flow.

There's probably a little bit of money left for Canada in terms of severance cash payments in the first quarter.

But generally speaking for fuel cell, we're targeting 15 or less right now as our cash flow.

You're saying cash flow, but do you mean cash burn?

Cash burn.

Sanjay Shrestha, First Albany.

Actually, this is Steve calling in for Sanjay.

Just a quick question on the sub-megawatt alpha unit.

Was there anything specifically that you can talk about that you learned -- any advancements technologically, or just fundamentally, and how that's going to help you in your second packaged unit in Montana?

Are you talking about the fuel cell/turbine hybrid?

Yes, I mean, obviously we'll learn.

We're building that first one during the first calendar half of '05.

In fact, we're either going out or getting ready to go out to the packager to put it together for us.

When we want to run that unit, and then have a second alpha unit going into Montana.

But the second alpha unit -- obviously, there is a lag, so we can grow on a learning curve between the first and the second.

But the timing is such -- I don't expect to see major redesigns.

Most of our learning curve came on the last 18 months of operating the fuel cell/turbine here in the lab on a 250-kilowatt stack unpackaged.

So part of what we have learned would be to extend what we already learned here -- the operational aspects of start up, shut down, how do you do the fuel cell separate from the microturbine and vice versa.

So it's that kind of thing we are learning.

And from that, you then go to obviously beta units and commercial products if we go in that direction.

Great.

And for the second packaged unit, can you talk about who is supplying the turbine?

Well, the first one is Capstone.

And it will probably be the second one, too.

As far as we can tell, and we've talked to quite a few, there are limited companies that have -- in the size we need it -- operating experience with a microturbine.

There are quite a few companies looking at coming out with one.

But we would rather go with the experience of Capstone than trying a new one.

And if we were different sizes -- for example, for our 2- megawatt plant, the Kawasaki 440-kilowatt turbine would be an ideal fit.

And their 440-kilowatt turbine dominates the industry.

So depending on the size, you have different turbine suppliers that make sense.

David Smith, Smith Barney.

Just to follow-up on Jarett's questioning about SECA.

And I don't mean to beat this to death.

But how much did you include in the revenues this quarter for SECA?

The revenues -- hang on one second.

SECA revenues in the fourth quarter would have been somewhere around 400K.

Okay.

And one thing going forward, and I kind of get a bit of an understanding on what you said already to Jarrett, but just to follow-up a little more, do you guys have direct costs that offset these revenues, or are they just basically kind of inflow and outflow?

We have tasks -- you're talking about the SECA contract?

Yes -- I know that you're recognizing revenues, but where do the costs come in?

On the financial statements, they would come under research and development costs.

So you guys are directly incurring the costs yourselves.

Either we are incurring the cost limited for direct labor and materials, and then we incur the cost through subcontracts to Versa and other partner companies.

So if we get $1 million of revenue, we could have 800,000 of cost that we subcontracted, or we could have 800,000 of costs that we did ourselves.

But either one is treated as a cost of the R&D contract.

Okay.

So then you guys are still doing work specifically within your facility on natural solid oxide systems?

We are, but it's limited.

It's limited compared to what our initial plan was a couple of years ago, because we now want to move that work as much as we can -- other than project managing the SECA contract, we want to move that to the Versa folks and our other partners.

Plus, one of the reasons we got selected is that we have specific expertise, certainly in integration and in packaging and in commercialization.

So those are the tasks and activities that we took, that we are responsible for, under the SECA contract.

I mean obviously, stack development, cell development, technology development is under Versa between our MSRI, University of Utah, and Calgary operations.

I would add that that's a key point.

DOE recognized that we have one of the largest, if not the largest, experience basis on high-temperature fuel cells -- the fact that one is carbonate and one is solid oxide.

Part of our commitment is to put all of the IP we have on carbonate into this program to be used on solid oxide.

We retain the IP.

But the IP can be used on solid oxide.

And I think DOE recognized that we have a big intellectual property basis on high-temperature know-how that would be applicable to SECA.

For example, we have a patent on a combination high-temperature fuel cell in turbine -- not a carbonate, but any high-temperature fuel cell in turbine -- this indirect heat exchanger approach we use is patented.

And that is one of the things that we put into the IP for this contract.

One other thing on the megawatts in the backlog -- where do they stand at the end of '04?

We have a 10.5 megawatts on backlog at the end of fiscal '04.

And then we receive another 250-kilowatt unit in November -- I think, December for the post office in San Francisco.

And that's all just DFC systems, right?

Correct.

One other thing -- in the press release, you talk about -- I think it was R&D costs went up relating to support costs on field units.

Can you just talk a bit more about what that is specifically?

Let me find that, David --

I think it's on page 4 --

Well, the internal R&D goes up from product development cost-out programs.

And in this cost-out program, we include also the documentation requirements.

For example, if we change a piping layout to reduce cost, we have to document that, both for an engineering standpoint, service standpoints, maintenance, serviceability, and so forth, and then for engineering support for products in the field.

As we get operating hours -- and this is where you really drive cost out and performance up -- the units operated 2 years, you'll find out a valve, a component fails.

So you want to fix that and take it going forward that it won't, that you will put in better valves that won't fail or will last longer. (multiple speakers)

And that's called a field follow program.

Caterpillar does it with their engines.

MTU does it in Europe.

Kawasaki does it.

It's very typical.

So your fleet leaders become your learning curve.

So that when you fix the fleet leaders from an engineering standpoint, then you roll that through the total fleet.

So if we change a fuel valve out because on our oldest units, we find out when its life is, then we'll retrofit that throughout the fleet.

And those require engineering support to do it, as well as service support.

That goes into the commercial product development R&D line.

David Snow, Energy Equities, Inc.

I haven't heard anything about your Caterpillar reciprocal engine deal recently.

What is happening there?

You're talking about the hybrid, David?

Yes.

Limited -- we're not getting a lot of activity in the marketplace from it.

Just as a general rule, the price of gas is having definitely a negative impact on our business and the whole distributed generation business.

So gas-based recip engines, like gas fuel cells, are impacted when the price of gas goes up to 7, 8, $9 a million BTU.

And I know that has some bearing on it.

I think Caterpillar's primary focus is on the Cat-branded unit.

But they haven't gotten much traction on that hybrid.

And it surprises me, really, because it's a neat deal.

We've got a couple of projects out in California we're looking at that we will probably take the similar kind of approach to, because it makes so much sense by having a capital cost skewed toward low-cost recip engines, and environmental profile skewed towards very clean baseload fuel cell.

But no orders to report to date.

I'm surprised you haven't felt the price of gas impact on your business more generally, or if you have, you haven't --

We definitely do, and that's why you can make numbers pencil (ph) in California with the incentives they have, whereas in the Northeast, it's very difficult.

And gas pricing is higher in the Northeast.

The big issue -- and we have seen it in the power industry in the '70s, the '80s, the '90s -- everything comes down to dollars per barrel of oil equivalent.

So you'll see grid prices change.

I think Connecticut just announced a 17 percent rate increase if they can push it through the CPUC.

So you will see it.

The coal prices will go up.

Nuclear power will go up.

Everything will go up to where it balances out, but there's a lag.

Gas spikes up first.

And I'm sure there's a bunch of peaking gas turbine plants that are mothballed right now.

But then, as the electricity prices react -- and they are reacting, and we think that's irreversible -- then it becomes levelized again.

And then as gas goes back down, with all the LNG plants and all, there is a lag before, again, prices come down.

So it's a lag cycle.

And we think it will moderate over time -- one of the other reasons why wastewater treatment gas, which in effect is a free fuel, becomes an even more attractive market segment then.

Absolutely.

Any news on your diesel technology that would be applicable to marine, as well as to islands?

Yes, we just received a mechanical balance of plant last week, as a matter of fact, here in Danbury.

We're going through stack testing on it.

The stacks are due to be built during the late spring, early summer.

We'll put the two of them together and operate it here in Danbury.

Then is to be followed, if the Navy so wants it, to move it down to the Philadelphia Navy Yard for further testing, and of course, eventually, fleet testing.

So we are making progress, but it's a long-term play, David.

When do you think that might go into actual use?

Well, in the Navy, it's hard to predict.

The Navy has a lot of other demands on it right now, as you can appreciate.

What we really want to do is prove it out on the Navy, and then put it into commercial islands and places like that.

The Navy's target is 2008, but we think that if we can prove it out, we think we'll see commercial opportunities.

In Japan, for example, there's a lot of industrial plants that are running baseload diesel engines for power -- those that are away from the coast and away from the grid.

It would be a very attractive market there -- plus, of course, the islands, as you mentioned.

You could then be commercializing it beyond the Navy by 2008 --?

Or even earlier.

And the Navy wants this.

The Navy wants to take a commercial product and put into the fleet rather than having a military-only product.

So this is sort of a win-win all-around.

The other thing that would materially help the situation to commercialize earlier is if we can get low-sulfur diesel.

What we're building for the Navy is a very high-sulfur diesel -- 10 or 12,000 parts per million.

We want less than a PPM.

If you had low-sulfur diesel at 50 or 100 PPM, it would make that process a lot less cost, a lot simpler, and it would allow us to commercialize it earlier.

You want how many parts per million?

50 to 100 is what they're talking about with low-sulfur diesel.

Now, we still have to clean it up to less than 1.

But starting from 50 or 100 is a lot easier than starting from 10 to 12,000.

Okay.

And do you think the regulations will give you that, or what?

The automotive industry is being pushed into low-sulfur diesel right now.

John Adams, Adams, Harkness & Hill.

What is your current production rate in megawatts?

Approximately 6 megawatts a year, John.

And your backlog is 10.25 -- does that mean your leadtimes are 1.5 years, or perhaps you're contemplating speeding up the production line a little bit?

That is certainly a possibility.

We are running now a stack every 2 weeks.

And we run 2 stacks a week.

So at this level we're at now, we could accelerate fairly easily.

We would recall some labor.

But we could pump it up pretty quick.

And we're balancing out versus scheduled need.

We will be converting over to Block 2 in late summer, which has a fairly significant cost reduction into it.

And the other thing that we're doing that we haven't talked that much about is technology uprates, where we start rolling in the fact that a 250-kilowatt stack gives us more than 250 kilowatt.

And we've got to rationalize how we bring that into the market.

So all those things --

You mean in terms of retrofit, or in terms of introduction into new production?

Both.

If a 250-kilowatt stack gives us 275, 300 kilowatts, first, how do we market that?

Everything is priced in dollars per kilowatt, so obviously, that's a pretty significant uprate for us.

And the second is that, as we change out stacks after stack light (ph), of course the BOP is capable of more.

But we would have to be introducing that.

But of course, you don't want to introduce it unless you get paid for it.

And in terms of your cost-out indications you've given us, the 20 to 25 percent on the '04 cost-out project, the 20 to 25 percent on the '05, and then the 15 to 25 percent at 25 megawatts, and again at 50 -- this uprate is incremental to that?

It's part of that.

It's part of that?

It's part of that, but the point I was trying to make is that we do value engineering at a very nominal rate of 5 or 6 megawatts a year.

We pick that in '03 because I think that was the rate for the previous year.

And then we also say, all right, get the real cost out that way, don't rely on volume.

But then if you do have the volume, what will that give you further than the value engineering?

And then you look at that.

And when we see those numbers hitting to where we can dramatically expand production by forward pricing, then we will absolutely launch for that.

And there are no further questions at this time.

Okay.

Thank you, operator, and thanks, everyone, for attending this conference call.

We will talk to you next quarter.

Bye-bye.

Thank you for participating in today's FuelCell Energy fourth-quarter and year-end 2004 earnings results conference call.

You may now disconnect.