Comverge, Inc. Q1 2008 Earnings Call Transcript

Comverge, Inc. (COMV)

Q1 2008 Earnings Call

May 13, 2008 10:00 am ET

Executives

Dan Pfeffer – Treasurer

Robert M. Chiste – Chairman of the Board, President & Chief Executive Officer

Michael D. Picchi – Chief Financial Officer & Executive Vice President

Dean W. Musser – President & Chief Operating Officer Enerwise Group

Analysts

Stephen Sanders – Stephens, Inc.

Sanjay Shrestha – Lazard Capital Markets

Michael Molnar – Goldman Sachs

Brian Chin – Citigroup

Colin Rusch – Broadpoint Capital

Anthony Riley for Stuart Bush – RBC Capital Markets

Michael Carboy – Signal Hill Group LLC

Robert Stone – Cowen & Company

Elaine Kwei – Piper Jaffray

[Ronin Rodstal] – Independent Analysis

Presentation

Operator

Good day everyone and welcome to today’s Comverge first quarter 2008 earnings conference call. Just as a reminder, today’s call is being recorded. For opening remarks and introductions I would like to turn the conference over to Mr. Dan Pfeffer, Treasurer.

Dan Pfeffer

Welcome everybody. Joining me today on the call are Bob Chiste, Chairman, CEO and President, Mike Picchi, Executive Vice President and CFO and Dean Musser, President and COO of our Enerwise Group. I’d like to begin today’s call by reminding you that the remarks on this call will contain forward-looking statements. These forward-looking statements include, among other things, statements regarding the business strategy, plans and objectives of Comverge. More specifically, those statements will include discussions about the amount of future revenue we expect from long term contracts, the amount of megawatts we expect to be generated by certain long term contracts, the potential for AMI contracts, various regulatory changes and the amounts of revenue, profits and growth we expect to recognize for fiscal 2008 and beyond.

Although Comverge believes that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, estimates and other risks and uncertainties that could cause our expectations to prove to be incorrect. The actual results for Comverge could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors including market conditions, other risks typically associated with our business and the risk and uncertainties discussed in Comverge’s quarterly report on Form 10Q filed this morning and the annual report on Form 10K filed on March 25 with the Securities & Exchange Commission both of which are available from the SEC and online at EDGAR. You should not place undue reliance on these forward-looking statements which speak only as to the date of this conference call. Other than as required under the securities laws Comverge does not assume a duty to update these forward-looking statements if circumstances should change or otherwise,

With that said, I’ll turn the call over to our Chairman, President and CEO Bob Chiste.

Robert M. Chiste

Good morning everyone and thank you for joining us on Comverge’s first quarter 2008 earnings conference call. Our objective today will be to continue to help everyone on the call to better understand Comverge’s business model and major growth opportunities in the demand response industry which we help to create. I’ll begin our discussion today with some highlights on the first quarter and recent events and then Mike Picchi will provide more detailed information about the company’s financial and operational results for the first quarter. We will open the call afterwards and leave ample time for questions from analysts, investors and potential investors.

As we stated on our last earnings call six weeks ago we’re committed to pursuing robust top line growth while staying focused on our cost structure and achieving profitability. Our focus always will be on creating long term shareholder value. To that end, in Q1 2008 we have increased the number of megawatts under management by 557 pretending significant future top line growth while we continue to implement programs to capture synergistic benefits, cost reductions and operational efficiency measures in our drive to profitability. We also continued to observe that the strong market drivers impacting our business and industry such as supply and distribution constraints as well as environmental and regulatory concerns are becoming more and more urgent and they continue to provide large opportunities for Comverge.

We have carefully reviewed Comverge’s business opportunities for 2008 in each of our three operating groups. We’re very optimistic on the growth opportunities in all three groups and we are reaffirming our financial expectations for the full year 2008 that we communicated on our last earnings call. We expect full year revenues in the range of $95 to $105 million, up from $55 million in 2007. Our focus remains on successfully executing our business plan and vision, increasing our market penetration, expanding the market for our clean energy solutions and pursuing strategic opportunities.

In the first quarter I am pleased to report that we entered in to several major agreements. First, a $67 million multiyear contract with Consolidated Edison for energy efficiency. With our four contracts with ConEd our objective is to reduce their base load requirements by over 100 megawatts. Comverge also won a 75 megawatt 10 year VPC contract with Southern Maryland Electric Cooperative, our first VPC contract with an electric coop which received regulatory approval in April. And, we also expanded our largest existing contract in terms of megawatts with Nevada Power by 20 megawatts making it a 143 megawatt VPC contract. Additionally, our Enerwise Group increased megawatts available to sell in the open market open to demand response market programs by more than 74% this quarter alone. Between new contract awards and successful bidding in PJM open market programs, we added 557 megawatts during the first quarter of 2008.

As of today, considering our Q1 2008 activity just referred to and the 130 megawatts of capacity with Connecticut Light & Power awaiting regulatory approval we have 2,011 megawatts of capacity under management. To level set, at the time we completed our initial public offering 13 months ago our total cumulative megawatts under management was 362 megawatts. In other words, over that short period we’ve increased the number of megawatts that we manage more than fivefold. Again, that is more than two gigawatts. To put this in perspective, this is roughly the peak capacity consumed by well know electric utilities such as Austin Energy or Great River Energy. This represents future contracted revenue potential of $398 million.

We anticipate that we will continue to be successful in driving growth towards profitability by implementing new long term contract wins and continually leveraging our operating performance and scalability as critical mass is obtained and or expertise continues to deepen. With approval now received on all but one of our executed VPC contracts, we have started build out under these programs. This will increase sales and marketing costs in 2008 but also deliver over the longer term increased revenues and profitability on these contracts and for Comverge as a whole.

Let me provide an update on our 130 megawatt VPC contract with Connecticut Light & Power or CL&P. It was initially denied approval by the Connecticut Department of Public Utility Control as submitted. Working with CL&P we amended the contract and resubmitted it to the Utility Commission on March 3, 2008 for approval. We expect a decision to be forth coming and may occur in the second or third quarter of 2008. In addition, we are renegotiating with Southern California Edison on a revised C&I VPC contract and plan on submitting it to the California commission in June for approval. Our first contract was initially denied approval by the California Public Utility Commission along with several other contracts in March of this year.

Our Smart Grid Solutions Group which provides hardware and software technology products to utilities entered in to a number of new promising customer relationships including with several utilities in the mid Atlantic region. These programs are a sign of wider acceptance and usage of more demand response resources with a growing pipeline indicating more to come. We are also rolling out pilots to use our Super Set Thermostat to deliver a demand response solution over broadband power line connections and through a price responsive program. We will provide additional information in the near future by press release further explaining these relationships. Further, we remain confident about the long term prospects for our Smart Grid Solutions business as advanced metering initiatives or AMI are being planned in 2009 and beyond with our industry leading alliance partner such as Itron, Elster and Sensus.

There is a robust pipeline of RFPs throughout the country representing future opportunities in each of Comverge’s three operating groups. We are involved in as many as one proposal a week on average and some have matured to the point where we are engaged in negotiations involving contracts worth tens of millions of dollars with both our Smart Grid Solutions and Alternative Energy Resources groups. This industry and Comverge are poised for rapid growth. Federal and state legislative and regulatory movement to decrease demand on our existing energy infrastructure is wide spread and demand response and energy efficiency are generally viewed as the most expedient and cost effective resource, indeed sometimes being referred to as the fifth fuel.

All the trend that we see point toward an ongoing and increasingly robust role for demand response in the United States market and indeed the world. Just as one example, we’re encouraged to see progress [inaudible] Carolina’s filing to double the side of its demand response and energy efficient programs throughout its region to 2,000 megawatts. This is an illustration of what we see over and over again where demand response has become an integral mainstream component of a utilities resource mix. Consumers are asking for more measures and solutions to help them as electricity rates and fuel costs continue to escalate causing a domino effect of higher prices in their household and businesses. We know we’re on the right track in a new large market that can be uneven at times on a quarter-to-quarter basis but this is one of those times that our knowledge, expertise and leadership position will enable us to continue to gain market share as we move towards a profitable future. This is not just a business or industry it is a movement towards the right thing to do for utilities and their customer base to build and operating sustainable enterprises.

With that said, I’ll turn the call over to Mike Picchi our CFO to talk about Comverge’s first quarter financial and operational highlights.

Michael D. Picchi

As we have stated in previous earnings calls, under our residential VPC contracts we defer a significant portion of our consolidated revenues, our most profitable revenues until the fourth quarter of the year. We are required to defer revenue until the fourth quarter when we true up our estimates for megawatt capacity available to our customers during the peak cooling season in light of actual capacity that was made available over the summer.

Revenues for the first quarter of 2008 were $10.5 million compared to $5.7 million in the first quarter 2007, an increase of 82%. $3.9 million of our total revenues in the first quarter of 2008 came from our Smart Grid Solutions group compared to $4.9 million in the first quarter of 2007. As previously noted, this group operates under a build to order business model thus, quarter-to-quarter revenues for this group can be somewhat uneven depending on the timing of orders. While the first quarter of the year has traditionally been one of the strongest quarters for the Smart Grid Solutions group, based on the timing and fulfillment of orders this year we anticipate a strong second quarter. And, we believe Smart Grid Solutions group future business opportunities look promising based on the large AMI implementation being planned in 2009 and beyond.

The Alternative Energy Resources group recognized revenues of $3.3 million for the first quarter of 2008 compared to $800,000 for last year, an increase of 304%. $2.6 million of AER’s first quarter 2008 revenues were from Public Energy Solutions which was acquired at the end of the third quarter of 2007. Deferred revenue on the balance sheet from the VPC contracts that is generally not recognized until the fourth quarter was $7.7 million as of March 31, 2008. This reflects an increase of $5.2 million in the first quarter of 2008. For our Alternative Energy Resource Group as of March 31^st, we had 641 megawatts of contracted capacity with regulatory approval, up from $479 megawatts at the end of 2007, a 34% increase in the first quarter. Of the 641 megawatts 527 megawatts are on long term VCP contracts and 114 megawatts are on long term base load capacity contracts. These are the primary components of our future contracted revenues from long term contracts which total $324 million during the next 10 years. These megawatts and contracted future revenues do not include the 130 megawatts and $74 million in potential revenues from the CL&P contract awaiting regulatory approval which Bob discussed earlier.

Out of the 641 megawatts under contract, approximately 227 megawatts are built out which excludes capacity already built out under our ISO New England contract that we expect to deploy under our Connecticut Light & Power Contract. During the first quarter of 2008 we incrementally built out 34 megawatts of capacity under our long term contracts. These built out megawatts and the additional 414 megawatts remaining to be built out will translate in to high margin profitable business as we build them out over the next three years.

Revenues for the Enerwise operating group were $3.2 million in the first quarter 2008 consisting of $1.4 million in demand response services and $1.8 million of software energy engineering services which relate to the upgrade, maintenance and monitoring of power systems. Our Enerwise group has 803 megawatts of commercial industrial load under contract, an increase of 341 megawatts or 74% in Q1. These 341 incremental megawatts won’t begin producing revenue until June 1^st of this year. Enerwise also manages an additional 437 megawatts for fee. In the first quarter 2008 Enerwise’s revenues from economic or voluntarily demand response programs in PJM were negatively impacted by tariff and proposed business rule changes that are still being debated by parties before the FERC. These proposed rules reduced economic benefit to our commercial and industrial customers. We have the megawatts under contract, it’s now our goal to find the most lucrative market in which to deploy these highly valuable megawatts.

Enerwise’s revenues from economic demand response programs were $100,000 in the first quarter of 2008 compared to $2.8 million in the first quarter of 2007, a period prior to the acquisition by Comverge. While Enerwise has significantly increased the number of megawatts in 2008 for these PJM economic demand response programs, our revenues have not yet increased due to the combination of the traditionally lower shoulder month locational margin price, the rule changes and the new 341 megawatts not beginning to produce revenue until June 1^st. As prices increase with warmer weather and rising fuel costs it should become more economically attractive for our commercial industrial customers to begin contributing revenue producing load in to the market. This process has already started in Q2 for PJM zones which have elevated wholesale prices. The operating expertise we have to perform in this economic demand response market is because of our software platform and operational expertise which create a large opportunity for us particularly in the third quarter when wholesale prices are historically the highest.

Consolidated gross margins for the first quarter of 2008 was $4.4 million compared to $2.1 million for the first quarter 2007. Consolidated gross margin for the first quarter of 2008 was 42% up from 37% from last year’s first quarter primarily as a result of the inclusion of Public Energy Solutions whose business operations on higher gross margin. Let me add, we believe gross margin comparisons are only meaningful when looking at the entire year because deferred revenue recognition of the VPC contract until the fourth quarter. Importantly, the $7.7 million of VPC revenue deferred as of March 31, 2008 has a profit margin of 79%. In other words there’s an anticipated $6 million of deferred profit resting on the balance sheet as of March 31^st 08 that we would expect to be recognized in the fourth quarter of this year.

Total selling, general and administrative expenses were $13.4 million for the first quarter compared to $6.4 million in the same period of 2007 an increase of $7 million. Of that increase $2.3 million relates to the operations of Enerwise and PES acquired in 2007. Of the remaining $4.7 million increase $600,000 was for amortization of intangibles from our 2007 acquisitions. $1.4 million of the increase was from non-cash stock compensation expense and $2.7 million was for additional staffing in marketing and G&A costs. Included in that $2.7 million were customer acquisition costs for our VPC programs of $1 million compared to $400,000 for the same period last year. Notwithstanding the deferral of $7.7 million in VPC contract revenue as of March 31, 2008 we expense customer acquisition costs as they are incurred each quarter. Keep in mind the more successful Comverge is in winning new VPC contracts the greater sales and marketing expenses will increase in the near term as we incur customer acquisition costs to build out the programs during the initial few years of the typical 10 year contract term.

Capital expenditures for the first quarter 2008 were $1.4 million compared to $800,000 in the same period last year. As we begin to build out under our SMECO and other recently awarded VPC contracts, capital expenditures are expected to increase later this year.

Turning to the balance sheet, total unrestricted cash and cash investments as of March 31^st were $61.5 million with $62 million in cash on hand and considering $20 million in acquisition related debt we have essentially $42 million of net cash. Between the solid cash position and with the sizeable credit facilities we have in place, we expect to have the liquidity we need to grow the company organically, fund R&D and pursue strategic acquisitions over the next 12 months. We do not currently foresee the need to raise additional capital. As of today shares outstanding for the purpose of calculating earnings per share are 20.9 million. Total debt was $26.3 million as of March 31^st. This consisted of $6.3 million under our GE Capital Credit facility and $20 million was subordinated convertible debt related to our acquisitions of Enerwise and PES.

To reiterate what Bob said earlier, we continue to expect full year revenues in the range of $95 to $105 million, up from $55 million in 2007. If we achieve the midpoint of that range, that would represent approximately 81% revenue growth year-over-year. Our revenue growth in the first quarter 2008 compared to the first quarter 2007 was 82%.

That concludes our prepared comments. At this point I’ll turn the call back over to the operator to open it up for Q&A. Bob, Dean and I are ready for questions from our listeners.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Stephen Sanders – Stephens, Inc.

Stephen Sanders – Stephens, Inc.

A couple of questions, first on the PJM can you just walk us through a numerical example maybe in the shoulder months and the summer months of what the megawatt price less the retail rate would be just to help us understand the economics and the behavior there a little better?

Dean W. Musser

It’s relatively simply. Basically, you use an average retail rate for a customer of about $75 a megawatt hour and that could range from $50 to $100 but let’s figure on $75 a megawatt hour at the retail rate. So any time the price is above $75 a customer would be in a sense in the money. So, for instance in the shoulder months the price can go up to maybe $100, maybe $120 a megawatt hour so instead of putting that customer in to, their load back in to the system for $120 it would be $120 minus the $75. So, in essence they’re going to get $45 of economic benefit for participating for that hour. That’s the real change in the rules from the past. Now, where that differs now once you roll in to the summer time months the prices increase. So for instance last year, there were about 185 to 200 hours that were over $200 a megawatt hour so in that case if it was $200 a megawatt hour and a customer participates for one hour it will be $200 minus let’s say their average rate of $75, the customer would get $125 a megawatt hour. That’s the big change. What it’s effectively done is move the program from the shoulder months to a summertime month.

The other thing that it’s done is in an economic program there are only so many hours that a large C&I customer would want to participant in that type of program. So, from an opportunity cost perspective you don’t want to burn them out in their first quarter where there would be little economic benefit, maybe $25 to $50 a megawatt hour, you’d rather wait and hold those hours and use them in the summertime months when they could get upwards of $200 to $300 a megawatt hour. So, we had to be very prudent on dealing with our customers to not just register them for low economic benefit. In the past the customer got full LMP, locational marginal price if the price was above $75. So, in that case if it was $100 they received $100 for every hour they participated not $25.

Stephen Sanders – Stephens, Inc.

Then historically Dean, I think you’ve seen your revenues a bit 3Q loaded but with these changes, how do we think about that for 2008? Just kind of using the bogies that were in the original deal but do we look for 50% of your revenue to now fall in 3Q or will it not be quite that dramatic?

Dean W. Musser

Mike, do you want to answer that or do you want me to take that?

Michael D. Picchi

You can take that and I would focus on the large increase in the megawatts.

Dean W. Musser

The large increase in megawatts that we’ve signed up would generally be performing over the summer cooling season and they’ll also be in the capacity market in that summer cooling season. So, the majority of our revenue from a percentage standpoint will again be in that third quarter but with more megawatts obviously, that increases from the past.

Stephen Sanders – Stephens, Inc.

Then a follow up question on the VPC installations, I think you did 34 megawatts in the quarter. How should we expect that to play out over the balance of the year? Is it still reasonable to think 150 to 200 megawatts for the year? Or, how should we think about that?

Robert M. Chiste

Yes, it is Steve and I’ll let Mike give a little bit more color on that.

Michael D. Picchi

Correct Steve, 34 megawatts built out organically in Q1 and if you were to annualize that, that’d be almost 140 megawatts for the full year and yet in Q1 we didn’t have the benefit of building out over SEMCO or Connecticut Light & Power. So, in the back half of the year we would expect to be building out under those contracts as well so we feel like we can get over 150 megawatts of organic build out for the full year in addition to bringing on the amount of megawatts in our Connecticut Light & Power territory presuming we get Utility Commission approval on that contract.

Stephen Sanders – Stephens, Inc.

Then I think last call you talked about lowering the sales and marketing costs, the installation costs, the hardware costs, can you just give us an update on those? Still tracking at levels you were talking about at the analyst day on the prior call?

Robert M. Chiste

Yes Steve, they’re still tracking and what we talked about was bringing down installation cost from $70 to $50 and bringing down our customer acquisition cost also just coincidentally from $70 to $50. We’re actually seeing in some of our programs bringing down installation costs as low as $30 where we have a large concentration. So, we are seeing the continuing trend as we had talked about at the last call.

Stephen Sanders – Stephens, Inc.

Two quick questions and then I’ll hop off. On the Coop market maybe Bob, if you could just give us some additional color on what kind of opportunities you see in the Coop market, how that market is different in terms of sales cycles, channels, economics, whatever you think is relevant? Then, the final question is just for Mike, beyond the obvious increase in sales and marketing and other costs associated with the VPC build out is the expense infrastructure from here in terms of staffing and overhead looking pretty stable over the balance of the year?

Robert M. Chiste

Yes, on the Coop market we really bunch it in to two markets the Coop market and the municipal market. There are about 3,000 utilities in the country, some of those are very, very small Coops and municipals. There are about 400 to 500 large investor owned utilities. So, the market is approximately 2,500 to 2,600 of these smaller Coop markets and municipal markets. When I say smaller, that could possibly be a misnomer because LAPWP for example is a municipal electric company serving Los Angles but, for all practical purposes these are generally smaller.

We think it’s a great market for us for a couple of reasons. First of all, there’s a lot of them. Second of all they’re enduring all the same pains that the larger utilities are enduring with transmission constraints and generation constraints. And thirdly, and probably most importantly for us is they’re more capital constrained, they don’t have access to the capital markets as large investor owned utilities do. And of course, I’m talking in general terms here because some of them are well financed but we’re finding that there’s a great reception to demand response at this market so we are pursuing those. Our sales force is geared up and we’ve spent a lot of time with the municipalities and with the Coops. And of course, in our Smart Grid Solutions group of our 400 or 500 customers probably half to two thirds are actually already serving this market. We do think it’s a great market for us. We think with the SEMCO contract it opens a whole new avenue from the standpoint of utilities like to see successes and just like any other utilities the municipals and the Coops will be looking to the success that we will be in our deployment at SEMCO. So, I believe that answered the first question Steve, if it didn’t you can jump back in and I’ll let Mike answer your second question.

Michael D. Picchi

On the cost side in terms of the operating cost on the build out of the VPC contract, our Alternative Energy Resource group essentially had the infrastructure already created. We’ve got about a little over 150 people that manage our VPC contracts and these are the specialties we have in the area of marketing, doing consumer marketing to drive participants and enrolling these programs, our operations group, the measurements and verification group, all of that our call center, all that is created and in place and cost reflected fully in first quarter. Any incremental costs that we’ll have for the balance of the year will be more project related, hiring a project manager, some quality control technicians at specific project sites for example SEMCO, expanding what we’re doing in Connecticut. So, for Q1 does essentially represent a run rate of costs on the VPC contract side.

Operator

Your next question comes from the line of Sanjay Shrestha – Lazard Capital Markets.

Sanjay Shrestha – Lazard Capital Markets

Just a couple of quick questions, I guess you talked about the Connecticut Light & Power that you expect the approval in either Q2 or Q3 of this year. Can you guys go in to more details on that as to your level of comfort that whether it’s Q2 or Q3 is probably not as important as a lumpy business but are we confident that this thing will move forward?

Robert M. Chiste

I have to be careful when I say confident because it’s always uncertain when you’re dealing with the Utility Commission but that being said, we did resubmit it at March 3^rd and we expect a preliminary decision actually published this month and I believe May 19^th is the preliminary date and then there will be a final decision either in June or July based on if there is any further consideration. But, one of the great aspects of this residential VPC contract is the fact that we actually own the assets for 40 megawatts which we’ll be putting in to this contract so we get a great jump start and it enabled us to bid or to renegotiate this contract on favorable terms without hurting economics. The way that we did that, we hired a consultant to actually quantify the benefit cost ratio for the Public Utility Commission and I believe the Commission was quite appreciative of that. What we did by just moving some of the economics on the program we’ve increased the benefit to cost ration from 2.8 to 1 from what was about 2.2 to 1. We’re favorably inclined and we’ll just expect and hope that we get approval. If not, we intend to put those assets in to the ISO New England capacity market option in the future.

Sanjay Shrestha – Lazard Capital Markets

A couple of follow ups if I could, you guys mentioned the two gigawatt demand response by Progress Energy here and that’s certainly is the trend in this market and you’re very well positioned to benefit from that. Can you sort of get in to some more detail as to the timing of it? When we might be hearing some incremental stuff related to that?

Robert M. Chiste

Are you talking Sanjay specifically on Progress Energy or just other macro drivers and deals?

Sanjay Shrestha – Lazard Capital Markets

Both actually.

Robert M. Chiste

I guess the two I’d like to point to and we didn’t put it in our prepared remarks, one is on the West Coast and that is Southern California Edison which as you know has awarded their underlying meter contract for the AMI program to Itron but in their filing they’ve stated publically that the benefit of demand response to that AMI initiative is about $350 million. And, their intention is to bring anywhere between 850 and 1,000 megawatts of demand response on to that program. That equates to approximately close to one million thermostats as we’ve talked about before so the potential there, and hopefully we’ll get our share of that potential is over $100 million just for the thermostat piece.

Now, going back to the East Coast or to the right coast is Progress Energy of Caroline. There are some programs we are working on that have not been announced but as you know we’re active with a lot of the major utilities so I won’t specifically say who they are but with regard to Progress Energy of Caroline this is a program where they do have Utility Commission approval already and there will be awards on the demand response side which are in the very near future let me say. So, we are seeing large programs which are coming down the pike. It seems to be very real this time because we all know being in the Utility business over the years there being quite a few false starts. But, we are seeing, you know the proof is in the pudding and we are seeing real awards being issued and awarded now.

Sanjay Shrestha – Lazard Capital Markets

One last question, it seems like you’re adding more megawatt under management even faster than I think the guidance you provided or maybe an internal expectation to an extent.

Robert M. Chiste

That’s correct Sanjay.

Sanjay Shrestha – Lazard Capital Markets

Which is obviously very positive on a long term but should we now rethink about what the customer acquisition cost should be? Is it going to higher than maybe what the street expectation is right now which is going to end up impacting near term EBITDA and profit opportunity but certainly means phenomenal cash flow down the road. Is that something we need to be revisiting right now or we’re not quite there yet?

Robert M. Chiste

No, and I suppose what you’re talking about Sanjay is not the individual customer acquisition cost, the $50 we talked about but just our marketing cost in general rising because of the new programs we’re bringing on.

Sanjay Shrestha – Lazard Capital Markets

Exactly.

Robert M. Chiste

I’ll let Mike touch upon it. We generally look for project about 250 to 300 megawatts internally. I think in our analyst meeting we talked about, and I’ll let Mike jump in here in a second if I get it wrong, we’ve talked about each additional 100 megawatts equating to approximately $900,000 in first year marketing costs. However, those same $900,000 in order to build out equate to about $13 to $14 million in net present value of revenues. So, it is a slight trade off but of course, from our perspective we’ve constantly struggled with the concept of trying to educate on the fact that every megawatt that we add will cost up front but the rewards and the benefits on a net present value are actually dramatic.

Michael D. Picchi

So as Bob’s talking about on the long term contract side we’re seeing favorable trends in our cost to acquire customers on a per unit basis but that investment in a customer upfront has extremely long term value to Comverge and to our investors because of the net present value of those cash flows. Now, looking at the C&I side of the business our customer acquisition costs are very low. In our last earnings conference call we talked about $2,500 per megawatt added and that’s because we primarily use channel partners to generate new customers leads and using that channel partner structure allows us to keep a fewer number of direct sales people and acquire customers on a very cost effective basis.

Operator

Your next question comes from the line of Michael Molnar – Goldman Sachs.

Michael Molnar – Goldman Sachs

Can we detail the 641 megawatts in the VPC business, I apologize if I get too detailed but I want to make sure I have it right. The 641 we have 90 in Utah, 100 in San Diego, 62 in New Mexico, 143 now in Nevada, 75 in Southern Maryland and the PES would be 114. I seem to be short 57 is that the ISO?

Robert M. Chiste

Probably Pacific Gas & Electric.

Michael Molnar – Goldman Sachs

Is the 57?

Robert M. Chiste

Yes.

Michael Molnar – Goldman Sachs

And the Maryland contract is an expiration of 2018, is that about right?

Robert M. Chiste

Yes.

Michael Molnar – Goldman Sachs

And the last question would be for the 803 sold in the open market programs can you just give an idea, I know you don’t give too many specifics but if you had to kind of think about the economic programs versus capacity market versus I believe you have some in spinning reserves, how can we think about the rough breakout of those megawatts in those different programs so we can begin to assess how to think about that getting forecasted forward?

Robert M. Chiste

I’m probably not going to go too far down the path with you on this one but some of these megawatts could be used in any of the three markets. So, we have the 803 megawatts, some of them could be moved from one market in to another or serving in several of those three markets or multi markets. So, without going in to too much detail, Dean do you have any more color to put on it and Mike will be the governor here and make sure we don’t go too far on this path for competitive reasons.

Dean W. Musser

Right, Bob I think that is what I would reiterate. We don’t give out that information because it can point to where we think the sweet spots are in the marketplace and we do move megawatts around and concentrate from a sales perspective on different regions based on different pricing and where we think it is in the marketplace. We’ve kept this very close to the vest and I believe that we will continue to do so.

Michael Molnar – Goldman Sachs

Just to be clear, the PGM ruling does that only impact the economic program?

Dean W. Musser

That is correct that is strictly for the economic post, the real time program and the day ahead program.

Michael Molnar – Goldman Sachs

One last question, if I think about your guidance of revenues, if I just distribute among feature segments it would be say $30 to $35 million each. When you thought about that did you bake in sort of a skew I imagine to the AER and the C&I business meaning they would get more than their one third share? Any color you can give on that would be helpful.

Mark

I think first of all for the Enerwise business the C&I business as part of their merger agreement they have an earn out at the $36 million revenue level for 2008 so I think you can presume what level they’re trying to work to this year. Then, I think if you think about our Smart Grid Solutions group that business did about $17 million in revenue last year and that group is growing more modestly so I wouldn’t project that they would get to the $35 or $33 million level that you asked in your question but they’ve had more modest revenue growth in that 10% to 20% annual rate historically.

Operator

Your next question comes from the line of Brian Chin – Citigroup.

Brian Chin – Citigroup

Let me see if I can ask Michael’s question in a slightly different way. Is it possible that the impact of the PJM ruling in the economic market can be completely made up for by swapping the megawatts in to capacity market or an ancillary services market?

Dean W. Musser

Yes, there are opportunities. The hard part with gaining megawatts is signing the customer. We now have that asset because we have the customers under one to three year contracts, in most cases three year contracts. So when we talk about finding the lucrative market, yes we will move some customers in to the synch market where they can participate in the synch market or spinning reserve market. We also may actually have some inquiries about some bilateral, things of that nature. So yes, there are other opportunities for the customers. Again, we need to actually kind of work with our customer base to determine what’s best for everybody from hours participated, what time of year can they participate because again, since it is an economic program and there are a large number of hours associated with economic you have to look at opportunity cost as well. But, in a short answer yes, it can be made up by putting them in other programs and those programs historical will be of more value in the summertime months when we’re talking about bilateral.

Brian Chin – Citigroup

On that point when you had said earlier also that you’re shifting more and more of that load, that profitability opportunity in to the summer months am I to take that as the higher percent of those megawatts profit contributions will be in the summer months and that the overall absolute dollar amount of profitability for those megawatts for the year is unchanged? Or, are we talking about that ruling changing actually does lower the absolute profit for those megawatts for the year and it’s just that the percentage has shifted more towards the third quarter? Do you kind of see what I’m getting at?

Dean W. Musser

No, basically the raw dollars don’t really change. If you look historically at the first quarter, the first quarter results were normally relatively low because there’s not many hours for customers to participate in the economic program so that’s why last year it was $2 million and some dollars. The raw dollars will be the same because of two things. One, while we might have missed a quarter we have found many more megawatts than what we had planned so those megawatts will role in to the higher priced markets in the summertime so the raw dollars should not change.

Brian Chin – Citigroup

One more thing, you guys reiterated your revenue outlook for 08, are you also reiterating the modeling data points for EBITDA, net income and so on as you guys provided last quarter?

Michael D. Picchi

No, we’ve not provided a specific outlook in terms of EBITDA and EPS and the like. We’ve just spoken publically on revenue.

Brian Chin – Citigroup

So you’re only reiterating the revenue for this piece. You are not updating any views on EBITDA or committing to any views on EBITDA for net income for 08 and 09?

Michael D. Picchi

That’s correct.

Operator

Your next question comes from the line of Colin Rusch – Broadpoint Capital.

Colin Rusch – Broadpoint Capital

Can you give us an update on any progress on developing a demand response first policy in constrained areas?

Robert M. Chiste

Probably as you know or possibly not, in the Energy Independence Act of 2007 there was a mandate by Congress, a legislative mandate for the FERC to develop a national action plan on demand response. We are participating, the leader within FERC is a fellow named Mr. Wellinghoff who is one of the FERC commissioners, he’s leading the charge on demand response. We know him well, we’ve been working with him for a couple of years now. A number of the companies who are providing demand response energy efficiency programs are working with the FERC to try to develop this plan. Now, this is the FERC so it probably will take a year before that National Action Plan on Response is issued but it appears that there are really a couple of focuses that certainly Mr. Wellinghoff talks about and one is to somehow get the state utility commission to try to levelize the playing field whereas rate treatment for demand response energy efficiency is similar as the supply side rate treatment and the second is really to target constrained areas from the standpoint of distribution constrains and transmission constrains and generation constrains.

So, there is a lot happening but it appears that in some ways just the pure economics of our type programs are driving the marketplace. In other words we’re seeing utilities as evidenced by the fact that we now have these hundreds and hundreds if not thousands of megawatts under contract. This is because utilities generally have their backs to the wall. There is in fact these constrains both from a generating side and distribution side so despite the fact that FERC is moving on this, just the pure economics which are non-subsidized for demand response energy efficiency are gaining great foothold.

Colin Rusch – Broadpoint Capital

Can you give us a bit more detailed update on your channel partner’s backlog on the C&I side? What you’re seeing in terms of potential customer acquisition there?

Robert M. Chiste

Yes, I’ll give an opening to that and then I’ll let Dean speak about it because our channel partners are generally on our C&I side and the Enerwise group. We had signed at least one channel partner this year which we had publically announced, that’s Eaton Corporation and each of these are different. We’re not going to disclose how successful any one of our channel partners are doing but it’s certainly bringing the bulk of our C&I customers so we think it’s an excellent opportunity for us to grow and we have other similar types of arrangements which have not yet been announced but in effect channel partners where we have the opportunity to also bring on additional large C&I loads throughout the country and we probably will be talking about that more publically in the next 30 to 90 days. Dean, any more on that?

Dean W. Musser

Actually, our channel partners have already engaged in the [inaudible] market and in the New England markets where they have, actually, we’ve already signed some load through them so they do have a backlog of customers we are putting in to the queue to determine how many megawatts they can actually participate in to some of the upcoming auctions. We also have a channel partner that’s yet to be pressed in PJM that will provide an introduction to about 500 large industrial customers across PJM. So yes, our channel partners do have customers in the queue now going through the process of actually doing energy audits to determine what exactly can we put in to the auction. That’s kind of a continuous process, there are always customers coming through the gate, it’s just a matter of which ones can we put in to a program, how much load can be there so there’s some engineering back office. The bottom line is not just signing up customers but to find as much load as you possibly can per customer so that you can put them in to the program.

Operator

Your next question comes from the line of Stuart Bush – RBC Capital Markets.

Anthony Riley for Stuart Bush – RBC Capital Markets

Two questions, one is I guess more of a momentum question regarding the three segments, you’ve kind of talked about your outlook, if you had to compare your view of these three segments now versus a quarter ago in terms of business potential would you say they’ve strengthened, it’s the same or reduced? Could you kind of speak to that?

Robert M. Chiste

I’ll be careful here because I have my lawyer here also and they can get pretty giddy about the potential and the momentum. I’ve never been in a company or an industry with this kind of momentum but all three of our operating groups have just great upside opportunity and I’ll touch just kind of on the highlights. As you know, we’re very favorably inclined on the Smart Grid Solutions group on these AMI initiatives. I’ve mentioned two areas alone on the East Coast and West Coast where two utilities are just dramatically going to be pressing for more demand response programs. So, we’re very, very excited in the Smart Grid Solutions group. On the alternative energy resource group our pipeline has probably never been larger. We’re moving now in to this Coop market as we talked about with SMECO. We have a number of programs that are in the pipeline but more importantly demand response and even our VPC has really moved in to the mainstream. We’re no longer an anomaly, we are just talked about at virtually every utility we talk to just about how this is accepted and virtual peaking capacity is accepted.

We’re seeing a number of RFPs as I mentioned and we are seeing bids where they talk about capacity resource, not differentiating between the demand side and the supply side which is just very, very dramatic for us. So, we are bidding against generation and we’re winning in many cases. Then going to the C&I side of the business, as you know we have a very strong footing in PJM but we’re seeing markets open up now. [URCOT] is probably the most exciting for all of us in the industry which is Texas is just a tremendous C&I state, it’s probably the industrial center of large C&I in the country, the New England, the New York markets. We’re seeing markets open up and the opportunity for large C&I bilateral contracts. I hope I didn’t sound too giddy but I am just very, very optimistic and excited about the growth. But again, we look at the long term so the more successful we are, our customer acquisition costs often would suppress our earnings and EBITDA for particular quarter or all year. I hope that answered Anthony. I continue to be optimistic, I don’t know if I am any more optimistic than a quarter ago but I’m certainly very, very positive and there’s a lot of enthusiasm in the company.

Anthony Riley for Stuart Bush – RBC Capital Markets

Two last questions, one you reported your SGS units shipped in Q1 at 26,000, is there any chance would you be able to communicate to us do you have an internal 08 unit shipment goal?

Michael D. Picchi

We won’t go to that level of granularity but certainly you can look in our 10K for the number of units we shipped last year which was in excess of 100,000 unit and reference against my earlier comment where we’ve historically said that this business absent AMI is growing in the 10% to 20% range per year.

Robert M. Chiste

Anthony, it’s worth noting also we’ve said this before but just kind of the continuing education we have almost as many units being shipped internally to our sister company, to AER and what this gives us is actually two benefits. One is a little bit more invisible but one of the benefits is obviously that mass production allows us to do everything in our power to continue to reduce costs. The second is we actually have a built in internal margin which is eliminated in consolidation but when we talk about the margins for example on our AER side of the business we also have a margin built in to our Smart Grid Solution side of the business because we have an internal markup on our equipment costs. So the fact that we sell almost as many units internally and sometimes maybe even more on a quarter-to-quarter basis really bodes well for our cost structure and our competitive advantage not only in our Smart Grid Solutions group but in our AER group as well.

Anthony Riley for Stuart Bush – RBC Capital Markets

One last question, pretty simple, it looks like the 34 megawatts you added this quarter, is this tracking at a good pace for the rest of the year? Any reason not to believe that your VPC build out goals of basically it takes you three years to get to 100% build out. Any reason not to believe that’s still a good rule of thumb?

Robert M. Chiste

Anthony I’ll answer that and say that it’s a very good rule of thumb maybe on average. The reason I say that is just to sort of be cautious. Our San Diego program for example where we’ve had a slow process in San Diego approving our marketing programs just because of internal bureaucracy not because of anything we’re doing may take a little bit longer than three years but we’re seeing other programs where we’re accelerated and could come in a little bit less than the three years. So, I think for modeling purposes and so on you can’t go wrong by using the three years. My suspicion would be on average we might even come in slightly less than that three years but it’s a good modeling number.

Operator

Your next question comes from the line of Michael Carboy – Signal Hill Group LLC.

Michael Carboy – Signal Hill Group LLC

Let’s swing back here to the PJM and FERC issue, Dean I think you had alluded to the idea that this decision was still sort of subject to review or in negotiation. I’d like you to elaborate a little on that and share with us how you think that decision or that request by the PJM may be modified subject to constituent input? [Inaudible].

Robert M. Chiste

Michael, as I think you know we have a VP of regulatory affairs, his name is Eric Woychik and he’s been leading the charge here along with a couple of other people who focus on the regulatory matters in the company including one of Dean’s people. So, I will turn that one over to Dean and he can give you much further detail.

Dean W. Musser

Basically how this came about is late last year PJM had kind of went in to sunset clauses in the original demand response program which basically put in these interim rules in to effect. What they did at that point is they put in to a working group to put up with better rules for demand response both on the customer base line which is to prevent gaming and also what they call incentive and what we’re talking about is full LMP, recovery from a customer perspective. So, over the first three months of the year there was negotiations back and forth in the working group with the PJM members to try to come up with some compromise and quite honestly we thought we were close but then we just didn’t get there. So in April PJM has filed with FERC for the actual business rules for the change in this tariff which kind of memorializes the changes in baseline which have no real effect on what we do and also the full LMP versus retailing it or taking out the retail rate.

Where I think it is going to end up, my prediction is there will probably be some compromise. PJM has already publically stated that they are looking at the number to see if really transmission should be involved there maybe just subtracting out the G portion of G&T. There’s a group party before FERC right now called the PJM ICC that is appealing this again because of its effect on industrial customers who have input systems in to place to curtail load during peak pricing to be responsive to price and now this is detrimental to them from a cost benefit perspective in the shoulder months. So, where it’s going to end up I really can’t predict but I do think PJM has already put out there that they are looking at this to determine what is going to be the best benefit for everybody.

Michael Carboy – Signal Hill Group LLC

Do you have any idea on timetable with which these negotiations get resolved Dean?

Dean W. Musser

There’s really no timetable with the exception of there are some hearings coming up I believe it’s June, don’t quote me for fact on that but I think it’s early June where they are going to discuss this again. But, I know PJM is working very hard on this and FERC has been involved so this is kind of an ongoing dialog. Certainly, all the CSPs have gotten together and are supporting this as well so I can’t give you a prediction but it’s not something that’s sitting on the back burner and kind of waiting for somebody to act. People are acting on it now.

Michael Carboy – Signal Hill Group LLC

Dean, you’ve mentioned the ability to sort of shift customers around across different programs as it’s perhaps most economically beneficial to them. Are there any incremental expenses that Comverge bears in moving customers around through programs?

Dean W. Musser

No, actually the economic program is the most costly program from a back office perspective. Now, in our case we built software back in the late 90s that we patented this process and so from our standpoint there is no human intervention so the settlement is the big issue. You have to record a metering data and you have to settle with the power pole and that takes a lot of [inaudible]. Fortunately our software that we built years ago we’ve been able to kind of modularize if you will and adapt it to this so that’s done kind of behind the scenes. But, the economic program is probably the most operationally intensive because you have to put out forward pricing, respond to forward pricing and then settle with the power poles. So, really there’s no incremental costs the only cost you may have, may incur is customers that you put in to the synch program have to have robust meter and they have to have one minute meter data flow so there maybe some capital that the customer puts in or we pay for out of demand response, whatever it might be so they can participate in the synch program. But, quite honestly it’s minimal across the programs.

Michael Carboy – Signal Hill Group LLC

So you really don’t bear any economic hardship associated with shipping folks around?

Dean W. Musser

The fixed cost of the 24/7 command center, all the software, all the back office and hardware, that’s all the same.

Michael Carboy – Signal Hill Group LLC

Bob, let me come back to you here, you pointed out that the FERC seems to be nudging the various state PUCs along on the DR front but we saw similar sort of initiatives unfold on the transmission arena and ultimately the FERC had to crack the whip and say, “If you guys at PUC don’t pay attention we’re going to force some orders here.” Do you see the same degree of [inaudible] political delays and snags that might somehow frustrate the pace of DR once it’s evolved out of the PUCs?

Robert M. Chiste

I’ll just talk as an individual and none of us have a crystal ball but because these program are quite economic, as I had mentioned we’re just seeing programs and regulators that are moving forward regardless of what FERC does. And, I understand your analogy in the transmission arena but there’s another analogy I think and that goes to the Policy Act of 2005 which was much more focused on Smart Grid where the FERC required each of the utility commissions and utilities to set forth their plan for discussing, implementing AMI programs and so on so there was nothing explicit there but it opened up a dialog and as a result of that dialog it appears and it could have been coincidental but it appears that could have been part of the impetus for so many of the utilities now pushing forward and it’s really a ground swell frankly for large AMI programs.

We think the AMI programs will move forward with demand response because AMI by definitions is automatic meter reading plus demand response and we think just other initiatives of demand response programs standing on their own will be more of an incentive or more of a motivator because of the pure economics than the bully pulpit that FERC will be bringing. Incidentally, on the AMI side, just pilots that we’re engaged in bringing demand response programs to those AMI utilities we’re involved in at least seven AMI pilots right now and those pilots alone, those seven utilities have 14.3 million end points of meters. So, you can see just the pilots we’re engaged in are with very major utilities and so AMI is being pulled along for metering and demand response. Utilities are moving forward just because it’s economic for them and their backs are to the wall plus, we’ll get this push from FERC and utility commissions. I know I’ve blabbed on a little bit. I don’t see there being much resistance at all just because of pure economics.

Michael Carboy – Signal Hill Group LLC

I guess the last question here if I may, it seems ISO New England has its issue with FERC, PJM has had it, can you elaborate a little bit on any potential bump in the road there might be down in the [URCOT] market. Is there anything particularly unique with [URCOT] and the FERC rules that might result in some unexpected program revisions prospectively?

Robert M. Chiste

I’ll give this over to Dean, I think that he could articulate maybe the particulars that he sees at [URCOT] but I think what is a little bit important for us all to remember, these are very, very early stage markets, these are in their infancy so the rules are being defined. So, I think there are going to be some rules that are put in place which are tremendously helpful and other rules which we’ll have to step back on and figure out how to participate in these markets. I think New England, if we look at it is just being well thought out and they’re moving, progressing forward. The good news is these are markets which are becoming very, very important to the operations of the electric grid. And secondly, I think we could say almost unequivocally we think they’re here to stay. With that being said kind of in a macro sense I’ll see if Dean has anything more to add on more of a micro sense and maybe Texas market in particular.

Dean W. Musser

Well, [URCOT] is not governed by FERC so they will kind of make their own rules. However, I think [URCOT] will follow the same path that California followed, that PGM has followed and even New England has followed. Bob just stated that the rules have changed dramatically as DR continues to increase its importance in to those marketplaces so they’re going to have to adjust the rules. DR is relatively, while it’s been around a long time, their participations levels are dramatically different than what they were years ago so there will be tweaking or wholesale changes of rules. The real key is having the asset, the customer asset, the customer signed up and understanding how many megawatts they can contribute to whatever program is out there and the operational ability to determine what program fits the customer best, that drives the best revenue stream for both the customer and for Comverge, that’s the key.

I think as you watch markets grow they will continue to evolve. That’s how we built our software and when I say it’s modularized, that’s exactly why we did that so that all we have to do is kind of change tariffs and baselines for different markets because they will be vastly different and they will change and we don’t want to continue to rewrite software every time the rules change. I would say it’s going to be one of those trial and error a little bit as the markets evolve but the key issue is having that asset and being able to determine where you can deploy that asset in the marketplace.

Operator

Your next question comes from the line of Jeff Osborne – Thomas Weisel Partners.

Jeff Osborne – Thomas Weisel Partners

Just a couple of quick follow up questions, I just want to make sure I understand the Connecticut Light & Power issue, if that was denied in 2Q or 3Q how should we think about those megawatts? Would they be rolled over in to the New England forward capacity market but that wouldn’t start until June 1, 09 so they’re kind of temporarily dead megawatts?

Robert M. Chiste

Dean, is that the case? Do they start in June of 09 or earlier? I thought that we started $34,000 of megawatts this year?

Dean W. Musser

They can be put in, there’s monthly auctions that go on in New England so they can be put in to the marketplace we don’t have to hold them until next year.

Jeff Osborne – Thomas Weisel Partners

I just wanted to double check on that because the ruling will come out before your next conference call so we’re prepared for that. Then, I assume the low end of the guidance would include any type of negative impact on that?

Michael D. Picchi

Correct.

Dean W. Musser

Let me clarify one statement, it’s not really an auction it’s actual a fixed price in a transitional market so that price is already predetermined in the marketplace.

Jeff Osborne – Thomas Weisel Partners

And that’s the $34,000 which would be lower than what CL&P would be paying you, correct?

Dean W. Musser

Correct.

Jeff Osborne – Thomas Weisel Partners

Then I think you mentioned Southern Maryland would start in the second half, should we assume that’s kind of a 3Q rollout? Or, is there any possibility of that being accelerated?

Robert M. Chiste

I think 3Q is a safe assumption, a conservative assumption.

Jeff Osborne – Thomas Weisel Partners

My last question is just some time ago you announced the 12 megawatt contract with the United Illuminating, can you just update us on what’s happened with that?

Robert M. Chiste

That was actually a part of the CL&P or of the New England ISO contract and those megawatts were commercial and industrial megawatts which are not embedded, in other words are not part of our residential 40 megawatts that we talk about. So, those are available to go try to sign up again but those are C&I customers.

Jeff Osborne – Thomas Weisel Partners

Because they had expired, correct?

Robert M. Chiste

Yes.

Operator

Your next question comes from the line of Robert Stone – Cowen & Company.

Robert Stone – Cowen & Company

A couple of question for Mike, I didn’t quite catch what you said cap ex was for the quarter. Do you have a figure in mind for cap ex for the year?

Michael D. Picchi

Cap ex for Q1 was $1.4 million and I’d given some color on that to say it will increase during the course of the year as we begin the build out as I mentioned in the second half of the year under the SEMCO contract and the Connecticut Light & Power contract again presuming we receive Utility Commission approvals. So, somewhere in the slightly over $10 million range for the full year seems good. But, remember we have the GE Capital Credit facility that funds 90% of the cap ex under our VPC contract so we’ve got a lot of financial flexibility to build out a lot of megawatts under our VPC contracts.

Robert Stone – Cowen & Company

A second question related to your customer acquisition costs, I think you mentioned it was roughly $1 million spent on that versus $400,000 last year for VPC. Is that just for the marketing piece? Or, how much of the cap ex in Q1 was related to the [inaudible] megawatts this year?

Michael D. Picchi

It is just for the marketing piece so our total sales and marketing line for the quarter was $4 million, what we’re trying to say is that the customer acquisition piece of that was $1 million. The cap ex of $1.4 million relates to the cap ex incurred to build out those 34 megawatts.

Robert Stone – Cowen & Company

So there wasn’t any other cap ex, any other non-VPC related cap ex [inaudible].

Michael D. Picchi

There really isn’t, we ordered some computers but that’s not a material amount. You can really think about almost every dollar of that $1.4 million being related to that VPC build out.

Robert Stone – Cowen & Company

Last question, related to the mechanics of your deferred revenues, as you noted the majority of the VPC revenue comes in Q4. You’ve increased the number of megawatts under management, you installed additional megawatts in the quarter but although the sequential growth was higher this year the absolute dollar amount of deferred revenue is down. Is that because of last year including programs under ISO New England that are not in there this year? What are some of the mechanics of the absolute level of deferred revenue being lower year-on-year?

Michael D. Picchi

You’re right on Rob. At March 31^st last year, deferred revenue related to the VPC contracts was $9.1 million and that included six months of revenue related to our ISO New England contract which lapsed in October of 07. In 08 our deferred revenue on the VCP contracts is $7.7 million so the absolute number is lower year-over-year but I think important to look at is Q1, what happen in Q1 in both years. This year the deferred revenue grew $5.2 million and again in 08 that’s without Connecticut Light & Power and obviously that’s without ISO New England. Last year in Q1 the growth in the deferred revenue related to the VPC was $4.5 million so notwithstanding not having ISO New England or the replacement contract Connecticut Light & Power in place we grew in Q1 the deferred revenues under the VPC contract. Last year was an increase of $4.5 million, this year in Q1 it’s an increase of $5.2 million.

Robert Stone – Cowen & Company

So even netting out the changes with taking out the expired ISO New England, you’re on a pace to drive higher VPC revenues this year by the end of the year than last year?

Michael D. Picchi

We believe so.

Operator

Your next question comes from the line of Elaine Kwei – Piper Jaffray.

Elaine Kwei – Piper Jaffray

I was wondering if you could talk a little bit about the visibility that you have in to SGS revenue for the rest of the year? I understand that there was a little bit of a delay in the timing of some orders and I’m wondering if that’s something that you would expect to be made up and if there’s a percentage that’s been contracted for?

Robert M. Chiste

Yes Elaine, on SDS we would expect that from our internal budgeting, we would expect that all of those orders would be made up for.

Michael D. Picchi

So our visibility in the Smart Grid Solutions group, because it’s a book and ship business is essentially one quarter out in terms of having orders in hand that we’re executing on to deliver on. But, in terms of looking at the full year, we continue to feel good about our Smart Grid Solutions group.

Elaine Kwei – Piper Jaffray

Just on the CL&P contract, could you talk a little bit just generally about some of the reasons why it was originally denied and what types of modifications you had to make to the contract that you think would make it more acceptable this time?

Robert M. Chiste

The couple of reasons we think it was originally denied is we didn’t provided all of the support we believe the staff at the Commission desired so we hired the consultant as I mentioned. We went in and made a very good relationship we believe with the Commission. The second reason was they stated in their ruling that first denial, was that we had gone in to the wrong bucket of funding so we moved and have gone in to a bucket of funding which is called a conservation and demand response funding so those were the two things that we saw. What we did in our resubmital, I said that our economics were not affected to any material extent but we increased the benefit to cost ratio from 2.2 to 1 up to 2.8 to 1, this is dramatic for rate payers by the way because what a Commission generally will look for is a ratio of over 1.0 so we were already fairly strong in our first submittal and have become extremely strong. The way that we did this when I say that our economics were not materially affected and yet we gave the rate payers and the Commission a much more attractive program was frankly there are other participants in the program such as Connecticut Light & Power and where we’re sharing some of the marketing costs. So, we have shifted some of the economics internally to other participants and that’s the reason why we were able to give a lot more attractive program we think to the rate payers of Connecticut and still maintain fairly closely the economics that we’ve built in to our model.

Elaine Kwei – Piper Jaffray

And with the [inaudible] to the So Cal Edison situation as well or is that a completely different process?

Robert M. Chiste

So Cal Edison was completely different from the standpoint of it was still reviewed and denied initially. There were originally eight contracts which were submitted, only two of those were recommended for approval by the Commission Council and the other six participants filed an appeal, if that’s the correct word, two additional contracts were approved, four contracts were not approved. The difference in the contracts that were approved and those that weren’t approved we believe were they were different types of contract from a reliability standpoint. The type of contracts that were approved were providing day ahead notice whereas the contracts which were not approved were providing four hour notice. Four hour notice is a more valuable demand response program we believe than day ahead. So, the four that were not approved I assume are all being resubmitted because we’ve received pretty firm guidance from both the Commission and the Utility itself on what will be acceptable. We think these will still be economic contracts so we’ll be resubmitting.

Operator

Your next question comes from the line of [Ronin Rodstal] – Independent Analysis.

[Ronin Rodstal] – Independent Analysis

Most of my questions have been answered but I have three that mainly focus on cost items. The first is I’m wondering if you have any more cost take out opportunities in your SGS business? A while ago you were talking about the benefits you were seeing as far as manufacturing down in Mexico and that sort of thing?

Robert M. Chiste

Ron, I guess part of the culture of individuals at Comverge comes from cost environments. I mean, Ed Myszka who comes from Motorola and my history with really focusing on costs and Mike Picchi who is just downright cheap. A lot of what we think about as individuals has been costs. What we do though however when we’re just growing rapidly is we talk a lot about the top line in growth and there is some balance. I mean, we wouldn’t grow with any expense. So, I give you that background just to tell you and I think I mentioned this before, we view 2008 as a year of operations and we’ve actually set up five task forces internally, some focusing – one in particularly is focusing exclusively on costs, the second is on processes which relate to efficiencies and therefore costs, another on training and development, another on IT infrastructure which relates very heavily also to cost by consolidating and the fifth is the sales and development task force. We continually make an active approach to looking at our cost and our efficiencies and also just as our volumes grow, for example, as the AMI volumes grow dramatically we see more and more cost reductions obtainable. Those are the types of things we do.

So although we talk a lot on these calls and talk about our revenue projects, we’re very focused on the fact that ultimately we want to be highly profitable so we’re doing it in the manner which we think serves two purposes. One, we grow very dramatically on the top line but secondly we move towards profitability very rapidly also.

[Ronin Rodstal] – Independent Analysis

Then on your VPC deferred revenue, Mike was talking about a very, very high gross profit margin on there, I think I heard 79%, I guess I was wondering how that looks to be tracking in Q2 and what sort of margin do you think is sustainable through the year?

Michael D. Picchi

Well, I wouldn’t want to give an outlook specifically for Q2 but I think investors have heard us say that on our residential VPC program these have very good margins at the gross margin level between 70% and 75% so very strong economics to us is what we would anticipate kind of for a full year outlook.

[Ronin Rodstal] – Independent Analysis

I guess what I’m wondering is what would account for the rise in the gross margin? Does it have to do with your lower customer acquisition costs or lower marketing costs? Because, you’re above that prior range?

Michael D. Picchi

It would have to do with lower installation costs. So we talked about driving the cost of installation from $70 per kilowatt down to $50 per kilowatt and that’s starting to get reflected. We depreciate our installation costs through the cost of sales line so that’s what’s reflected there in terms of the work we did in 07 and now continuing in 08 to lower our installation costs, improving margins. Bob’s talked about what’s great about these VPC program, we get a long term 10 year contract that has fixed pricing in there so we know the revenues available to us. We bid these programs knowing what internal rate of return we would like to get and if we can operate the programs over that 10 year life by taking costs out that only enhances the returns to Comverge and Comverge’s shareholders. That’s what we’re working on in terms of lower costs to operate, lowering costs to acquire customers, lowering costs to install in these VPC contracts.

Robert M. Chiste

Thank you everyone. I hope that the fact that we stayed on the call for over an hour and a half and gave over an hour of time for Q&A and it appears that most question were answered, I hope that’s appreciated. We’re trying very hard to explain our business and to make sure we educate on our business model and differentiate ourselves and we’ve tried very hard to do that. Thank you very much for your patience.

In closing, we had our largest quarter ever and organically growing megawatts under management by adding 557 megawatts through new long term contract awards and successful bidding in open market programs. The macro market drivers remain very powerful for Comverge reflected in the high level of RFPs we’re responding to and recent contract awards such as the Con Ed Energy Efficiency contract, the SMECO Electric Coop VPC contract and the Nevada Power VPC contract expansion. All of this activity allows us to reaffirm our revenue for 2008 at $95 to $105 million. With that, I’ll conclude our call today and thank you all for joining us.

Operator

This does conclude our teleconference for today. We’d like to thank everyone for your participation and have a wonderful day.

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