Good morning, everyone, and welcome to the Acorn Energy First Quarter 2013 Earnings Conference Call. [Operator Instructions] Please note today's event is being recorded. At this time, I'd like to turn the conference call over to Ms. Heather Mallard, General Counsel. Ma'am, please go ahead.

Thank you, and good morning, everyone. Please take note that certain of the matters discussed in this presentation contain statements that are forward-looking, such as statements relating to results of operations, financial condition, business development activities and market dynamics. Such forward-looking information involves important risks and uncertainties that could significantly affect anticipated results in the future, and accordingly, such results may differ materially from those expressed in any forward-looking statements made by or on behalf of Acorn Energy or its subsidiaries. All statements other than statements of historical fact in this presentation regarding Acorn Energy's or any of its subsidiaries' future performance, revenues, margins, market share and any future events or prospects are forward-looking statements. For more information regarding risks and uncertainties that could affect Acorn Energy's or any of its subsidiaries' results of operations or financial condition, please review Acorn Energy's filings with the Securities and Exchange Commission, in particular, its most recently filed Form 10-K and Form 10-Q. Acorn Energy's forward-looking statements are not guarantees of future performance, and the actual results or developments may differ materially from the expectations expressed in the forward-looking statements. As for the forward-looking statements that relate to future financial results and other projections, actual results will be different due to the inherent uncertainties of estimates, forecasts and projections and may be better or worse than projected, and such differences could be material. Acorn Energy undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. I will now turn the presentation over to John Moore, President and CEO of Acorn Energy. John?

Thank you, Heather, for that dramatic reading. Welcome to Acorn Energy's First Quarter Conference Call. I'm delighted to announce our business reported a 37% Q1 versus -- 2013 versus Q1 2012 growth in revenue. We also had growth in gross profits and margins. Over the balance of the year, we anticipate further ramping revenue with rising customer adoptions of our new products. We expect margins to increase in the second half of the year as US Seismic's new interrogator and automatic -- automated production line comes online. GridSense continues to make strides in efficiencies, and OmniMetrix continues to grow its high-margin monitoring revenue stream. Overall, our businesses are poised to emerge from this major investment cycle in products and infrastructure, and we believe this will be reflected in our shareholder value and our plan to be profitable by the end of 2014. Our balance sheet is strong with over $30 million of working capital and over $20 million in cash, of which $17.6 million is held at the corporate level. 3 of our 4 businesses, DSIT, GridSense and US Seismic, have working capital lines, and OmniMetrix is developing a banking relationship. We've budgeted $7.6 million of equity investments in our operating businesses for the remainder of this year. Our board has decided to halt our quarterly dividend because they are so enthusiastic about the use of our capital to accelerate the growth of our businesses. Our portfolio of companies can best be considered in terms of risk-reward ratio. We believe we own businesses that address large market opportunities, and we've invested in new products that help our customers solve problems they're having by doing things the old-fashioned way. Our risk is investing our capital not only in new products but also in sales and marketing infrastructure that's necessary to prove…

[Operator Instructions] Our first question comes from Harvey Poppel from Poptech LP.

John, certainly, your narration this morning shows a very promising outlook for the company going forward after what I think investors would view as, at least, a couple of quarters where things appeared to be stagnant, at least on the financial front. First of all, I did want to applaud you for suspending the dividend. I know that's always a difficult thing for any company to do, but I think in this particular instance, you've paid the investors back a considerable return for the CoaLogix exit. And now it's time to go forward and you're facing a period of investment, and continuing the dividend would have been imprudent in my view. So I think most savvy investors are with you on that call. The other aspect of your business I'd like to have you comment on is one of the hottest areas for investment in technology today is the so-called machine-to-machine, or M2M, segment of the marketplace. And there are companies like Cellular that have just been acquired at a substantial premium, others out there. And I don't get the sense that you've tried to characterize Acorn Energy as that type of company. Energy has always been the kind of the word that binds the various holdings together, and yet it would appear to me that every 1 of the 4 companies, OmniMetrix probably being almost a pure M2M play, but all of them are basically M2M kind of businesses. And I wondered whether you shouldn't be stressing that in terms of identifying the company in that sector.

Well, thank you, Harvey. So thanks for your comments, and your question was definitely one of -- last quarter's call, it was the one I got the most comments and compliments on. I think positioning and branding is so critical. I'd say that we haven't been more aggressive about M2M because we sort of see OmniMetrix as being earlier-stage. But I take it as valid criticism. I need to engage with you and look at positioning the company as M2M because clearly, companies like GE are talking about the Internet of Things and Mitsui visited us recently, and they're interested in investing in M2M. So you'll see us considering that very seriously.

Our next question comes from James McIlree from Dominick & Dominick. James Patrick McIlree - Dominick & Dominick LLC, Research Division: Just a few things. Can you clarify for me the testing for the supermajor? There's an initial test? And then assuming success, there would be a second test in the Eagle Ford? Is that -- did I hear you correctly there?

Jim, can I hand that one over to you? [Technical Difficulty]

Sorry. I just -- somehow, I got dropped off the line. They just put me back on, so sorry if I missed something.

Okay, great, Jim. So Jim, did you hear the question?

No, I did not. I just got back on.

So Jim just asked if -- he said that the way I presented the trial with the supermajor was that there was a test to get an order for 100-level units, and then there was a sort of a follow-on test for -- once they bought the 100-level system at the end of June or middle of June. And in my understanding, is this -- if you can give more detail on this.

Yes. So what happened is -- this is one of the supermajors, they've determined -- they've spent a lot of money trying to determine how to maximize their ultimate recovery, and they've determined they're not doing it. And because of that -- and this is all their unconventional fields. And because they're not doing it, they feel like every month that they don't implement some kind of monitoring system to improve their efficiency, they're losing money. So they decided to embark on this ambitious plan, where they're going to take all the technologies that could be used for microseismic monitoring, conventional, fiber optic, set up a test and based on this test, pick a company they want to go forward with the technology they're going to use for their monitoring in the future. So this first kind of like shoot-off is happening in the end of this month. And then from that, they're going to pick one company, and then with that one company, you're going to have that company build a 100-level array. And that 100-level array will get installed sometime in the August, September timeframe. And because they intend to do these permanently, that will get cemented in in a test run, and they want to run it and leave it cemented in in the order of a month or 2 to make sure everything works fine. And then at that point, it's noncompetitive work because the selectee is their technology. And then after that, if there's no problems with it being cemented in over a period of 1 to 2 months, they're going to order 4 100-level arrays and do a full-scale test of their whole approach for -- that takes -- it's called Life of Field monitoring, where they'll do some cross wells and vertical seismic profiles with these arrays to get a high-resolution image, use that to drill the laterals where they're going to place them in the shale bed. And then once the laterals are drilled, they're going to use the same arrays to monitor the frac-ing, get the frac maps. And then they feel that they're going to have to go back and re-frac many times over the life of the field. And so the arrays are going to stay in place so that they could re-frac maybe over a 5 to 10 year period. So I'm not sure. I didn't hear the actual question. I hope that answers it. James Patrick McIlree - Dominick & Dominick LLC, Research Division: That was great. That was a terrific answer. Do you have a sense of how many permanent installations of your product would be necessary to monitor a field of -- I don't even know how to phrase this. If you had a field that had, let's say, a half a dozen production wells, how many monitoring arrays would you need to have to monitor that field?

Well, I mean, it varies with -- oh, sorry. James Patrick McIlree - Dominick & Dominick LLC, Research Division: I'm just saying if there's a more relevant way to look at it, then please educate me.

Yes, and it varies with company. Everybody's -- all the different companies I talked to are convinced. They've been frac-ing and not having efficient production, and the main reason is they don't really have a good understanding of the subsurface. And that they're convinced they're leaving a lot of oil and gas on the ground, and so they're trying to improve it. Now the one supermajor, they're envisioning for every vertical well that they're going to put in place, and a vertical well will have probably 8 horizontals that they'll frac, will take 4 100-level arrays. I think in the end of the day, they're going to back off from that because I think 4 arrays to monitor is ideal. I'm not necessarily sure they need a 100 levels, but that's what they're going to start. I think when the smoke clears and everything, probably somewhere 4 arrays, 20 to 40 levels each would probably be sufficient. And then those are the guys that are putting them in permanently. I think you need at least 3 in order to triangulate where the, I'll call it, the fracs are occurring. So probably somewhere between 3 and 4 arrays per vertical well pad. James Patrick McIlree - Dominick & Dominick LLC, Research Division: And this particular supermajor is drilling 40 wells per month?

Yes, in the U.S. James Patrick McIlree - Dominick & Dominick LLC, Research Division: And I know that you've talked about this in the past, but if you can just remind me what kind of average selling price you envision for this product when it...

Yes, our average selling price for 100-level array is in the order of $2.5 million. And when you look at per level cost, that's about $25,000 per level. The beauty of that is we can make excellent margins on that, and the industry standard is about $60,000 a level right now. And the product isn't really fit for the purpose. So I think once people see that it actually does and they test it out, then I think the sales are just going to ramp up because price point is excellent. It's less expensive than what's out there now. The performance matches the microseismic requirements. So basically, we're trying to prove it out with these majors, get the stamp of approval from some of these large supermajor oil companies, and with that, it makes our marketing job much, much easier. James Patrick McIlree - Dominick & Dominick LLC, Research Division: Jim, it just seems like if you're going to sell 4 100-level arrays and it's $2.5 million per array, then you're talking about a $10 million incremental cost for the oil companies. And it just seems like a significant increase in well costs for them, which would be -- it just seems too much. Am I...

I mean, I would tend to agree with you, but this is what they tell us. I mean, they're like losing so much money by not getting adequate production out of their wells. But we tell them about the cost of our array, they said, "Well, when you really think about it, the monitoring wells that we're going to put in are going to cost twice as much as what your arrays are going to cost." So I said, "Well, are you committed to spending the money?" I think at the end of the day, they'll be able to -- instead of doing 100-level arrays in each one of those, they'll probably end up with 20 to 30 levels. I think that will be sufficient. But I think initially, they're just going to go out, and they'll start with 100-level.

I think one thing I'd like to sort of underline is in the Mark Mills article, he was talking about how in the '80s, the ratio was 50-50 on drilling dry holes. The unconventional oil industry today is worse than the wild catters back before the 19 -- before 3D seismic came out, it's 1 in 4 wells -- 1 of 4 frac stages are producing hydrocarbons. So there's a huge return on investment for these guys to better understand the subsurface.

Absolutely, yes. James Patrick McIlree - Dominick & Dominick LLC, Research Division: John, can I get you to repeat the number of connections OmniMetrix had in the quarter versus the prior quarter? And then just one more thing, and I'll see the floors. GridSense and that $50 million opportunity you were talking about, that's over a multiyear time period, and were you expecting some decision on that this year? So the connections and the $50 million...

I think we'll do -- I think we'll be doing a press release and naming the utility this year. And I think their anticipation is that they'll start to roll the project out next year. It's the utility that's under huge pressure right now to better manage their grid, and so they've got -- they seem to have regulatory support. But that may be wishful thinking on my part. James Patrick McIlree - Dominick & Dominick LLC, Research Division: Okay. And the connections?

The connections was 854 units this quarter as compared to 184 units in Q1 of 2012 and 1,894 all of last year. James Patrick McIlree - Dominick & Dominick LLC, Research Division: Those are the addition during those time periods?

That is correct.

Our next question comes from Rudy Hokanson from Barrington Research.

A couple of questions. On USSI, you mention that you're expecting revenue in the second half of the year from a lot of these proof of concept runs that you had. And I was wondering if you could be a little more explicit, or do you see something definite and -- or is it related to relying upon the one vendor going out and coming through with the sales?

John, do you want me to take that?

Yes, I do.

Okay. I'll just talk about some of the near-term traction I think we're showing that should give you a feel for why we feel confident about the last half of the year really growing up. So first of all, we're selected to participate with the supermajor, we talked about that, for their microseismic monitoring. And the beauty of that one is where they're really not monitoring now, they're planning to do 100% monitoring. So that's a big opportunity for us. We also were selected by one of the largest oilfield services firms for a multi-well high-temperature microseismic monitoring project in Australia. And we envision we're going to get a lot of growth from that. We had 2 initial customers that bought systems from us. And I think John mentioned when we went out and did some of the initial tests with them, we had some minor issues. None of the issues really had to do with our equipment, but it was kind of like peripheral equipment, like the clamps that hold our things in the well and things like that and cables. There were some issues with that. Now we've put those all behind us, and the good thing is even though we had these issues, these clients have told us the data was so compelling and so much better than anything they've ever achieved, that now that they see that we've solved these minor issues, they're back in, and we're in the negotiating process for follow-on orders with both of them. And then we'll be delivering in Q2 the largest fiber optic downhole array ever, the 100-level array, and we'll be delivering that to SR2020 and expect them to be able to take that and use it to create more demand and we expect more orders from them. So they're sort of the near-term things that we see that are really going to be driving our growth through the second half of the year.

Okay. A question on GridSense. You alluded to the fact in the 10-Q that the utilities are just moving really slow and that this is one reason why you've got all these pilots going on. I wonder if you could maybe flush out a little bit more what you're seeing in the pilots and responses to the pilots?

Well, we have Joe Musanti on the phone. I'm going to throw that hot potato to him.

That's fine. Thank you, thank you. Yes, we're actually seeing a lot of positive response from the pilots. And as John mentioned, one of the areas that's getting us some more speed on the pilots is the Grid InSite software because what we have found is when we're running the pilots with the Grid InSite software, it sort of takes a lot of the bureaucracy away from the engineers as they're able to test it sort of off-line without having to go through their IT department. And a perfect example of that is the one that John talked about, the large deployment we're expecting, where that pilot -- we have that order. And the expectation is that that's going to be up and running in a couple of months for the pilot project, which is ready to be installed. The software is ready. And it also allows them to, without a lot of modifications, to get the system up and running. Because one of the things we're trying to do as we move from an engineering phase to a commercialized phase, is to try to get the systems, standard systems that have the software that the customer needs. And that is the path we believe is going to take us to try and shorten this timeframe. As the utilities don't move that fast, we're going to look at trying to move them faster through our innovation.

So it's basically -- I don't want to say it's going in the back door, but it's like going directly to the user and making it something that doesn't get anybody into trouble because you're just making it easier for the engineers to figure out that they want this.

Exactly. So they're able to get the data sort of, for lack of a better word, off-line and then use the data that we get to champion the project going forward.

And fill the business case. That's really been our problem is getting the business case because IT, at the end of the day, would fight us about access to their networks.

And so right now, I mean, there's the one that you've already talked about that could turn into something fairly major. And in the past, you've also said that it would take nothing for GridSense to ramp up if the demand is there. Do you think that -- is it such -- is it still such that these things could evolve rapidly within a quarter?

I mean, that's always the hope, and that's what we're shooting for. There are pilots that we're expecting to come to fruition soon. So yes, that could happen. And from a ramp-up point, if you're asking from an operational point of view, we're in the position to be able to do that with all of the improvements we've made on the operations side and with our suppliers that we have.

But generally, what we see, Rudy, is we'll see signs of -- I don't think they'll catch us by surprise, at least not -- there's usually not positive surprises. They'll come in, and for example, we have one major utility coming in and doing a factory inspection, and I believe we passed our second ISO certification test. And so we'll have warning signs, and they have to get things in budget, so generally what we -- generally, we can see a path to when the orders are going to come in. So we've got lots of pipeline. It's just a matter of when do those orders hit.

Right. And you actually see there's a significant increase in communication and paperwork as the projects are moving to get to the order point of view. So we're well aware of that happening.

Okay. And then one last question. John, you alluded to the fact that you hope that OmniMetrix gets to 10,000 units by the end of the year.

10,000 additional units, I should say.

Additional from now, that's right. I mean, that was talked about in the last call as well. Can you just maybe outline what's going to get you there, what's happening with your sales channels, your distribution right now?

Deena, would you like to take that question?

Sure. Yes, so we are rapidly adding to our sales staff and contacting all of the manufacturer/dealers throughout the country, developing relations with ones that we haven't had in the past. We're also ramping up our residential dealer sales because that's where a lot of the volume can grow rapidly. So the goal is as we show the value to these dealers, that they will add these units to their existing preventative maintenance contracts that they have with their current customers as providing better service, and they can by driving the trucks and visiting the sites. So many of these dealers already have thousands of preventative maintenance contracts that their livelihood and their business depends upon the renewals of those contracts. That's where they make most of their margin. So we are showing them a path where they can utilize our product in their business and gain value from the economic perspective of saving money by using our product plus offering their customers a better service package in this preventative maintenance contract. So they'll be able to compete for that business and gain that renewal business. So as we're seeking out dealers and sending that message to them and as they're getting that message, many of them have large volumes. One that we just added this quarter -- first quarter was a large amusement park, where one dealer had 200 -- a customer with 200 generators. So we added all of them at one time. So that kind of volume launch is what we anticipate happening as these dealers understand the value proposition and the -- the value to their customer and to their own business with the use of our product. And we're seeing that it's now being requested by a lot of the end users, as well as dealers. Again, technology in this industry has been slow to evolve because many of them view rolling trucks as their revenue stream, but we're able to show them a useful way to better their business and to grow that volume for us.

That's very helpful. Just a clarification. I think in the 10-Q, it talks about you've had a promotional effort going on?

Yes.

And could you maybe clarify how big that is or if you're still doing it or what you saw the result of the promotional effort?

So at some of our earlier conferences and trade shows that we had in the year, again, we're trying to -- our belief is that we want to get the dealers addicted to the data. So we believe that this will start rolling out very rapidly once the dealers see the momentum that they can get in their business. So we launched a "Buy a 12 months of data and get 6 months free" was the concept there. We're already doing the razor/razor blade concept, where we're actually giving the hardware away for exchange for a commitment on the data. So that promotion was well received. We did see a lot of dealers take advantage of that promotion, and we're going to be trying new ones as we go along to see what works best.

I would like to point out that one of the dealers that we just landed is, I think, Generac's largest residential dealer. And they committed 1,000 units to us this year, so that's an example of sort of the lumpiness that can occur.

Our next question comes from William Bremer from Maxim Group.

Let's stay with OmniMetrix right now. Can you just sort of walk us through, since this is sort of a monitoring type of scenario, the economics and how that proceeds through to revenue?

So again, the hardware we are shipping in exchange for a 1-year, prepaid in advance monitoring commitment. So we are actually breaking even in about month 9 on that, but we're actually receiving the revenue for that upfront. So when we ship a unit, we have enough in hand to pay for the cost of the unit and then make a small margin for that year. So obviously, our growth and momentum will occur upon renewal. Now the renewal years is when it really gets sweet, and that is that we have probably a 90% margin on the data cost of those renewal years. And our overhead or our infrastructure cost is really -- in that first year, tech support with installing the units is where a lot of our in-house cost happen. Typically, after it's installed, we don't have a lot of support cost for that units. So our data cost is basically the majority of our cost moving forward, so the growth will -- the margins are great once we get the units installed.

Okay. Is there a limit on the scale between what you are monitoring? I'm assuming this is for both oil and nat gas units.

The majority of our growth is going to be in the power generator -- backup power generator monitoring business. We do still have the oil and gas product, and that's similar to GridSense's utility sales cycles. Those are pretty chunky. We have a large customer right now that makes up a big portion of that industry in that product line and they are continuing to order and it's a very profitable business and it's a pretty hands off, there's not a lot of work involved in supporting that business. So we like that business; however, we really see that the growth potential is in the power generation side because of the opportunity there and that the sales cycle is much lower than in the oil and gas.

One question that was asked to me was what percentage of the $530,000 of first quarter revenue, $163,000 of that was equipment revenue and $370,000 was recurring revenue from monitoring. So it's a pretty healthy fraction.

Okay. And then my follow-up is, you actually own the equipment. So if a client decides to terminate the contract, you could then bring that back in house and utilize that for someone else, is that correct?

That's correct. Or the dealer can take that unit back to the dealer and they can use it on another customer.

Okay. So really, the dealer owns the underlying assets here?

Yes.

Okay, not yourselves. Okay, all right. My next question, let's go to DSIT. Given the $8.2 million in backlog, what are your projections for revenue for 2013?

We haven't made any projections. But I think that you can assume that there's going to be some nice growth in that business. It grew 30% last year, I don't think it's going to grow 30% this year, but it's going to grow.

Okay. Now moving to GridSense. With the backlog at $300,000 here, how concerned are you that we may have some -- like a mix 1 or 2 quarters until we start seeing the orders coming through here?

Joe, do you want to answer that one?

Sure, sure. I don't want to say there's concern, because we are, as we talked about, looking at these pilots and looking at converting some orders this quarter and next quarter. So we expect to see some growth over last year. And the goal we're trying to do is to monitor the order rate and get the backlog built up so that we're not running sort of hand to mouth.

Right, right. Okay.

I'd also say that Joe's strategy is that to align sales -- align costs with revenue. So that's his -- that's one of his strengths. Something he enjoys doing is putting companies on paying bases.

Yes. And I think that's just a matter of converting the business like Acorn has been successful in the past from an engineering business to a commercialized business, and GridSense is at that point right now where that is the goal. The products are there, and it's a matter of commercializing them and moving your resources to sales and marketing from -- in engineering.

Right. Joe, earlier, it was mentioned that another version of the Grid InSite will be released at the end of May. Give us a little more color of what your customers wanted and the reason for the new monitoring system. And how -- and I'm assuming that this is because of the customers inquiry that you made these changes?

Yes. And it's really just like any other software as we put these pilots out there and have -- got feedback from the customers they requested other types of data that they've asked for, whether it be averaging or logging or things that would allow them to use the software so that they're more efficient in getting the data and that they can do analytics right off the software as opposed to taking it sort of offline and being able to do the calculations. So with like any other software, it's maturing as we get a lot of feedback from the customers.

And this is pretty much customized per end user? So each one of your utilities may require some types of...

It's really a matter of the utilities just asking for different types of data. So I wouldn't say it's customized. Because once we do that change or if we accept to make that change, it's in the software. And other utilities then have the availability to use that. And with, like any other software, if there's something in there that we just want to turn off and not provide to a customer unless we want to charge them for that, we can do that very easily.

All right. I'd like to move on to USSI, okay. Were you are, it's been voiced second half of '13, we should start seeing some, a little bit more material in terms of revenue contribution. First and foremost, can you give us an idea of what the production capacity is right now? We spoke about that a couple quarters ago with the factories. I'm assuming that's up and running and ready to go. And then my second part of this question is what do you anticipate the gross margins to be in the second half as a percent of revenue?

John. Do you want me to take that?

Yes, please. Thank you, Jim.

Okay. So I'll start out that I think John mentioned that we had some testing going on and we had some minor issues, but the test we just did last month was flawless. We went in the well, we installed it, clamped it downhole, took the data, the data looked fantastic, pulled it out, all without incidents and so now we're feeling like really, really confident that we can go out, any well, drop it in and everything will work very well with no issues. So that's really allowed us to start gearing up our marketing efforts. But on the other side, we have to make sure that the part we could scale up to the demand. So we've also been setting up the infrastructure in-house, I think we've been talking about it. I think [indiscernible] in the space. We got all of the FCC, CE, UL, all those kind of certs that are required on our equipment to ship it around the world. We implemented a SAP ERP system that coordinates all the activities of the company through the software package.

That's complete, Jim?

That is complete. I mean, there's a couple of little bugs always in the software, but it's installed, implementing and operating. Even the fact that inventory, we barcode. When they pull it out of the, I'll call it the cage, it gets barcoded. So the system tracks as we use the inventory. We have automated assembly stations we talked about, and this first group of stations are designed to handle $50 million worth of revenue. And actually they are operational now. They're not -- they're about 75% complete. What I mean by that, some of the stations, there's still some parts that are performing manually. But over the next 60 days, we expect them to be fully automated but were actually in use. And then, the important part when you start talking about, I think, talking about margin is that we licensed the technology form Northrop Grumman to do this PC-based optical interrogator. This is, I call it like, really, earth shattering compared to the approach that has been used in the past in maybe other fiber-optic companies. Because most of the heavy calculations are done in a PC, and it's software-based instead of hardware-based. So it really eliminates a lot of the hardware touch labor and makes scalable that we load the software onto the PC and have some other custom boards and handle hundreds and hundreds of center channels with that. And we expect that to be released in July. So the automated assembly stations and the new interrogator reduce the touch labor 80% to 90%. And with those, we envision we have at least 50% gross margin when we start selling systems that incorporate these items. And then the last thing, I think, I want to talk about, I mean, and I think this is very important to say like we have the infrastructure in place. Because right now, we're going through approved vendor certification with 2 supermajor oil companies and 1 of the big 3 oil service companies. They send teams out, they interview our people. And that's all going through so. And the fact that we have all this infrastructure in place has made that much smoother and faster, that we could start producing production systems for these large customers.

And what -- just -- earlier you mentioned and what I've read in the past, depths of about 1,000 feet. But have you gone even further than that? Have you gone to 3,000 yet?

We've gone, yes. And the reason we went to 1,000 feet in that test we did, it was with a local well at Southern California Gas, is that the first test that we're going to be doing with the supermajor at the end of May is 1,000 feet. So we wanted to mimic that test and just do everything just like that test because we want to make sure that -- we're convinced we're going to win, better make sure everything operates properly. So we asked the -- that well was a lot deeper. We asked SoCalGas people to plug it off at 1,000 feet and then we installed the test. But we've done testing with -- I think I mentioned before, Halliburton, in excess of 1,000 feet, I think we went down 1,700, 1,800 feet. We went in the Haynesville shale recently about 3,700 feet and the reason -- I mean, we wanted to go deeper at that Haynesville test, but there were some problems in the well, there were some stuff down there that -- and there are other conventional arrays and the wells next to us couldn't get any deeper either for whatever reason in those wells. And then the recent test we did in Devine with our OEM contractor was at 3,000 feet.

Okay. And then finally, John, just in terms of CapEx sort of uptick quite materially here. What do you anticipate for the end of the year?

Michael Barth? Well, I think that's -- I mean, when we think of capital, we think of the cash that we invest in the operating businesses and that's the $7.6 million number.

I'm looking at the cash flow in which you did about $861,000, up substantially from the fourth quarter and up year-over-year. So I was just trying to get a sense, is that sort of like the run rate just for the cash flow analysis? Or are we looking at tweaking that even higher?

Michael Barth. Are you online? Unfortunately it's...

Michael signed off.

It's the Sabbath in Israel, unfortunately. So I don't have an answer. I'll get back to you on that.

Our next question comes from Ross Silver from Vista Partners.

Just one quick point, and then a quick question for you. One, it's definitely encouraging to see you and other members of management team buying the stocks, so thank you for that. And then just a question as it relates to USSI. Can you talk about what sort of competitors you're seeing and sort of the differentiation between your products and their's when you're going into some of these field tests or evaluations?

Yes, Jim, I think that one's for you. Thank you, Ross.

I will. Yes, I mean, that's a perfect question, because there is competition out there. The competition is coming from the conventional technology. And there are some fiber-optic companies out there, and I'll talk about that. But we don't view the other fiber-optic companies as competitive in the microseismic arena, because the other fiber-optic companies seem to be focused on marine seismic and 4D seismic large systems. And we seem to be the leader in downhole microseismic monitoring using fiber-optics. But the problem we're seeing is that you got these major oil companies and the large service companies, they're all viewing this unconventional oil and gas as their primary area of growth. They're all telling us that, that's where the growth is. And then they all tell us the problem they have is that they're trying to grow in that area and it's -- that's not very efficient and they think the main reason is they don't understand the subsurface. They need to improve that to get -- improve what they call their ultimate recovery. And so they're all looking for a technology that gives them some sort of discriminator. And I think we view -- and I think they view us as a potential game changer that -- as a discriminator. And one main technical point I'll talk about is the conventional technology that's been out there used for monitoring for 40 or 50 years based on a traditional geophone, has a very narrow band, frequency band, that it could listen to. And many of the experts have come out that, that narrow band misses 90% of the energy associated with the microseismic event. And the fact that we have a wider band, we could detect all these microseismic signals. So it really is just a perfect time coming out with a perfect sensor technology for explosive growth happening in the oil and gas industry. So as far as when it comes to competition, primarily from conventional, but we know every time we've gone downhole against a conventional system, it's not like we're a little bit better. We're 10, 20x better which is shocking to the people when they see the data. I hope that answered your question, but let me know.

So is there something where your competitors are seeing, hey, there, you are so much further ahead of them in terms of sensitivity and other areas and they're trying to catch up to you? Or I mean, that's what it sounds like, right?

Well, I mean, the conventional technology, just the physics won't allow it. They have a magnet and a coil it could only move so fast, and then you start having spurious resonances. So if you try to get higher frequency out of those, it's just not possible. And then as the MEMS technology that came out, which turned out to be fairly expensive. This is a micro machined accelerometers, but the noise forms too high. And also on the low end, their sensitivity is very low at the low frequency. Interesting that we're going out to install in this test with the supermajor in May, but 2 of the 5 wells, with product in it, are us. We're going in one well and we're doing an OEM product for another company, and they've been selected to go on one of the other wells. So we're 2 out of 5 going into that test. So -- and there's another fiber-optic company, that is in the one -- third well. It's a new company, came on board and developing technology. But yes, years behind us in technical progress. So I don't view that as a threat. And then there's a couple of what is called distributed acoustic sensing systems that use fiber-optics. Some people view that as competitor. Really, we're on the order of 10,000x more sensitive than those distributed acoustic sensing systems. We've been downhole in a couple of applications with them. It's a night and day difference in the data, so we envision, we don't see any problem there. So if our system performs as it did at the test we did with the same equipment that we're going to be putting in the well in the end of May, if it performs like it did in the local test with the Southern California Gas, I think we're going to be head and shoulders easy selection process for the oil company.

Our next question comes from David Duley from Steelhead.

Just a couple of clarification points. Real quickly, is the interrogator software on track for mid-year rollout?

Absolutely. So I think -- well, I mentioned before that we built the hardware, and so we're going through the process now of software and software integration. We were seeing a little slip in the schedule. So brought in another software engineer to patch that up. I think we're getting back on track, and I feel confident that in the July timeframe, we'll have the product ready for release.

Okay. And then, earlier, you talked about the cost per well of the standard or the conventional technology being about $60,000. I guess I'd really just like to try to dwell a little bit deeper per level. What is this -- can you help us understand what these guys are spending now per well on monitoring technology versus what they would have to spend with your technology?

Well, right now, only a single-digit percentage of the wells are actually being monitored. And the technology they're using is the conventional technology, which has a price point that we discussed, about $60,000 -- $50,000 to $60,000 per level, where ours is on the order of 20 -- about $20,000 to $25,000 per level. So only maybe 3% or 4% of the jobs are being monitored, and we think it's due to 2 reasons: one, is that the cost is just too high for that technology; and two, is, like I said before, it's really not fit for monitoring microseismic, it misses 90% of the energy. So and I probably should add a third one is, about half the wells that need to be monitoring are high-temperature and, we're the only company out there with a high-temperature product. So when it comes to what are our cost and value, I think it's clear. We're significantly lower priced than the conventional technology, but it still allows us great margins. But I think it's going to open up the number of percentage of wells being monitored because of the fact the price point is significantly lower, and plus it's fit for the purpose. When you're missing 90% of the energy associated with microseismic events, it's hard to justify spending all that money to monitor. So with our product out there and the people actually see it -- because the people that have actually put it in their wells and tested it, I've used that term before. To them, the data is so compelling that even though we had minor issues, they're coming back and talk to us about follow-on orders.

So a dollar number on the 3% to 4% of wells that are using the conventional technology, what is the dollar figure in millions of dollars that they spend per well to monitor with the geophone? I'm just trying to get...

So a typical system that's a 100-level sells for about $7 million. And if they require, say, 3 100-level arrays, that'd be $21 million. That's for the hardware, the equipment.

So I guess that's the key reason why it hasn't been adapted on a broader scale at this point.

Right. Yes, it's so expensive.

And let's just say that you can get your cost, whatever your cost is, 1/2 that or 1/3 that, as some caller mentioned earlier, $10 million per a set of, I guess, 1 vertical well with a bunch of frac-ing jobs off of it, stages off of it. What -- do you have some sort of guess at a return on investment? Because it's all going to come down to dollars and cents at the end of the day.

Absolutely. Yes. And so what the operators are looking, you see numbers like, let's say, you're going to do a 10-stage frac. And for, say, a given well, 75% of those frac stages don't produce anything. And so if they could eliminate and frac where they want to frac or position the lateral in the proper position within the shale field to -- that they could get more oil out, all of the oil companies have done that calculation and they're telling us as we go, "That seems kind of expensive to us that you're going to put this many wells with this much equipment." And they go, "You know what, we're getting probably like less than 10% what we think we should be getting out of the field, and we feel we're just throwing money away by moving and doing it and then moving into the next one, and we have all these assets and we want to be able to improve the ultimate recovery." And if they could get that, double, triple, 4x as much, get up to 30%, 40% recovery, they see that, the cost of the monitoring, is in the noise.

Our next question comes from Charlie Sloan from Mid-Continent Capital.

I just want to thank the board and commend the board, echo the sentiment earlier about keeping the money intact on the balance sheet for the future investment of the company. Because what -- it's been a long investment cycle and still there's more to do. But as I listened to Jim undersell his product, I can't help but think that we're at least on the cusp of what we've been looking for in terms of the market development on US Seismic. And then certainly at OmniMetrix, it appears that, that is just a growth opportunity without too much -- so many hurdles in its way. So anyway, we're very pleased that you kept the cash on the balance sheet.

Thank you, Charlie. You've been very consistent in that opinion and I appreciate it. We've -- it was a controversial decision, but I think it was the right one.

Yes. And then second, so should we see on the balance your unbilled revenues going up? We should see that continually going up, correct?

That is right.

Current assets, is that due to mostly OmniMetrix?

Yes.

Yes, yes.

Our next question comes from Gavin Richey from Rockwood Investment Partners.

On the USSI sensor, how far away can the sensor detect as the crow flies? How close does the sensing well need to be to the construction well?

That is -- I'm sorry, John, can I take that?

Please.

Okay. Yes, that is yet to be determined because I'd give you an example of a test we just did with -- at the Devine test site in Texas. This is the University of Texas borehole test facility where a high-frequency sparker array was put in a well about 500 meters from our sensor that we're looked and dropped in a well that's about 3,000 feet. And then in close proximity to us, they had another system that is the most sensitive, digital, geophone system on the market, and that's actually 4x more sensitive than the traditional. And so that was in a well right next to us. When the sparker was energized, putting sound into the ground, we detected that wall-to-wall like gangbusters, tremendous signal. And the high-end sensitivity system sitting next to us of the multiple channels that were in the ground, on one sensor channel, detected a slight amount of the signal. So it was like night and day difference. And that's why -- and so the industry standard says, you should be that's why, this has sort of picked up, you should be within like 1,500 feet of the microseismic event in order to detect it and that's why we are like about 1,500 feet away. And with the most sensitive thing out there, it barely detected it. And we're detecting it. I mean, it just filled up the screen. So it's yet to be seen how far away you can do it. But with -- at the industry-standard limit, which typically, people say you have to be within 1,500 feet, we get huge signals. So I think we could drive that to make it be much, much further away and that's less expensive drilling cost with shallower wells. So we expect to see that as we move on.

And then earlier when someone was asking about the -- how many arrays need to be around a production well, I think you said 3 per vertical pad? What do you mean...

Yes, typically -- I mean, because if you're trying to triangulate on a spot, it's kind of like you guys that are maybe sailing and stuff, and used to doing fixed, like celestial fixes and stuff. In order to pinpoint something, you need 3 locations, right. A fourth helps, but 2 is -- doesn't give you confidence. So you need a minimum of 3, but we've seen people do 3, 4 and 5. So it seems like the supermajor are working with fields that numbers 4, but it varies with the operator.

Is this for horizontal use though or for vertical wells? You said a vertical pad, and so I wasn't sure...

I mean, what we're going to do with this -- the supermajor oil company is vertical. We are working with some companies that want to go on horizontally, meaning what they intend to do is put the array in an adjacent lateral while they're frac-ing it, and so they'll be within like 400 meters or so of the fracturing event when it happens. And then also, they feel they don't have to drill another well, because the well's already there. So there's so many people with different strategies and we could fit and apply ourselves to all of them.

Our next question comes from Don Steinkamp from TSC [ph].

Well, I've been watching the -- a lot of people on the call, which is good. And I've been watching the progress of the stock this morning and it's -- it looks like it decided to move up to the 200-a-day moving average and maybe we will have some activity. One thing I wondered was will you be doing any underwriting for funds. Do you have plenty of funds or do you need funds? Or do you want funds? And so forth?

Well, we don't usually comment -- we don't comment publicly on our capital raising strategies. But we have said that we've got enough capital to last us into 2014. So I think, that being said, we're very proud of the fact that we only [ph] raised $16 million to create what is today $130 million of market cap. So...

Yes. I'm so very impressed and I'm happy with my investment. And then another question is the utility company seemed to be dragging their feet. Is that so much talk on the TV about power grids and so forth? Is there any chance that there'll be a -- some sort of a major change in policy and that sort of thing?

That's really the reason why we made the investment in OmniMetrix, because we felt that the private sector is better at making quick decisions about protecting themselves from power reliability problems. But what we're seeing is we're seeing a lot of traction overseas. I'd say probably half of our pipeline is from major overseas utilities.

Is that right? In Europe or other places?

Yes, yes. Countries you rarely hear of, but that are serious about upgrading their electric grids. So it's good to see seriousness around the world. And the U.S. seems to be willing to continue to -- yes, just kicking the can down the road.

Well, that's interesting, okay. Is there any likelihood of a big event, a big order that will boost the company's status in sales?

We are always optimistic, but we haven't -- we'll -- you'll -- we'll press release it when it happens. But each -- that's the benefit of having 4 companies is that your -- we're constantly working on big projects. Thank you so much for your call and your questions. Thank you, Don.

And our last question comes from Frank Barresi from Ameriprise.

I -- just going back to the cost per well. You're talking about on this situation with the supermajor, you have 4 monitoring systems that cost like -- would cost $2.5 million apiece. I mean, that's their plan. They'd be talking about $10 million worth of hardware, correct?

That's correct, yes.

Okay. And then -- and that's per pad?

Yes.

I mean, how far away from the pad would these monitoring systems be? I mean, at least the way they're thinking about it now.

They've drawn pictures and we've seen it. I don't recall the distance. But I would assume if they're doing the laterals and laterals are spaced maybe 300 to 400 meters, so -- and you have 4 of them. So I'd say these arrays would be placed in the corners, let's say, more like a rectangle. But from across the well, there might be a mile distance between the 2. And then in the lengthwise, it might be a little longer, because there'd be straddling the laterals on the other side of the vertical. I don't recall them giving up the actual dimensions, they just kind of -- and maybe they're keeping that to themselves.

Okay. And then -- so a well like their -- they think that they can increase the -- you were talking about their hope is to increase the amount of oil and gas produced by threefold or something, did you say?

Huge amounts.

Yes. I mean, they envision they're getting -- the numbers they mentioned, like 10%, 11% of what they're expecting to get. So that they really think they can improve that tremendously. So how much? It's -- we're yet to see, but they're convinced that doing it blindly, that they're not optimizing, getting the ultimate recovery they're expecting.

Okay. And then if a 20-level system would do the job, would be adequate, instead of $10 million, how much would a 20-level system cost? I mean...

It would be on the order of -- so that would end up being 4 20-level systems and they -- somewhere in the order of, say, $1.5 million to $2 million for all that instead of the $10 million.

Because a lot of the cost -- I'm sorry.

No -- and we envision, but we'll see. We envision that once they perfect it that the gains from the 100 level, it just -- cost-wise probably doesn't make sense. So we think when they actually do the rollout, it would end up being maybe 4 20-level or 4 30-level systems per well pad. But still, it's going to be a tremendous scale up for us because they're doing on the order of 40 wells a month right now.

Okay. So -- but 1/5 the number of levels only reduces the cost by something like 20% to 40% then?

Yes, I would say it's like -- it actually reduced it from a 10 level -- I mean, $10 million per thing down to -- so it's about 1/4 of the cost, right. So instead of spending $10 million in equipment per well pad, you'd do like a couple of million dollars. So it's 1/4 to 1/5.

Okay. So from -- you think the cost would go from $10 million to about -- say, how much again was it? I'm sorry, because...

In the order of a couple of million dollars. Because you're talking about 80 levels at $25,000 per level and...

Okay. I misunderstood a bit, but okay. And then the -- how much is the -- typically, on these kinds of wells, how much are they spending per well now, Jim?

Well, what they told us. Because we are concerned, because we are talking about the pricing and we go, "You're drilling these monitoring wells, and they told us that these monitoring wells are going to cost on the order of $5 million each for the monitoring wells." So they go -- so the fact that our equipment is less than that, they're pleased with. Because they said, "If we use conventional technology, the cost of the monitoring wells -- I mean, the cost of the equipment would be $7 million or $8 million, which would be more than the cost of the well." So they seem to be happy with our price point.

Okay. And so I was just wondering, do you know how much -- besides they're not monitoring now, but how much are they spending just drilling the well? Just try to understand the...

Yes, a typical like a well and once -- one lateral's on the order of about $6 million to -- I think, $5 million to $8 million, of which $3 million of that is just the frac-ing. It's typically -- it's a 10-stage frac. Every stage is about 300k, so the frac-ing itself, for the 10 stages is about $3 million. So that's where they say if they could cut that to the 10-stage frac and get the same amount out with just frac-ing 3 stages, they save a ton of money.

So -- I apologize, we're coming up on an 1.5 hours on the call. One last caller, Joel Sklar. Joel? Thanks. You can get directly with Jim if you have any more questions.

That was a absolutely tremendous article in Forbes, so Kudos on that. I think you really did a great job explaining the shale opportunity. I'm going to go on a little bit different direction with USSI. A couple of questions for, well, for John or Jim, however, you want to field it. But the first, very just sort of an ignorant question, about the -- I guess, about the use of geophones today in exploration. Now given that your fiber-optic geophones or not only are superior but also less expensive than the old conventional geophone, why wouldn't those -- your geophone just completely replace the existing geophones that are still currently used for, I guess, oil exploration? And then the second question is, Jim, I'm going to ask you to go, I guess, a little further out in the future and I do understand the wonderful opportunity you have with shale and the unconventional petroleum markets. But for the more conventional oil production and especially the 4D and then Marine seismic, wouldn't there be an opportunity for your fiber-optic sensors in those markets as well? And I'm talking longer term, because I do understand why you're focusing on shale today. It's certainly is a wonderful opportunity in the low-hanging fruit. But so I'm really asking longer term, couldn't there be a similar opportunity to upgrade the equipment being used for, once again, the 4D or conventional oil production, as well as marine seismic?

John, do you want me to take that?

Yes.

I mean, absolutely, you're correct. And -- but we made a sort of like a strategic decision here, like a few years ago, to capitalize upon the shale gas opportunity first, because it's such a high growth and a revolution going on, but the other part, it fit our ability to produce products based on our size. In other words, a typical marine seismic array requires on the order of 25,000 sensor channels and miles of cables. And typically, one installation, that equipment might cost $20 million or $25 million. We just felt like we weren't at the point where we could produce at that level, but we'll eventually get there. But the microseismic, a large system for microseismic is 100 levels. Typically, it's 20 to 30 levels, which is stuff we could do now and crank product out the door. And then once we get to the point where we feel we have the interrogator online that can handle hundreds and thousands of channels in a small box, and we have the automated equipment placed to scale up the build thousands and thousands of sensors a month, we can go after the large ones. Because you're right, the number of geophones that are sold right now, every year is on the order of 20 million. So we'll eventually go after that, but we're going to have that after we get traction and start to become the leader in the microseismic and unconventional fields.

And I'll just lastly add to that, that Royce Nelson, one of the founders of Landmark Graphics is consulting us. And he's one of the vendors of 3D seismic, and they made the decision not to go after the 2D seismic market, but to actually go after to create great a new demand for 3D seismic, because the guys who are working with the colored pencils, once you're working -- once you're sort of walking down the cow path, it's hard to get people to change what they do. So the shale industry has a real pain point and it specifically addresses the high frequency and the very low frequency capabilities that we have that the other sensors don't have. So we just think it's a natural place to go. Thanks, Joel. Thanks for your questions. And I think that's our last question. So we had 99 people on the call. So I guess, we'll turn it over to the operator.

Yes, sir. The questions have all been answered. And I would like to turn it back to you for any closing remarks.

Well, first of all, I'm just grateful for having so many great questions and so many fantastic people on the call. And thank you for your patience and your support and passion for what we're doing. And I'm -- I couldn't be more excited about the future of the company. Thank you, all, very much.

Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending. You may now disconnect your telephone lines.