Good morning. I will be your conference operator today. At this time, I would like to welcome everyone to the Dawson Geophysical Third Quarter Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator instructions). Thank you. I’d now like to call over to Mr. Steve Jumper, President, CEO. Please go ahead, sir.

Good morning and welcome to Dawson Geophysical Company’s third quarter 2010 earnings and operations conference call. My name is Steve Jumper, President and CEO of the company. Joining me on the call are Christina Hagan, Executive Vice President and Chief Financial Officer; and Decker Dawson, Founder and Chairman of the company. As in the past, today’s call will be presented in three segments. Following opening remarks, Chris will discuss our financial results. I will then return for an operations update, then open the call for questions. As is customary for us, the call is scheduled for 30 minutes and we will not provide guidance. Just an opening, I would say that we are pleased with our third quarter results. This is our best quarter in terms of revenue and EBITDA since the second quarter of fiscal ‘09 when the effect of the financial crisis of late 2008 begin to take hold and seriously affect demand for our services. This is our third consecutive quarter of positive growth and revenue, EBITDA, demand channel cap and channel deployment. And needless to say we’re feeling pretty good about where we are in terms of demand and opportunities going forward. So at this point, I would like to turn control of the call over to Chris Hagan, our CFO, to discuss our financial results.

Thank you, Steve. First, let us go over our Safe Harbor provision. In accordance with the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995, Dawson Geophysical Company cautions that statements made today in this conference call, which are forward-looking and which provide other than historical information involve risks and uncertainties that may materially affect the company’s actual results of operations. These risks include, but are not limited to, the volatility of oil and natural gas prices, disruptions in the global economy, dependence upon energy industry spending, cancellations of service contracts, high fixed costs of operations, weather interruptions, inability to obtain land access rights of way, industry competition, limited number of customers, credit risk related to our customers, asset impairment, the availability of capital resources and operational disruptions. A discussion of these and other factors, including risks and uncertainties, is set forth in the company’s Form 10-K for the fiscal year ending September 30, 2009. Dawson Geophysical Company disclaims any intention or obligation to revise any forward-looking statements, whether as a result of new information, future events or otherwise. During this conference call, Dawson will make references to EBITDA, which is a non-GAAP financial measure. A reconciliation of this non-GAAP measure to the applicable GAAP measure can be found on Dawson’s current earnings release, a copy of which is located on the Dawson’s web site www.dawson3d.com. Today, we reported revenue of $61,178,000 for the quarter ending June 30, 2010, our third quarter of fiscal 2010, compared to $52,319,000 for the same quarter in fiscal 2009, an increase of 17%. Net loss for the third quarter of fiscal 2010 was $1,019,000 compared to a net loss of $1,626,000 in the same quarter of 2009. Loss per share for the third quarter fiscal 2010 was $0.13, compared to loss per share of $0.21 for the third quarter of fiscal 2009. EBITDA for the third quarter of fiscal 2010 increased 32% to $5,591,000 from $4,245,000 in the same quarter of fiscal 2009 and from $2,488,000 in the second quarter fiscal 2010. Revenues in the quarter continued to include relatively high third-party charges related to the use of helicopter support services, specialized survey technologies and dynamite energy sources. The higher level of these charges during the third quarter was driven by the increased demand levels for the Company’s services in areas with limited access. And we remind you, we were reimbursed for these expenses by our clients. Our balance sheet remains debt-free and we have approximately $85 million in working capital. With that, I’ll turn to Steve.

Thank you, Chris. And Chris mentioned our third quarter highlights include a 32% increase in EBITDA up to $5.5 million, when compared the same quarter of fiscal ‘09. A 17% increase in revenues to $61 million, compared to the same quarter of ‘09. We redeployed crews in the second quarter of ‘10 and a third crew at the end of the third quarter just recently in June. We’ve been awarded new contracts and utilization all over the U.S., but particularly, several large projects in the Haynesville area of East Texas and Eagle Ford area in South Texas. And we’re seeing an increased demand for services which is leading to improve utilization rates. Chris mentioned our debt-free balance sheet with $85 million in working capital, and approximately 124% increase in EBITDA when compared to the second quarter of fiscal 2010. In response to increased demand, we redeployed additional crew in June. We now operate 12 crews in every major basin throughout the U.S. Utilization rates continue to improve from what we experienced in the recent quarters, particularly, the first quarter of 2010. Although variable wet conditions in May and June across areas of the country continue to negatively impact our utilization rates and quarter results. More balanced portfolio of oil and natural gas projects, combined with geographic diversity in continuing operational efficiency, further contribute to our stronger Q3 results. The third party reimbursable charges for the quarter remain at very high level as a percentage of revenue. The percentage increase is related to lower crew revenue but, more importantly, reflect, as Chris said, an increased activity in areas such as the Marcellus, Haynesville and Fayetteville shale basins which require more preparatory work in lead time than many other regions of the country. Demand for our services remained steady and is greatly…

Thank you. (Operator Instructions) And our first question is from the line of Collin Jerry (ph) with Raymond James. Collin Jerry (ph) – Raymond James: Hey, good morning. Well, Steve, it sounds like you’re a little bit more, I would call it cautiously optimistic, just kind of your tone about the order book moving, getting some day rate work as opposed to turnkey and maybe having a little bit of weather slippage announced last quarter that things are picking up. Is that a fair characterization of how you’re seeing things? And I guess, to add, on top of that, you mentioned how your competitors are moving to the multi-client model, I’m wondering has that effectively tightened the capacity situation in North America, so where maybe their proprietary market could see some pricing that you mentioned is still pretty low?

Well, we are optimistic. I think we’re seeing some very positive signs in the North American market. We’ve talked about it for several quarters of continued activity in the shale basin, particularly natural gas shale basin at Marcellus, the Haynesville, the Fayetteville. We’re actually sending increased activity in the barren end which I think many people felt was a shut up and dead. But we’re seeing increased activity in some of these more oily basins, oily shales. Our order book is strengthening with project of various sizes which allows us to maintain a higher utilization rate and avoid downtime which was really the issue we were facing particularly late fiscal ‘09 or early ‘10. And so, we are optimistic. I think cautiously is a fair statement. We still don’t know what the overall economic conditions are going to look like going forward. Certainly for the last several quarters, Collin (ph), we’re beginning to feel better not just about our company and our workbook but the overall state of the industry, I think, is showing signs of growing. The multi-client business is out there. As we’ve talked about in the past, it is not a business model that we currently pursue. It’s very similar to the proprietary market in that some projects work very well and some may not work well. And it’s certainly a factor of location, underwriting and how things are accounted for. I do think it is helping with the capacity issues. It is a competitive market for us but I would still caution that there is still some overcapacity still in the lower 48. I don’t think we’re by any structure the imagination fully-utilized across the lower 48. But nonetheless, we’ve been able to see growth in our order book and we’ve got demands and requirements that…

I was just about to say you sound like you’re trying to pick me into some guidance here. But you do have a good question. We are running margins that are 11%, 12% range and I would throw a couple of things at you. Number one, if you could model what the reimbursable expenses are going to be, Collin (ph), then that’s going to greatly impact what our margins look like going forward and that’s a very difficult thing for us to do. We are running at a third party reimbursable rate right now. That’s the highest we’ve ever had and we’ve always said that we’re in the 25% to 35% of revenue range and we are well-exceeded that. And so that is related to two things. One, we’ve had lower revenue on the crew side. But two, it reflects the increased activity in places like the Haynesville, the Fayetteville, the Marcellus where we have to have all the third parties that Chris talked about earlier. So I think that is having an effect on the margins and I think as proved revenue begins to increase and we begin to prep on areas that aren’t necessarily the Marcellus, Haynesville and Eagle Ford and those third party charges, do drop a little bit as we balance out the activity levels, not as much preparatory work. I think you could see a shift in margins that may or may not drop to bottom line. Does that make any sense at all? Collin Jerry (ph) – Raymond James: No, that makes ton of sense to me. I didn’t, I mean, the fact that third party is the highest that’s ever been, it’s well exceeding the prior range that you kind of talked about. I mean, that kind of truce up a lot of the numbers at least in my head.

And the other thing is we are going to have some day rate stuff. When we were back in what you call the heyday, we were about a 50-50 mix and that’s where we were comfortable. You get upside potential and you get some downside protection, hope, will we get there or not? I don’t know but I still think we’re down to weather and permits and availability and let’s not call it permits. Let’s call it availability of ready projects and I think our contract mix and our order book is such that we’ve seen a continual mitigation of that risk related to permits. And we’re not having downtimes of weeks at a time on – we had nine crews working, I called it a soft nine. Now we’ve got 12 working and I will call it a stronger 12 just based on the order book size and diversity. We’re still going to have a weather issue. I think even though we’re getting some contract terms as we’ve always said even in your comment of a heyday, weather’s always an issue and it’s never fully mitigated. So I think you’re thinking along the right track without me giving you any numbers and confirming any estimates that you’ve given. Collin Jerry (ph) – Raymond James: Last one for me is, I guess, I’m trying to understand if we can get into the head of your customer a little bit better. When approached if you’re drilling in of these shale plays, when approached with the prospect of a multi-client versus doing your own proprietary work, how, obviously there’s a cost trade-off and you get to keep the data kind of a trade-off, I guess, I mean, could you walk us through, has the customer like shipped in? Have you seen of your customers go exclusively from proprietary, the multi-client or is there a tendency for the majors to go one way versus the other? I mean, maybe just help us understand how your customer is thinking now that it’s – both sets of data are available?

Well, both sets of data have always been available and so this has been an issue that the multi-client, some of the multi-client data library providers are our customers. And we work for companies that provides that service and there is three or four minute (ph) particulars that we would consider very, very strong. And important cost, too is we maintain relationships with all those – I don’t think anybody goes exclusively one way or the other. I think it has to do with location and what’s being done in the area and what opportunities exist for both the ENC (ph) company and the provider, the multi-client data library. And so I don’t think this models anything new. I just think some of these shale basins are areas where the model is starting to be a little more effective, not a little more effective, they use a little more. Now our situation, Collin (ph) is we’re not in the business of selling data. We’re in the business that’s helping our client find their oil and gas. And we maintain very strong relationships with all of our clients and we’re in a position that we help them not just design the survey but permit it, require it, process, it’s a whole bid. And so I think our order book strength reflects the fact that we’ve been able to maintain our client base and maintain those relationships and I think it’s just more of a more situation of opportunities for both sides of the multi-client business, the provider and the user than it is just a desire to be one way or the other on the ENC (ph). Collin Jerry (ph) – Raymond James: Okay, great. Thanks a bunch for the help. I’ll turn it back.

Thank you. Our next question is from the line of Luke Lemone (ph) with Capital One. Luke Lemone (ph) – Capital One: Hi, good morning. Steve, just trying to dig a little more into your order book, could you give us some color, possibly on the contract wings (ph), crew size and number of contracts in the Haynesville and the Eagle Ford?

Oh, we’ve got – most of the Eagle Ford and Haynesville stuff and the Marcellus stuff just, and the stuff in the Western U.S. will require higher channel camp crews. So we’re going to be operating four crews in excess of 10,000 channels. One will be touching 15. We’ll be operating some crews with about 5,000 to 6,000 channels and then we’ll continue to have two of the smaller channel camp crews, one working in the Marcellus and one continuing to work in the barren end (ph), the project sizes and the Eagle Ford tend to be larger. The Haynesville project is larger. When you get to the Marcellus, we can have project sizes from anywhere from 20 square miles up to let’s say 80 square miles. And so we’ve – the course is stuck in barren end (ph). There’s a lot of activities in the barren end (ph) and all of that work tends to be very small, 10 square miles or less or so. So I think we’ve got a pretty, pretty good mix all the way across the board in terms of crew size, project size and a number of projects. The actual number of projects, I don’t have for you, Luke. But I’m not sure that that number really is reflective of anything because the diversification of size, geographic mix and whether or not they actually shock. Right now, what we’re reporting at firm commitments, our contracts are cancelable on very short orders. So maybe that’s the color you’re looking for. I’m not sure. Luke Lemone (ph) – Capital One: Yes, that’s helpful. And lastly, with your order book at these levels, since you haven’t seen since the fall of ‘08, it’s a pretty good likelihood that we could see a couple more crews redeployed by your end?

Oh, I don’t think so. I think we’re just getting projects ready, getting up, getting the 12 from the field has been an undertaking here of the last 30 days or so. It’s very difficult to predict the crew count. I can foresee a situation where we have some things with very, very short timing – timing issues that we may have to deploy small crew from time to time to get something shock. But right now, I think we’re pretty steady with the 12 and I think we’re in a position we can keep them working fairly steady. And Luke, as I talked about in the past, even back in ‘07 and ‘08, I’m not sure where our crew count will actually end up. What’s important is our channel count utilization continues to climb. And so we have, we’re almost fully deployed, not caught, but almost fully deployed on ARAM and I/O RSR (ph) channels, even with the crew count down to 12 and I don’t know if we’ll ever get back to the 1 or 14 but 12 feels pretty good right now. In response to your comment about the order book, or I guess it’s my comment about being how strong it has been since 2008, in the fall of ‘08. Everything’s relative. Order book strengthening is getting better but it’s certainly not the level that we had in ‘06, ‘07, early ‘08 time frames. So what we’re saying is positive growth, positive thing, positive signs going forward and I guess here in about 90 days, I’ll report it back to you and tell you how it went. Luke Lemone (ph) – Capital One: Okay, that’s it for me. Thanks.

Thank you. Our next question is from the line of Neal Dingmann with Wunderlich Securities. Neal Dingmann – Wunderlich Securities: Say question, you were talking about moving over more for the day rate, was trying to get a sense of kind of where is that breakeven point if we’re looking at that on a margin sort of basis, at what point do you have to get where makes sense or it becomes more profitable for the – you’d rather have day rates going forward?

Neal, I don’t know that we have a preference either way, to be honest with you. I think in 2007 and 2008 time frame, we were 50-50. And I don’t know that that was by any great design on our part if that’s just the way the market was reacting to capacity issues. You kind of want to be day rate in certain parts of the country. In other parts, you can handle a little more risk. We do have a couple of day rate projects. They’re in front of us. I don’t know that there’s any correlation between our profitability or our results to contract cut. I think given the weather condition, stability, if we get good weather and good permits, I think we have a chance to do very well under either contract. And so I don’t know that I could give you an answer and I’m not trying to avoid the question. I just don’t – Neal Dingmann – Wunderlich Securities: So Steven, does it have a lot to do with the past true cost? I mean, if you’re out east and you’re shooting dynamite (ph), you’ve held on top, I mean, you prefer on those to do?

Well, I think you want to be or you would like to be in day rate contracts where there is more access issues, where there is more unpredicted – lack of predictability on operational efficiencies weather permits, those kinds of things, I am in no way want to lead anybody to the idea that the market is so strong, that we’re going to be 50-50 day rate turnkey. We do see some day rate things coming back but they’re in isolated areas and isolated circumstances, I don’t think it’s a reflection of the market as a whole. Neal Dingmann – Wunderlich Securities: Got it, and then last question, like the crew that you added in June I was wondering now are you going to see some more mobilization, you’re going to be moving more of the crews over towards, I don’t know either the Niobrara or Bakken or some of these areas, from the Barnett or Fayetteville, I’m just wondering.

Well it’s a fairly seasonal issue, I think now we’ve got quite a bit of work in the Eagle Ford and so we’ll have some activity down there and that’s an area that like fall, winter from November to January you have to be out of that area due to other operating issues and then you back east you’re going to have some weather issues and certainly in the winter time and that north you’ll have some, the Bakken will have some weather issues and so I don’t know see any great mobilization issues coming up probably until the first quarter of ‘11, the November timeframe I think we’ll see quiet few moves relocating but right now I think we’re unless things change we should be fairly steady for a while. Neal Dingmann – Wunderlich Securities: And now –

We have two in the Marcellus; we have three in Barnett, one in Oklahoma, headed to the Haynesville, one in – two in the Permian Basin, two in Wyoming and two down South Texas (inaudible). Neal Dingmann – Wunderlich Securities: And are you getting up bid activities considering that 13th and 14th yet?

Not yet. Neal Dingmann – Wunderlich Securities: Okay.

As I said earlier, I don’t think unless there is just a very small crew deployed to pick up some things it may have time initiatives, I think we’re pretty comfortable with the fact that we believe and given the strength of the order book and the permit situation that we can keep 12 working through into calendar ‘011. So I don’t have any great desires to continue to increase the crew count at this time. Neal Dingmann – Wunderlich Securities: Would you have the crews available to add small 13th if you had to?

Yes.

Thank you. Our next question is from the line of Veny Aleksandrov with Pritchard Capital. Veny Aleksandrov – Pritchard Capital Partners: Thanks.

Good morning Veny. Veny Aleksandrov – Pritchard Capital Partners: I have a couple of questions left, so with everything going into Gulf of Mexico, do you see any money coming offshore and possible increase of activity for the rest of the year or only next year?

Veny, I don’t think we’ve seen any impact of the any shift of dollars yet directly related to the Gulf situation. I think we’re probably little early to see what the effect of that’s going to be. So I don’t think that that had any tremendous impact on our bid activity. Veny Aleksandrov – Pritchard Capital Partners: Okay, thank you. And we show already the increase in the number of drilling for offshore (ph) but what are the drilling with all seismic oil shifting, can seismic now that growing to be (inaudible) like what’s going on there?

Said that again Veny? Veny Aleksandrov – Pritchard Capital Partners: Is the increase in land rates that we already saw in continental US, where does drilling of all seismic, is there a few, apparently there is still demand for seismic, but do you think we will see the increase in demand for seismic from now on because the seismic is already gone?

Some of the Shale plays the Marcellus and the Haynesville and the some of the larger ones, they are multiple drilling locations that are generated from seismic surveys, it’s not just shoot a survey for one location. Its – they will have several and what that number is it depends on where they are and the size of the survey. So I think there is drilling going on right now particularly in the Shale play that is related to prior seismic work. Having said that Marcellus is a very large area, the Haynesville is very large area, the Eagle Ford is very large area. So there is a whole lot of stuff to be shot in those areas and there is a whole lot of detailed work that still needs to be done and all those basins were still staying relatively high level of activity for us in the Barnett. Of course there is a lot of open area that need new seismic data in the Bakken, the Niobrara and so I think the increase in rig count is probably a little bit detached from any predictability of the crew count. I think over time, over the last 20 years, I feel like in the lower 48 that seismic activity had become more of a lagging indicator than a leading indicator. And so when I first came into the business in the mid 80s, if you track crew count that was pretty good indication of what drilling activities are going to look like and I think as we move from more of an exploration tool into more of an exploitation type tool, I think we’ve seen a shift in the lower 48 from leading indicator to lagging indicator. And having said that, the crew count in the early 80s was 700 or something like that and now it’s somewhere in the 30s or 40s, I don’t have an accurate numbers, somewhere in the 40s I guess, in the lower 48. And so I think there is a whole lot of work to be done and I think it’s going to depend obviously on drilling success and cash flow already peak lines, gas prices are still a concern, and then I think what’s really helping is some of the activities to oil related basins. Veny Aleksandrov – Pritchard Capital Partners: Thank you.

Thank you. Our next question is from the line of A.J. Strasser (ph) with Cooper Creek Partners (ph). A.J. Strasser – Cooper Creek Partners: Hey there, hey guys, thanks for taking my call, this is A.J. Strasser from Cooper Creek Partners. Could you just give us a sense of where your order book, I guess break it out as a number, is that right. Can you give us a sense of where it stands versus where it stood in the past. So it back to kind of ‘08 levels or just too specific as you can be and it is the first time we’re seeing it move sequentially up, I’m just curious and I have another follow-up question after that. Thanks.

A.J. I think we’ve seen it increase slowly since the first quarter. It’s hard to call a bottom and I don’t want to get into calling bottoms or peaks or anything like that but we’ve seen steady improvement in demand since the first quarter of late 2009, I guess calendar ‘09. It’s about – our order book is about no means as strong as it was in ‘07, ‘08 timeframe, but it’s certainly a lot better than it was a year ago and I think when I say better, it’s not just the size of the order book in terms of square miles or dollars or number of projects have or whatever metric you choose, I think its stronger in terms of project sizes and diverse, mix of oil and gas and mix of where its located and so I think all that together gives us better chance to increase utilization rates. We do not report backlog in terms of dollars or months, we just we feel that sometimes that – it’s hard to anticipate when those backlog dollars pull forward into a certain quarter. So we just try to give the market a sense of what our demand looks like and I would call it steady, improving but certainly not robust like we saw in ‘07 and ‘08. A.J. Strasser – Cooper Creek Partners: All right, great. That’s really helpful, thanks. And just another question and I think it’s been kind of asked but I’ll try to ask in a different way. Just in terms of margins, I mean I think your EBITDA margins kind of roughly 10% obviously still way below kind of peak EBITDA margins from I guess, eight or so quarters ago. Should we – could we at least expect margin to remain flat to up for the foreseeable future. Is that a fair assessment?

Its running the risk of sounding like I’m avoiding the question, I want to go back to the weather issue, I think if weather and projects come good, I think we’re going to see margins upwards. And if we have weather issues and permit problems that could be flat, even down I think and coupled with that, going back to Collin’s (ph) original question or earlier question is I am not – it’s very difficult to predict what these levels of third-party chargers are going to be and if they continue to run at a very, very high level like they have in the last couple of quarters, then that could have an impact to apparent margin and I’ll just tell you that our position has improved from where it has been in the last three or four quarters particularly from the first quarter of this year. July was a little bit rough, weather wise, had a lot of rains particularly in Texas. Weather in August has been pretty good. We’re five days in or four days in and it’s been pretty good and I think we continue to have good weather conditions. I just think that’s the overall factor right now is weather and permit issues. A.J. Strasser – Cooper Creek Partners: All right, thanks. That’s very helpful.

Thank you.

Thank you. And I am showing no further questions at this time.

Okay, well if there is no further questions, I would like to thank everyone for listening in to our third quarter 2010 conference call. I’d particularly like to thank our employees for their continued effort, our clients for their continued trust and to shareholders to continued support. Well make a note, we will be presenting at the Intercom oil service conference, excuse me, the Intercom oil and gas conference in Denver on Monday August 23. And with that we’ll sign off and look forward to talking to you in another 90 days. Thank you.

Thank you for your participation in today’s conference call. You may now disconnect.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS. If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!