Ladies and gentlemen, thank you for standing by and welcome to the Core Lab Third Quarter 2012 Earnings 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) It is now my pleasure to turn the conference call over to David Demshur. Please go ahead, sir.

Well, thanks Raquel. We’d like to say good morning in North America, good afternoon in Europe, and good evening in Asia Pacific. We’d like to welcome all of our shareholders, analysts, and most importantly, our employees to Core Laboratories’ Third Quarter 2012 Earnings Conference Call. This morning, I am joined by Dick Bergmark, Core’s Executive Vice President and CFO. Also this morning, we are again joined by Core’s COO, Monty Davis, who will present the detailed operational review. The call will be divided into five segments. Dick will start by making remarks regarding forward-looking statements. Then we’ll come back and give a brief investor update and highlight the three financial tenets by which Core’s executive management executes the company’s growth strategies. We believe these three tenets have produced industry-leading shareholder returns and returns on invested capital. We will also discuss Core’s long-held philosophy of returning excess capital back to our shareholders. Dick will then follow with a detailed financial overview and additional comments regarding building shareholder value and Core’s Q4 outlook and a general industry outlook as it pertains to Core’s continued growth prospect in 2013, which confirm our confidence in the trends of increasing activities in unconventional reservoirs in North and South America, and also other parts of the world, and especially international and deepwater activities tied to crude oil and large LNG developments. But Monty Davis will go over Core’s operating segments detailing our progress and discussing the continued successful introduction of new Core Lab technologies, including Core’s new RSAT technology, and then highlighting some of Core’s operations and major projects worldwide. Then we’ll open the phones for a Q&A session. I’ll turn it back to Dick for remarks regarding forward-looking statements.

Thanks, David. Before we start the conference this morning, I’ll mention that some of the statements that we make during this call may include projections, estimates, and other forward-looking information. This would include any discussion of the company’s business outlook. These types of forward-looking statements are subject to a number of risks and uncertainties relating to the oil and gas industry, business conditions, international markets, international political climate, and other factors including those discussed in our 34 Act filings that may affect our outcome. Should one or more of these risks or uncertainties materialize or should any one of the assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. For a more detailed discussion of some of the foregoing risks and uncertainties, see Item 1A, Risk Factors, in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011, as well as the other reports and registration statements filed by us with the SEC and the AFM. Our comments include non-GAAP financial measures. Reconciliation to the most directly comparable GAAP financial measures is included in the press release announcing our third quarter results. Those non-GAAP measures can also be found on our website. With that said, I’ll pass the discussion back to David.

Okay, thanks, Dick. I’d like to give you a brief investor update. Core’s operations produced another solid quarter as the company continued to benefit from our continued focus on international and deep-water offshore activities and unconventional oil plays in response to relatively high oil price and dwindling global spare capacity for oil producing. The focus on crude oil-related projects continued to build in 2012. As we have discussed on the last five conference calls, we believe that gas drilling activity in North America will continue to wane in the fourth quarter. Therefore, Core’s revenue mix now is closer to 8% oil and 20% revenues from natural gas, a shift from our previous 70-30 earlier this year and in past years. Moreover, most of the natural gas-related revenues emanate from projects in the international theater and are LNG-related with major developments in the Eastern Mediterranean, East Africa, and Western Australia. Reviewed company’s improved the year-over-year third quarter results reveals the company’s growth strategy of progressively working in established fields and new field development will continue to – and continue to offer new technologies and services will lead to revenue growth of 200 to 400 basis points higher than the increase in the worldwide activity levels. Year-over-year quarterly revenue and operating profit growth for the third quarter of 2012, with flat-to-down worldwide activities is a testament to the validity and robustness of the company’s growth strategies and are underpinned by our operational excellence. We believe these trends to outperform market activity levels to hold in the fourth quarter of 2012 and in 2013. Therefore, our growth strategies and the execution by our operating units continue to serve our clients, our employees and our shareholders well. Core’s continued focus on higher return international crude oil-related developments, especially those in deepwater environments, and unconventional…

Thanks, David. I’d like to start by mentioning that we are excluding a gain from the business interruption insurance claim that we have previously discussed relating to the fire last year at a steel supplier. It has now been settled with an additional payment of $1 million that was received in the third quarter. So we are removing this gain from our operational earnings as the gain was specifically excluded from our prior guidance. Looking at the income statement, revenues were $245.4 million in the third quarter versus $231.3 million in last year’s third quarter. Revenues were up 6.1% year over year. Given that we view our business on a year-over-year basis, of note, this represents record revenues for any third quarter. And to point out commentary contained in the earnings release, we do view year-over-year comparisons as the most indicative of how well our business is performing. This is due to inherent business seasonalities that can impact the optics of sequential quarterly comparisons. This is particularly true of our reservoir description segment. As has been the case in four of the last five years, third quarter reservoir description revenue was down sequentially from second quarter because of the large amount of revenue the company generates from Canadian oil sand projects, which peaks in the second quarter of each year. Our reservoir description segment reported recorded revenues for any third quarter. Operating income increased 15%, and operating margins expanded to 30%, more than 300 basis points over year-ago levels. This segment’s revenue growth and margin expansion occurred in an operating environment of flat international rig count. Increasing market penetration and improved utilization of higher technology services drove this marketplace outperformance and continues to demonstrate the strength of this franchise. Now if we look at the revenues on a services basis…

Thanks, Dick. The third quarter 2012 revenue of $245 million represents growth of 6% over Q3 2011. Operating earnings excluding a $1 million business interruption insurance recovery, grew 7% over Q3 2011. 2012 was a record third quarter performance thanks to the efforts of our 5,000 employees, and we thank them. The year-over-year improvements in revenue and profitability is directly related to the company working in more fields worldwide and our ability to continue to offer new technologies and services to improve daily hydrocarbon production, and more importantly, increase ultimate hydrocarbon recovery rates. Reservoir description revenue grew 4% over prior-year third quarter, while operating earnings grew 15% over Q3 2011. Operating margins grew by 300 basis points to 30%. The continued growth of reservoir description occurred despite a flat international operating environment. Core Lab is analyzing core from a deepwater well in Namibia for Petrobras. Analyses including paleontology, geochemistry, petrology and sedimentology, are being performed to help Petrobras evaluate this new area. Petrobras continues to be Core’s largest national oil company client worldwide. The first shale Core cut in Australia is being analyzed in the field for gas absorption with full laboratory analysis of the rock to follow in Q4. Core was recently requested by a major client to increase our technical capability and processing capacity in Australia for several large potential shale developments. Shale reservoirs are being evaluated in Australia as sources of gas for LNG projects to supply to Asia. Core Lab Malaysia is working on core and geological samples from a high pressure, high temperature deepwater well in the Malay basin. Analysis is ongoing in our Kuala Lumpur advanced technology center. Asia Pacific continues to be a revenue growth region for the company. To meet the increasing workload from primarily deepwater Gulf of Mexico and international deepwater…

Thank you.

Raquel, we can go ahead and open the call for questions.

Thank you. (Operator Instructions) Your first question comes from the line of James West with Barclays. James West – Barclays: Hey, good morning, gentlemen.

Good morning, James. James West – Barclays: Dave, there’s been a lot of chatter as you know in the market about increased competition. I think you addressed some of that in your prepared comments about mudlogging, and that not really being what you guys are interested in doing. But when word out in Houston and other areas, you have some of your competitors showing off what they call core analysis facilities and talking about kind of large growth programs, now, you’re adding a lot of capacity as well to the business. So I guess my real question is are you seeing any kind of degradation in your overall market share or any real competition. Or is just the pie growing so rapidly that there’s room for everybody?

Well, I think they’re – some of the remarks you make about some of the laboratories that you view in Houston, they’re addressing a different market. We are after a market that deals with reservoir condition testing. So we look at measuring petrophysical data at reservoir conditions. Read that “temperature and pressure.” There are lower tech markets that some of these individuals and companies are addressing. Those markets have very little interest to us. And so the market that we are addressing, we continue to see a gain in what we believe are the highest-margin projects worldwide. We’re not going to do every core that is taken around the globe. We know that. However, we are choosing projects that are the highest-margin and highest-return. Read that “the most difficult reservoirs to understand and characterize.” And we do that using reservoir condition testing. So I think the margins over the last 11 quarters in reservoir description, and the margin expansion in the last four quarters, has been dramatic. And so we don’t see this competition in our marketplace. Are other individuals and companies doing lower-tech, lower-margin projects? For sure, no question about that. But the market that we address, we have not seen any serious competition enter, nor do we think we will see any serious competition enter in the near future. James West – Barclays: And what’s the key, David, in your mind the barrier to entry for those companies that do the low-tech work from doing the higher-tech work?

It would be our intellectual property and our 1,300 senior scientists worldwide. If you look at our expansion here in Houston, as Monty talked about, 105,000 square feet, and that expansion was made to essentially address the increased work that we’re getting from the deepwater Gulf of Mexico, both in rocks and in fluids, and deepwater reservoirs around the world. So read that “West Africa, East Africa,” where companies want that work performed here in Houston. Are we going to do every deepwater core in the world? Probably not, but are we going to do a very, very large percentage of those? Probably, yes. So those barriers to entry have to be our IP. Comments that Monty made about our new reservoir saturation, or RSAT programs, these intellectual properties and techniques and proprietary methods are the moat, along with our 1,300 senior scientists worldwide, form the moat that protect that business. James West – Barclays: Okay, very clear. Thanks, Dave.

Okay, James.

Your next question comes from the line of Rob MacKenzie with FBR Capital Markets. Rob MacKenzie – FBR Capital Markets: Good morning, guys.

Hello, Rob. Rob MacKenzie – FBR Capital Markets: David, I had a question for you, a couple of questions for you focused on production enhancement, I guess first. Number one, how much are you guys running into, if you’re aware, systems like Schlumberger’s HiWAY system, which now they say is $1 billion of revenue? Does that mean more SpectraChem and ZeroWash type work for you or less? How does that impact your business, if any?

Well, actually as a independent evaluator of proppants, we test proppants that are sand, resonated sand, ceramics and proppants related to systems like HiWAY that Schlumberger has. So it does form a source of revenue for us, as we test these systems under rock mechanics and hydraulic stress that would occur in the reservoir. So for us, the more proppants that are available, or the more systems that are out there to prop open the reservoir, the better for us. We cheer when we see new proppants being developed, because we know that they’re going to form a series of tests that we will perform and revenue for us. So when we look at systems like HiWAY, we will openly test those systems for all of our clients. Rob MacKenzie – FBR Capital Markets: Got it. And does the same somewhat apply to sliding sleeve completion tools? Does that – would that theoretically generate more revenue for you in terms of tracers, as oftentimes where the profit goes can be of debate?

Yes. There’s going to be a couple, because I’m going to have Monty speak to this as well, because we have done a lot of testing internal, and we keep internal files on the effectiveness of sliding sleeves. We do find that it is an effective tool, but it’s a limited tool. And there are formations where it’s effective and formations where it’s not effective. So when we look at the total number of completions, we think it’s more related to where these systems are effective and not effective. Monty has done some work on this, and he’s got some results based on sliding sleeve versus plug and perf.

Yes. We’re seeing a lot of different things. A lot of it depends on your formation, where you’re drilling your wells in the formation, and admittedly different technology that different companies are offering in sliding sleeves, inflatables and those sorts of equipment. So we are doing a lot of testing. It’s obviously a good business for us to test. It’s also good for our clients to know what’s working and what’s not working. There are new technologies being developed all the time. There are a couple of new technologies that I’m aware of coming out from different companies that offer these sliding sleeve-type completions. And we’ll be testing those as they’re put in the ground. And there are – the results are quite variable. The success rate really requires a borehole integrity that is important, particularly when you’re using inflatables and sliding sleeves. If you don’t have the borehole integrity, we’re finding a high failure rate. But also, some systems have a higher mechanical failure rate, and we let our clients know where it’s effectively fractured and where it hasn’t. So that’s a really good business for us, to help our clients understand what’s going on. It’s the only way for them to understand what’s going on downhole in a sliding sleeve completion. Rob MacKenzie – FBR Capital Markets: So effectively, as the clients – as operators try these more, they spend the money and time on analyzing it so it’s a net positive for you guys?

That is correct. We’ve got a good example in the Granite Wash, where it was a 21-stage completion. They used the sliding sleeve technology. And after they completed their stimulation, the well flowed exactly what they thought it would flow, so they thought they had a very successful completion and stimulation of all 21 stages. What our tracers did show that the first nine stages did not take any stimulant and all the production was essentially from the last 12 stages. So that client, in the next drilling operation, used plug and perf, and made their best well that they ever have. So it’s on a case-by-case basis, Rob, but it is providing additional fracture diagnostics services to the company.

Rob, also I’ll add the economics of completion are critical to success with sliding sleeves versus plug and perf. And a lot of that’s dependent on availability of frac spreads, availability of core tubing, and of course with that, the cost of those items, as the cost of sliding sleeve equipment is expensive compared to plug and perf. So it depends a lot on the other ancillary services. So the economics play a big role in deciding which direction to go. Rob MacKenzie – FBR Capital Markets: Got it. Thank you. Real quick question on reservoir management, are you guys comfortable sharing roughly your geographic mix there in reservoir management? Because you talk a lot about both the shales in North America and international deepwater and land. Roughly, how does that break down?

Highly variable from quarter to quarter, Rob. It’s just the revenue stream is dependent on when we have projects that are completed or we reach a stage where we have a data disbursement. So one quarter, it could be primarily from shale projects in North America, or other quarters, it could be purely 100% from the international theatre. So I would say that the mix probably is tilted towards international, but it can be highly variable.

The other thing I’ll add on that Rob, we do not talk about, naturally, the proprietary projects we do in that group. We can’t. We won’t talk about those, naturally. We talk about consortium projects because they are publicly known. So that can also influence where our revenue is coming from. Rob MacKenzie – FBR Capital Markets: Got it. Thank you. And just a final on pinning a reservoir description, you guys highlighted your mercury-free PVT capabilities there. Can – do you have any kind of handle on what the whole market there is? You said you’re adding a lot there and you have, what 10 going to 13 sales. What’s the industry capability, and how important is that to your customers? It sounds like they’re trying to drive it. Is this critical or is this -?

No. I think you’re on to something there, Rob. This will be a 100% mercury-free market over the next several years, driven by our clients. And so for us, we are converting to those systems presently, and essentially have more systems than anybody else in the world, and will convert totally around the globe to mercury-free systems over the next three to five years. Rob MacKenzie – FBR Capital Markets: Do you have a feeling on how big that market and/or how big you are – how far along you are in the transition?

We think probably somewhere on the order of half of our capacity to generate reservoir fluids data probably now emanates from projects surrounding the mercury-free units. Probably 75% of that work is still done in-house at the major oil companies, and the other 25% is done by us. Rob MacKenzie – FBR Capital Markets: Got it. Thanks very much. I’ll turn it back.

Okay, Rob.

Thank you. Your next question comes from the line of Veny Aleksandrov with FIG Partners. Veny Aleksandrov – FIG Partners: Good morning, guys. It’s so great to be on this call again.

Hello, Veny. Welcome. Veny Aleksandrov – FIG Partners: Thank you. My first question, reservoir description, we know that it’s coming, or most of the revenues, are coming from internationally and they’re all related. But can you tell us in the last quarter what percentage was coming out of North America, ex-Gulf of Mexico?

Ex-Gulf of Mexico, so right if we just split it, 85% of that revenue is international or comes from international-based reservoirs. 15% of it is from, let’s say, the United States. Probably 5% of that 15% is from – so I’d say 10% of that revenue is probably from the U.S. Veny Aleksandrov – FIG Partners: (Inaudible).

Ex-Gulf of Mexico. Veny Aleksandrov – FIG Partners: Ex-Gulf of Mexico. Okay, thank you. And then my next question for 2013, 200 to 400 basis points above the increase in worldwide activity, and I understand that it’s still October and it’s way too early. But do you have any indications from your clients internationally what CapEx budgets might look like in 2013?

Yes, we’ve had some discussions with our major clients who are now in the process of constructing their budgets. First read would be that if we got Brent crude prices that remain at the levels that they’re at, we could see again about somewhere on the order of a high single-digit, low double-digit, low-teens growth rate. Very early days, but that’s what we would expect. Veny Aleksandrov – FIG Partners: Thank you so much. I really appreciate it.

Okay, Veny. Welcome back.

Your next question comes from the line of Joe Hill with Tudor Pickering. Joe Hill – Tudor Pickering: Good morning, guys.

Good morning, Joe. Joe Hill – Tudor Pickering: Dave, just a question on kind of the 200 to 400 basis point premium target you put in the release this morning. Should we be using the worldwide rig count as a proxy for the base? Because I know you’ve kind of hitched it to producing fields, and I just wanted to figure out what you guys were using internally for that.

Yes, Joe, good question and making a good point. The worldwide activity level, you can use the rig count as a proxy. However, when you are in an era where you have day rates increasing, your problem – and you have deep water wells, some of which are going to start costing up to $500 million to drill – you’ve got to look at the total number of wells drilled as an activity level. So use that as your basis. You can use the international rig count, offshore rig count, actually, which was down 5% last quarter sequentially. You can use that as a proxy, but a better study would be the number of wells drilled versus the number of wells drilled last year. Joe Hill – Tudor Pickering: Okay.

And remember that 30% of all oil is produced offshore. 40% of our revenue right now emanates from offshore. So, as these deepwater rigs start to roll out next year, the year after, and the year after that, that demographic will trend in our favor. So as opposed to maybe 40% of our work coming from offshore, that will certainly trend higher. Joe Hill – Tudor Pickering: Okay. And then given that, I think production enhancement, just based on its product-focused as opposed to services-focused, is probably a little bit more levered to kind of the producing fields in development as opposed to exploration. Would we expect to see the growth rate of production enhancement kind of blow out a little bit relative to reservoir description?

That is – no. The focus for production enhancement, as you know, is still primarily North America. So that is tied very closely to the number of wells that are completed, and more importantly, the number of stages in these long laterals that are being completed and stimulated. So looking at that act, the growth rate there is more closely tied to the number of wells completed and stimulated in North America and, more importantly, of those, the number of horizontal wells drilled in the liquid plays and the number of stages that are completed and stimulated in those long lateral wellbores. Joe Hill – Tudor Pickering: Okay so –

So if that activity level continues flat, or to trend down, we still think we can grow that business, again, 200 to 400 basis points more than the market activity. And I think a good proxy for that is to just look at the third quarter revenue for that production enhancement segment, where we saw the rig count in North America go down 6%, more importantly, some 32 horizontal rigs drilling in liquid plays being laid down, and we were still able to grow that business, as Monty remarked, by the increased market penetration of our HTD-BLAST and HTD-BLAST XL technology. Joe Hill – Tudor Pickering: Okay. And then, Dave that’s a great segue into my last question, which is you guys are using a flat North American rig count as the basis for your guidance for the fourth quarter. If we were to take 100 rigs out of that rig count, what would the earnings sensitivity impact be?

If you took out 100 rigs – so you want to go from let’s say, 18, 30 to – Joe, it all depends what rigs you take out. If you take out natural gas rigs, it will have a small, negligible effect. If you took out 100 rigs that are drilling horizontally in some of the liquid plays, it would have an effect. So it just depends what that mix is – the mix of rigs would be and how it would affect production enhancement, and to a lesser amount, reservoir description revenues and profitability. Joe Hill – Tudor Pickering: So if we just assumed it was 100 oil rigs, we’re probably talking on the order to $0.05 to $0.10, maybe.

Yes. I’d give you that range. Joe Hill – Tudor Pickering: Okay. Fair enough. Thanks, Dave.

Okay.

Your next question comes from the line of Kurt Hallead with RBC. Kurt Hallead – RBC: Hey, good morning.

Hello, Kurt. Kurt Hallead – RBC: How’s everything? I just wanted to verify a couple of things to make sure I heard them correctly. Did you indicate that your offshore revenue was 30% or 40%?

The amount of oil produced offshore in the globe is 30%. Our revenue from offshore projects is 40%. Kurt Hallead – RBC: And therefore, going higher from there, right?

Yes. Logically, when we deliver these – when these deepwater drilling assets start to roll out, logically we would believe that would indeed go up. Kurt Hallead – RBC: And then I think you also – make sure I just understood this correctly, so forgive me for repeating a question. But 10% of your revenue comes from U.S. land, is that total revenue, or just one of your segments?

That –

Description.

Yes. That was in reservoir description. Kurt Hallead – RBC: Just reservoir description. Got it.

Correct. Kurt Hallead – RBC: Okay. And then, in terms of your guidepoints for the upcoming quarter, understanding that 2013 is much more relevant at this stage, so you guys are thinking that rig count’s flat. Some of the discussions that we’ve been having with varying companies right now are indicating that rig count’s going to continue to bleed lower. I know you said the rig count is a proxy, got to look at well count, but I got to assume well count’s going to go down as well in the fourth quarter. What kind of sensitivity should we be thinking about in that context, then? I mean you guys are using kind of flat. I’m thinking kind of down. What kind of sensitivities are we looking at?

Yes. Again, as – just from Joe’s question that was asked earlier, it all depends on the make-up of the number of rigs that are laid down. If they’re primarily natural gas rigs, not going to have a lot of effect to us. But certainly, if we still see another significant decrease in the number of horizontal rigs drilling in liquid rich plays, it can have an effect. And the range that we did give to Joe was somewhere between $0.05 and $0.10, and I think that’s reasonable. Kurt Hallead – RBC: All right. And I think in some prior discussion that we had you indicated that there is no pricing pressures, per se, for any of your product lines or services at this point. Is that still the case?

Yes. I think our margins would speak to that, Kurt. Kurt Hallead – RBC: Okay. All right, great. That’s it for me. Thank you.

Thank you, sir.

Your next question comes from the line of Doug Becker with Bank of America. Doug Becker – Bank of America: Thanks. I was just hoping to get a little more color on the seasonality related to oil sands projects. What specifically drives it, like kind of a third quarter trough versus a second quarter trough? And if you can just give any color what’s changed from the two previous years when reservoir description revenue was pretty flat from 2Q to 3Q.

The oil sands projects are driven entirely by the weather in Canada. The typical seasonality of that is you go in, as early as December maybe, and they start their drilling. So they’re laying out their programs now that they plan on. Assuming the weather is cold – they have to have frozen ground. Assuming it’s cold, they’ll start drilling in some time in December. They’ll drill through February. Cores will be coming into us all of that time as they’re drilled. Those cores then are analyzed in a very rapid flurry of activity in the first quarter. Generally, the reports, data reports, are issued towards the end of the second quarter, sometimes earlier. It depends on we know how long – when the cores come in. But as the cores come in, we analyze them. We don’t have revenue at that point, because we record revenue when we issue the reports, the data, to the clients. And that’s why usually, it’s going to fall in the second quarter, and that’s throughout the second quarter, heavily weighted towards the end. We have had years in the past where it fell over, some of it, to the third quarter. Just depends on the weather, seasonality and the volume of cores, but normally, it’s a – that’s the way it goes. They drill in the winter, December, January, February. We’re analyzing cores in the first quarter and into the second and giving them their data, which is our revenue recognition point, in the second quarter, sometimes falls a little bit into the third. Doug Becker – Bank of America: Makes complete sense, just a slight lag to the rig count. In terms of fourth quarter, do you see anything that would prevent a normal seasonal bump for the reservoir description segment?

No, we do not. Doug Becker – Bank of America: Okay. Just switching to some of the new technology, and particularly the RSAT, will we see that in the reservoir description business, and any sense on how big a driver this could be? It seems like if we go back to 2006 and 2007, there were certainly time periods when new technology was being introduced and we saw incrementals of around 50%. Is this a product that could be that big a driver going forward?

Yes. Good – some good points there, Doug. When we look at this reservoir saturation, or RSAT, technology, very early days for that. A parallel to that, when we discovered in working with Petrohawk in the Haynesville, this rate-determinant permeability, where the higher we flowed the reservoir, the less permeability and the less recoverability you had over time. So choking back some of the wells produced a higher efficiency in the permeability of a stimulated reservoir, which enabled lower flow but ultimate recovery from some of these wells to increase by maybe 2 or 3 bcf. Turning to RSAT, we believe that this does increase the flow of hydrocarbons while decreasing the flows of water. Essentially, what we’re trying to do is identify reservoirs where we can increase the irreducible water saturation. So read that “the rock absorbs the water freeing more hydrocarbons to flow.” On our fourth quarter release, we will have more on this technology, and the reason why we didn’t write it up in this release is just very early days. We think it has some very good potential along the lines of the rate-determinate permeability that we worked with Petrohawk in developing, so more to come on that. You will see it have a revenue effect in reservoir description, because that’s where those analyses are done. And in reservoir management as Monty said, with proprietary studies being done, and this is where this technology actually was discovered by our reservoir management teams. So it will have an impact in both of those segments. The amount of impact, Doug, really too early to tell. We think it can be a very interesting technology that can not only be applied to the Utica, but also to the Eagle Ford and some of the other shale reservoirs including the Bakken, Niobrara, among others. Doug Becker – Bank of America: Perfect. And then just one last quick one, I know you’re very close with your customers. Do you have any early sense for what the 2013 activity growth could be? Are we talking mid-single digits, high-single digits? Any early bead on that?

Don’t know yet. Doug Becker – Bank of America: Okay. Thank you very much.

Okay, Doug.

Your final question comes from the line of John Daniel with Simmons & Co. John Daniel – Simmons & Co: Hey, guys. In response to James’ earlier question, you guys cited that one of the reasons you can maintain your market share is the 1,300 scientists. Skeptics would say that those folks could be easily poached by competitors. So it might be helpful if you could share with us what the employee turnover has been in recent years?

Okay, John. Good question. We’re going to let Dick talk, because he hasn’t talked on the questions.

I feel left out. Hey, John. If you looked at our 5,000 employees as a group, their turnover rate, and then let’s compare that to the turnover rate of our senior scientists, I think that gives you a good view. Our 5,000-employee turnover rate has averaged in recent years around 6%, which isn’t bad. For our 1,300 senior scientists, that turnover rate is about 2%. John Daniel – Simmons & Co: Okay. That’s what I thought.

And we think that’s reflective of a work environment where the employees have a greater variety of projects they can work on. So if they had gone to an oil company – and usually, if one of those leaves us, they tend to go to an oil company. We rarely see it they go to a service company, which I think is further testament to the fact that the others really don’t do what we do. John Daniel – Simmons & Co: Right.

So we’ve got that in our favor. And we also use restricted shares as a retention tool that vest over time. They’re six-year vesting and they get a sixth of it every year. They’re not performance-related, because the idea here is to retain them. So a lot of our senior scientists do receive those restricted shares that no one in our executive management receives, because ours is all performance-based. And I think the combination of that better work environment and those restricted shares has helped keep that retention rate pretty much at an industry low of around 2%. John Daniel – Simmons & Co: Okay. Well, thank you. Just a modeling question, you mentioned that free cash flow next year will remain at elevated levels. I just want to make sure I understand the context of the statement. I read that to me in that it’ll be better than this year.

What you should read into that is, because we haven’t given numerical guidance, is that our capital discipline will remain the same. So excess free cash, which is the amount after we’ve already spent for our own growth, will be used for dividends. I think we mentioned that we expect it to increase in 2013. And the remainder would be used to give back to our owners in the form of share buybacks. John Daniel – Simmons & Co: Okay. And then just a last one for me is with respect to the buybacks and the balance sheet. Do you have an established threshold whereby you go back to paying down the revolver as opposed to buying back stock? How do you look at that?

No. We do not have an established threshold, although we do look at our balance sheet for reasonableness from a debt-to-cap, or importantly for a company like ours, a fixed coverage ratio of cash flow versus outstanding. And as you know, the coverage ratio now is double-digits. John Daniel – Simmons & Co: Yes. Fair enough. Okay, that’s all I had.

Thank you. John Daniel – Simmons & Co: Thanks, guys

Okay. Thanks, John. So in summary, Core’s operations posted another solid quarter. We have never been better operationally or technologically positioned to help our clients expand their existing production base. We remain uniquely focused and are the most technologically advanced reservoir optimization company in the oil field services sector. This positions Core well for the challenges of 2013. For 2013, we continue to be encouraged by recent activity trends in international and especially deepwater activities, and the growing activity levels in the deepwater Gulf of Mexico and remain confident in the activity levels associated with unconventional oil plays, not only in North America but extending worldwide. The company remains committed to industry-leading levels of free cash generation and returns on invested capital with excess capital being returned to our shareholders. So in closing, we’d like to thank all of our shareholders and the analysts that follow Core. And as already mentioned by Monty Davis, the executive management and the board of Core Laboratories gives special thanks to our 5,000 worldwide employees that have made these outstanding results possible. We are proud to be associated with their continuing achievements. So thanks for spending your morning with us, and we look forward to our next update. So, goodbye for now.

Thank you, ladies and gentlemen, for joining today’s Core Lab third quarter 2012 earnings conference call. You may now disconnect.