Gwen Schreffler - IR David Demshur - CEO Dick Bergmark - CFO Monty Davis - COO Chris Hill - Chief Accounting Officer.

James West - Evercore ISI Rob MacKenzie - Iberia Capital Chase Mulvehill - Wolfe Research Gregory Lewis - Credit Suisse Sean Meakim - J.P. Morgan Blake Hutchinson - Howard Weil Marc Bianchi - Cowen John Daniel - Simmons and Co Stephen Gengaro - Loop Capital Markets.

Good morning. And welcome to the Core Laboratories Second Quarter 2017 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to David Demshur, Chairman and CEO of Core Laboratories. Please go ahead..

Thanks, Kate. 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’ second quarter 2017 earnings conference call. This is our 88th quarterly earnings release.

This morning, I am joined by Dick Bergmark, Core’s Executive Vice President and CFO; Core’s COO, Monty Davis, who’ll present the detailed operational review; Chris Hill, Core’s Chief Accounting Officer, and Gwen Schreffler, Core’s Head of IR. The call will be divided into five segments.

Gwen will start by making remarks regarding forward-looking statements. We'll then review the current macro environment, updating industry trends in EOR, in unconventional reservoirs, the use of finer proppants, and the limits of lateral length and horizontals.

We’ll then Core's three financial tenets, which the Company employs to build long-term shareholder value.

Chris will then follow with a detailed financial overview and additional comments regarding building shareholder value, followed by Dick Bergmark commenting on Core’s third quarter 2017 outlook and a general industry outlook as it pertains to Core’s prospects.

Then Monty will go over Core’s three operating segments, detailing our progress and discussing the continued successful introduction of new Core Lab technologies, and then highlighting some of Core’s operations and major projects worldwide. Then, we’ll open the phones to a Q&A session.

I will turn it back over to Gwen for remarks regarding forward-looking statements. Gwen..

Before we start the conference this morning, I’ll mention that some of the statements 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 of our 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 up for the fiscal year ended December 31, 2016, as well as 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 financial measures included in the press release announcing our second quarter results. Those non-GAAP measures can also be found on our website. With that said, I’ll pass the discussion back to Dave..

Thanks Gwen. Core has observed the emergence of three major industry trends that will shape tomorrow's oil field and Core's client activities. Core is utilizing these trends to focus the company's technology to enhance the growth and profitability of Core and its clients.

The first major trend is the increasing client interest in enhanced oil recovery from unconventional reservoirs.

Early work performed by Core has indicated possible recoveries increasing from an average of about 9% in share reservoirs to 13% to 15% by utilizing engineered gas absorption techniques, gas recycling and the laws of physics and thermodynamics.

Ongoing dynamic flow test look promising and Core has developed gases traces that will be used to determine the positioning and effectiveness of this engineered gases in the EOR process. We are now investigating the role of dense and complex completion and stimulation programs and the role in the EOR process.

Increased recovery rates of this magnitude can increase the clients' return on their invested capital by 40% to 50%, boosting their free cash flow and shareholder value. The second major trend is the interest in using finer proppants or micro proppants in the initial procedures in a hydraulic fracture program.

Core via our industry wide profit consortia with a 30 plus year history and consisting of over 40 companies is boosting its evaluation of 100, 200 and 400 non-API mesh sand. These macro proppants are thoughts to open secondary and tertiary fracture patterns significantly increasing the stimulated reservoir volume.

Therefore, increasing initial flow rates as well as the estimated ultimate recovery from the wellbore. Micro proppants pumped during the placement of the frac pad could potentially boost these curves by tens of thousands of barrels with very little added cost, pumping 70 and 40 mesh sand late in the frac process also appears critical for success.

The third major trend is that lateral length may have reached their maximum owing to frictional forces of pumping the frac fluid and its profit. However, Core is currently testing friction reduction additives to once again allow for longer laterals.

Pad drilling and completion programs rule today and are causing the recent disconnect in wells drilled and wells completed in the last two quarters. Wells drilled and completions will start to mirror each other in the second half of 2017.

Now to review the three financial tenets by which Core is used to build shareholder value over our 22 year history of being a publicly traded company. Incidentally Core as a company is celebrating our 81st year of technological innovation.

During the first quarter of 2017 Core generated over $16 million in free cash flow and once again produced the oil field industry leading return on invested capital for the 31st consecutive quarter. Also Core over $30 million back to our shareholders via our quarterly dividend and share purchases.

Core will continue to return all excess capital back to its shareholders in future quarters via the quarterly dividend and additional share repurchases. I'll now turn the call back to Chris and he is going to give a detailed financial overview.

Chris?.

Thanks David. Now looking at the income statement, revenues were $163.9 million in the second quarter, up 4% sequentially, which was led by the growth in our production enhancement segment. Of this revenue, service revenue was a $117.2 million for the quarter, down sequentially $3.7 8 million or 3%.

Product sales were $46.7 million for the quarter, up $9.8 million or 27% sequentially, which is primarily related to the improved activity levels in North America. Moving on to cost of services which was 69% of service revenue for the quarter and consistent with last quarter.

Cost of sales in the second quarter was 79% of product sales revenue, a nice improvement from the 84% last quarter and 89% in the same quarter last year, as our operating leverage and the absorption of our fixed cost improves with higher levels of revenue.

G&A for the quarter was $11.1 million, down from $12.8 million last quarter primarily due to employee compensation. We expect G&A to be around $46 million to $48 million for the full year. Depreciation and amortization for the quarter was $6.3 million, which is comparable to the last several quarters.

For 2017, depreciation expense is expected to be approximately $26 million to $27 million. The guidance we gave on our last call and past calls specifically excluded the impact of any FX gains or losses and assumed in effective tax rate of 15% for the second quarter.

So accordingly, our discussion today excludes any foreign exchange gain or loss for current period and prior periods. To conform to our guidance, EBIT, ex-fx for the quarter was $29.8 million and continues to represent best in class EBIT margins of 18.2%, a sequential increase of 270 basis points.

Income tax expense for the quarter was $4 million at an effective tax rate of 15%. However, it will continue to be somewhat sensitive to the geographic mix of earnings between U.S. and other regions of the world. Net income ex-fx for the quarter was $23 million, up from $18.7 million ex-items last quarter.

GAAP net income was $22.7 million for the second quarter. Earnings per diluted share ex-fx were $0.52 and GAAP EPS for the second quarter was $0.51. As we move on to significant aspect of the balance sheet, I'm only going to highlight the items that have materially changed from previously reported balances.

Receivables stood at a $129 million, up about $7 million from March 31, primarily as a result of increased revenue. Our DSOs for the quarter came in at 67 days, up slightly from 65 days last quarter.

Inventory at $35.6 million is down over $1.9 million sequentially as inventory turns continue to improve at the same time demand for our products continues to expand. We expect inventory turns to continue showing improvement throughout the remainder of the year. And now on to the liability side of the balance sheet.

Our accounts payable were $41.6 million, up $5 million in the quarter as the business expanded. Our long-term debt ended the quarter at $233.7 million, up from $218.6 million in March 31st. Capital expenditures for the quarter were $2.9 million and $9.4 million year-to-date.

We expect capital expenditures for the year to be in $18 million to $20 million range. And we'll continue to adhere to our strict capital discipline as we evaluate the capital expenditure opportunities throughout the year. Looking at cash flow.

In the second quarter, cash flow from operating activities was $18.7 million and after cutting our $2.9 million CapEx, our free cash flow for the quarter was $15.8 million and $39.1 million for the first six months of the year.

During the quarter, we repurchased 55,000 shares under our share repurchase program at an average of price of $103.48 per share. Since the inception of the Company’s Share Repurchase Program in 2002, Core has lowered its outstanding share count by over 39 million shares, repurchasing shares at an average of approximately $41.30 per share.

Also, over this period Core has returned over $2.4 billion to its shareholders via share count reduction and dividend distributions. Our free cash flow conversion ratio which is free cash flow divided by net income continues to be one of the highest in the industry at almost 97% for 2017.

We believe this is an important metric for shareholders when comparing companies' financial results, particularly for those shareholders who utilize discounted cash flow models to assess valuations. I'll now turn it over Dick for an update on our guidance and outlook. .

Thank you, Chris. Let's talk about guidance for the upcoming quarter.

Internationally, several FIDs have been recently announced by oil and gas companies; however, activities for Core Lab relating to those FIDs are not expected to materially increase in 2017 as the operators are currently developing their project plans and should begin to implement those plans early in 2018.

Further, the international rig count does remains flat due to limited capital projects underway by international operators. That being said, OpEx is continuing to be spent by operators to maximize recovery from their existing producing fields. According to Baker Hughes, the land-based rig count in the U.S.

increased 15% during the second quarter and 44% during the first half of the year. We believe this increase is in response to the improved pricing of crude oil in the first quarter, when the average oil price per barrel was about $54.

However, in the second quarter, crude prices were more volatile as prices trended down as the quarter progressed and ultimately ended the quarter around $46. We believe that the crude oil price continues at the current level for a protracted period of time, and then the U.S. land-based rig count will begin to flatten in the second half of 2017.

If crude persists below $50 per barrel, the U.S. land-based rig count may actually contract in the second half as we do not believe operators can continue to outspend free cash flow with debt and equity markets likely closed to them for additional capital.

This observation is not withstanding the continual decline in the global crude oil inventories and the impact this will have once the decline falls below the five-year average inventory level. Further, in the U.S., We are experiencing the impact of the prevailing market and transitory industry issues of U.S.

labor and completion equipment shortages, which is expected to continue through year-end. The increasing number of DUCs, as reported by the EIA throughout 2017, is evidence that completions have not been able to keep up with the pace of drilling.

The shortage of equipment is an issue for operators getting crews to complete wells which are why DUCs went up. Many EMP analysts wrote about this as the issue became more problematic as quarter went on. The pressure pumpers spoke about this in their own vernacular on the recent calls.

The reason they are bringing equipment of out of cold stock is because they are short spread. They wouldn't be spinning money to bring them out of storages if they were not short equipment. And because they and other private pressure pumpers were short equipment in crews, DUCs in Q2 grew rather than shrink.

Remember, on our last call the discussion was about how quickly DUCs could be drawn down. Our revenue guidance assumes DUCs would go down not up and it was the shortage of equipment that all the pressure pumpers are now trying to rectify that caused completion they will be put off which caused DUCs to build and our revenue to be light.

That's the reason for the shortfall, as well as the increased use of diagnostics on multi well pad. A job for us is not complete until the wells have all been diagnosed which can be over at several months period. This compares to single well diagnostics in the past where revenue is earned one well at a time. Our U.S.

revenue is correlated with completion and stimulation events and large-scale reservoir rock and reservoir fluid characterization studies, rather than with immediate increases in rig count. Wells need to be drilled and subsequently completed, stimulated, and cored -- or have reservoir fluid samples collected -- before we can realize a revenue event.

Taking these transitory market conditions into consideration, we project third quarter 2017 revenue of approximately $165.5 million to $170 million.

As discussed in prior quarterly earnings releases, we expects to generate incremental operating income margins of up to approximately 60% early in the activity recovery phase, followed by historical incremental operating margins of approximately 35% to 45% well into the recovery phase.

We project that our operating income in the third quarter may range between $30.9 million and $33.5 million yielding operating margins of approximately 19%. And assuming a 15% effective tax rate, EPS for the third quarter is expected to range between $0.54 and $0.56.

Third quarter 2017 free cash flow is expected to exceed net income and we anticipate continuing our share repurchase program during the quarter. Now let's turn the call to Monty for operation review. .

Thanks Dick. In the second quarter, Core Lab scientists and field technicians continued delivery of new technology to our clients, to help them produce more oil and gas with greater efficiency, which in turn improves client cash flows. We appreciate the efforts of our employees to deliver these value added services and products to our client.

Q2 revenues of $164 million increased 4% over Q1 and generated $29.8 million in operating income excluding FX charges. Operating margins of 18.2% were up 250 basis points from Q1, 2017.

Reservoir description operations which are mainly focused on international areas generated revenue of $104 million and operating margin improved to 18.2%, a 160 basis points improvement. Most of this revenue is generated from OpEx budgets. In the second quarter, Core continued on a large multi well prospect offshore South America.

Fresh core were received in Q2 to further evaluate the reservoir potential of thick section of laminated sandstone.

Core's involvement so far includes proprietary well site core handling and stabilization techniques, dual energy CT scanning of the core and an extensive geological evaluation of the reservoir rocks, mineral logical, digenetic and core system properties.

Core's proprietary high resolution dual energy CT deliverables provides the client with a rapid evaluation of lithology, porosity, bedding architecture, rock strength formation ahead of geneity and net pay. In addition, it gave critical key guidance on sample selection for the traditional laboratory measurement that will follow.

The CT derived information was provided to Core's client before the rocks were removed from the inter core bare liner. This offers the client a substantial head start on their analytical program and greatly accelerated their understanding of the Core's stratigraphic interval.

In addition, routine rock property analysis is underway and continued its thermal porosity, thermal ability and fluid saturations. As the client evaluates the results of this fundamental work, the project will move into advanced rock property testing over the next several quarters.

Combined routine, advanced rock property test will use as input for log calibration and for determining hydrocarbon volumetric. Over the past several quarters, Core has discussed reservoir condition rock and fluid testing program that are being performed in the laboratory to evaluate their effectives of engineered gas cycling.

These tests were conducted as a means of evaluating enhanced oil recovery in unconventional reservoirs. Core has seen growing demand for these services over that time.

Pursuant to that in the second quarter, Core initiated a consortium in which members companies will collectively sharing results of laboratory test and support of their Eagle Ford EOR efforts. These tests will be performed at reservoir temperature and pressure on core and hydrocarbon samples contributed by the consortium member companies.

Given the positive reception to both proprietary projects and this initial unconventional EOR consortium study in the Eagle Ford, Core sees opportunities for additional unconventional EOR consortia emerging in the Western Hemisphere over the next several quarters.

Core sees this technology gaining acceptance, a joint test course between reservoir description and production enhancement operations was constructed to bridge laboratory and field scale test.

As Core's clients to look to upscale laboratory validated gas cycling method to field level projects, Core has been engaged to provide diagnostic services as a way to among other objectives determined if the injected gases are being contained within that targets stratigraphic horizon.

In the second quarter, Core performed diagnostic services on several EOR field projects and once multiple oil and gas base traces were deployed within the injection gas. While produced hydrocarbon in adjacent wellbores and stratigraphic horizons were tested for the presence for these traces.

From this diagnostic tracer testing, our clients are gaining insight into the reservoir volume being contacted by the engineered injection gas, as well as breakthrough times and inner well communication pass.

Understanding these parameter is essential to optimizing the engineered gas injection cycling program as they were increased the absorption efficiency on the target formation and ultimately all recovery factors. Core also initiated a joint industry project to examine the potential of the [Osage chalk] formation as an unconventional reservoir.

The [Osage chalk] has long been a conventional target for oil and gas exploration. But recently unconventional drilling and completion techniques have been applied with great success. There is a challenge in applying these techniques to this formation as it is not shale reservoir like most of the other unconventional plays in North America.

Evaluating the chalk requires more focused on carbonate geology and the incurrence of natural fracture system which enhanced the productivity of this reservoir.

Core has the experience and expertise to evaluate the chalk to help consortium members better locate and orient their well and determine the best method to complete them to maximize their return on investment.

Production enhancement operations more focused on North America activities grew revenues 13% over Q1 and operating margins improves 450 basis points to 18.1%.

Operators continue to adopt Core laboratory HERO PerFRAC perforating technology as completions in the long horizontal increase in state count and cluster intensity throughout North America shale place. In Q2, demand for HERO PerFRAC shape charges double that of Q1, which had exceeded the total use in the prior year.

HERO PerFRAC charges produced consistent entry hole size regardless of gun position to allow fracture initiation to occur at the base of the bore hole. They are specifically designed to improve the efficiency of fracturing operations in today's unconventional reservoirs by optimizing hydraulic horsepower and proppant pumping rates.

During the second quarter, a Permian operator visited Core Laboratories manufacturing facility in Godley, Texas to test the HERO PerFRAC technology in predetermined test parameter closely replicating typical field conditions and downhaul environment.

All tests results confirmed HERO PerFRAC performance with regard to consistent hole size resulting in a standard deviation adjust 2.2%, compared to an industry norm of greater 15% with conventional perforating technology.

Based on seeing these results, the operator decided to move forward to field testing with HERO PerFRAC charges for perforating operation.

Another Permian basin operator stated that they have been testing various diverter technologies and since switching to their own or to HERO PerFRAC charge; we have seen a more consistent calculated number of holes open after step down test before introducing the diverter.

It appears that the uncertainty around hole size has been reduced by using the HERO PerFRAC equal hole size charge and book.

Additionally, during Q2, a study of best completion practices using Core's diagnostic technologies and expertise to optimize key parameters such as stage contentment, cluster density, frac fluid clean up and diversion techniques was conduced by a Mid-Continent client. The study involved a significant number of wells across multiple basin areas.

Strategies were adjusted based on the diagnostic learnings over a one year period. Optimization yielded consistent stage contentment of the frac treatment, better frac fluid clean up and effective cluster stimulation at high cluster density through effective divergent methodology.

The operator observed dramatic production improvements in early flow data and a long term data indicates an improvement in the decline per month. The client estimated an increase in revenue at $15 million per well. With many more well planned for further development.

Diagnostics will continue to be used to verify completion effectiveness and to identify other opportunities to cost effectively recover hydrocarbons. Kate, we will now open the call for questions. .

[Operator Instructions] The first question comes from James West of Evercore ISI. Please go ahead. .

Hi, good morning, guys. Dave, your comments about lateral length somewhat I guess hitting their peak at this point was very interesting to me.

Could you perhaps expand a bit on that and the science behind that suggesting that perhaps we cannot grow in further lateral lengths and it's going to have to so maybe reduction in addition to that probably across their spacing perhaps closer to the wellbore. .

Yes, James, right now the average lateral length is about 10,000 feet. That expanded from number of years ago from an average of 7,000 -8,000 feet. The problem is the frictional forces in pumping the proppant and fluid at or about 10,000 feet. You don't get enough effective pressure to actually do a good job in fracturing the reservoir.

We are looking at fortune reducers to enable longer laterals to be drilled because we are still in the camp of longer laterals, more profit, more stages, closer clusters to increase the size or the amount of the stimulated reservoir volume because that is a critical factor not only in initial recovery efforts but in what we see as the next coming wave of EOR in unconventional reservoirs.

The amount of proppant should be humped probably will increase but it will increase in its complexity as well, where we can see 400, 200, 100, 70 and 30 mesh sand being used in some of the ultra complex completions of the future.

We are not seeing that as of yet because our profit consortia is still looking at the economic effects of pumping 400 and 200 mesh sand. Some of the earlier SPE papers do suggest that you do open up tertiary and secondary fracture networks using this find proppant.

So all of it is actually incredibly related in looking at trying to increase the recovery factors from this well. So right now we probably with the current technology are going to be limited to on average a length of about 10,000 foot on the lateral. .

Okay. That's very helpful and very interesting, Dave. On the EOR point maybe from Monty, the gas injection and I guess sometime reinjection part, how widespread is that testing today as you guys see that. Now it's so early days but are you seeing better adoption from more and more customers to drive that and enhance recover rate. .

We are seeing a lot more interest in performing the laboratory testing to verify on their rock and reservoir that this work and what's the best gas and what's the number of times you can repeat this gas, engineered gas injection because it's a process, over time that you can repeat and recover more.

That's a diminishing return but if you can repeat it a number of times, you are getting a lot more oil produced. So we are seeing a big increase there. As I mentioned, we are working -- our reservoir description and production enhancement have formed groups of performed -- have formed team.

We are working with clients in the field that are taking this to the field, that's early days, they are taking it to the field in certain areas we mentioned the Eagle Ford as one that's we worked on right now. And they are seeing the result that we would expect.

I also mentioned that we are looking into other areas we have interest from clients to expand into other areas where we will be forming up some more consortiums, projects with the number of clients coming together, working on methodologies and sharing in result.

But we are not at this time willing to give a roadmap to anyone as to where we are going on that. I know there is companies out there love to know so. We are working on those and that would be growing, James. It's a growing segment and is a very successful. .

The next question is from Rob MacKenzie of Iberia Capital. Please go ahead..

Thank you, guys. Actually follow up on the last question vis-à-vis enhanced or recovered, Monty.

Do you think you need to have the secondary and tertiary facture mix that's created by the finer proppant for this to work or is there a large-ish -- large enough applicable market with the existing wells for this technology?.

Actually, Rob, if you look at we probably need that tertiary and secondary fracture network so we remain open because the amount of stimulated reservoir rock was just the primary fracture system being open, is probably we are leaving a lot of reservoir rock as un-stimulated.

So we think that it's going to be a critical factor in making the EOR in unconventional a success. .

Okay. Thanks, Dave. Question for Dick in terms of the third quarter guidance, if I may, Dick.

In that revenue guidance what are you assuming for the number of unconventional wells that are completed and/or looking at a different way, how much you expect to see DUCs continue to build because by math it seems like you got have to -- continue to have DUCs building at a similar pace of second quarter to get revenue in the range you are talking about.

.

Yes. That's right. We are expecting DUCs unfortunately to continue to build. It has a diminishing ray as the year is progressed because more equipment has come on; it was like up 600 Q1, 400 in Q2. We would expect it to be up somewhat still and Q3 until these pressure pumpers can get more equipment out of stock into the field.

And it is certainly good news. We are hearing from some of the larger pressure pumpers that they expect all of their equipment to be out in the field in Q3, Q4 latest. So that's good news but until that happens, I think DUCs will continue to build. .

And would it be fair to say that pace of which wells are completed, the real swing factor results here at least until more international FI -- projects with FID?.

That's correct. .

Okay. And then final housekeeping question. What was the tax rate in your guidance? I might have missed that if you said that. .

15%..

The next question comes from Chase Mulvehill of Wolfe Research. Please go ahead. .

Hi, good morning, fellows. So on the EOR, I guess the couple of questions around that.

Could you talk about the incremental cost associated with basically taking the recovery from 9% to 15%?.

Yes. If you look at what is going to be needed at the well site, Chase, you are going to need some compression assets or you are going to take this engineered gas and injected into the reservoir.

And then you are going to need on the production site and that might are to be present, you are probably going to need some separator equipment because what we are going to do is inject this gas at pressures into the reservoir and temperature and then go ahead in the separator, go ahead and reduce those temperatures and pressures so we get hydrocarbon dropping out of that engineered gas solution.

So if you look at what the incremental adds are probably somewhere a $1 million and $2 million of additional assets at the well site or at the pad site. If you look at that versus an increase in let say a recovery of EOR of a million barrels, taking that at 10% recovery rate to 1.5 million -- 500,000 barrels, recover rate of 15%.

So you are going to next 500,000 barrels for $1 million or $2 million, I think that improves the return on invested capital for a client by a long way. So that's kind of what we are looking at for additional cost. .

And what basins are you looking at for this particular type of unconventional EOR?.

Right now all basins. We've got projects in essentially from all oil, liquid rich shale place. .

Okay.

In the address, if we think about I guess from a dollar amount, and we think about the addressable market for these unconventional EORs for Core Lab, could you help us kind of bracket the high end and low end for the addressable market for you guys?.

Don't know that yet, still very early days but as Monty said, we are getting a lot of client interest.

We have our technologically sophisticated clients and they run in front of us two and three quarters ago, but now we have a number of other players that are very much interested in increasing their EORs and along with that the return on their invested capital. .

Chase, the business mode is the same as all of other services. We have a price book and we have a cost associated with each one of these test. So for us, even though it's very preliminary or still early days, the service is commercial.

Every time we run one of these engineered gas tests to help the operator to determine which component of the gas stream works best, we are going to run the test, give them the data and an invoice at that time. So broadly speaking, it could -- each product could range between say $50,000 and $400,000.

And I think next point is what still open is how many of those will be running. .

Right. All right. One last quick one.

When we think about the production enhancement business for US onshore, have we seen a shift back to the higher technology products and services yet? Or is it still kind of your customers focused on the commoditize product?.

No. We are seeing a shift, actually away from the commoditized product. This HERO PerFRAC has been the most successful introduction of new technology at Core Laboratories since we introduced the HERO charge a number of years ago.

So they are looking at recovery rate and flow rates and we got a lot of clients that are opting for the advanced technology as opposed to commoditized product. .

And Chase you can see that in the EBIT margins. So not only do we have revenue growth in our products that is a very competitive to completions actually better than completion. You see our EBIT margins highest in the industry which also tells you of that makeshift towards higher margin products. It leads to better technology for the operators. .

Yes, with our product sales being up 27% in the quarter, I think that speaks volumes for the impact that technology is having. .

The next question comes from Gregory Lewis of Credit Suisse. Please go ahead. .

Yes. Thank you and good morning. Just on the reservoir description, in the press release you talked about the unconventional EOR project in the Eagle Ford, clearly that looks like it's up and running.

Could you just sort of kind of walk us through the lifecycle that in terms of when we should start to see that benefiting the company and then as a follow up to that, clearly it looks like there is opportunities to bring that elsewhere in North America. And I guess South America as well.

Could you just talk about where those look -- where we should be thinking about those new JIPs coming on line also?.

Greg, this is Monty. We are definitely as Dick said this is a commercial service that we are providing to the number of clients. It has been growing quarter-over-quarter and admittedly, you start small and it's growing to something significant. It's producing significant revenue for us now.

With the introduction this quarter of a consortium project focused on the Eagle Ford, we'll see that continue to grow and in both the laboratory test and analysis of those tests that we are providing to the clients.

The future direction on these consortium projects is into areas that are active shale projects around the US and perhaps in South America. But we are doing proprietary work in some of those now. It's just that we mentioned we are going to be bringing that to people as a consortium proposal in the next coming quarters.

So we are already doing proprietary work in a number of those basins. .

Okay.

But it's maybe something like maybe where we can get an incremental one -- maybe one or two year, is that how we should be thinking about that?.

One or two consortiums?.

Yes. .

Yes. But a consortium, several players and that's going to be -- it generate a significant amount of work for both the labs and scientists analyzing the test, each consortium will. .

Okay.

And then just on Dave on the prepared -- you talked about lateral length kind of due to frictional forces, as we think about until that issue is addressed, should we be thinking about kind of proppant intensity and even potentially staged counts stalling out until we can get that issue addressed to move lateral lengths longer?.

Well, actually we are still proponents that we need more stages and more per clusters. When we look at the amount of un-stimulated reservoir volume, it's still at an acceptable rate.

Right now just looking at an average shale reservoir, we should have stages that are no more than 240 feet apart, just due to the transmissibility of that reservoir rock in moving long chain hydrocarbon to the wellbore. There are very few companies that have that kind of density among that.

If you look at some of the most technologically sophisticated companies like Pioneer Natural Resources, their average stage length about 240 feet. So until the industry adopts that is average shale of what the number of stages and cluster should be, we should see that intensity continue to rise.

Also, we'll see the complexity of the proppant that should be pumped into that reservoir become increasingly complex with 400, 200, 100, 70 and 30 mesh sand being in used. And we've not seen any of that but stay tuned over the next several quarters. We'll see that complexity increase even more. .

The next question is from Sean Meakim of JPMorgan. Please go ahead. .

Hi, good morning. So maybe a similar question to the one on mix within production enhancement but from a different perspective. So you are talking about -- we talked in the past about pivoting to a higher end proprietary systems, not investing any more in the commodity systems.

Would you characterize that as a push from you or pull from your customers or both? And I guess I am just trying to get a sense for as you think about the updated guidance to what extent is this shift having an impact in terms of leading revenue on the table to competitors in order to focus on the higher margin business, and the trade off between top line and high calorie systems..

Yes, Sean. This is a function -- I have listening to our clients, talking about issues they are having. Completing this wellbores and developing a new product that addresses what was out there. So we will -- and that's at HERO PerFRAC, Monty talked about with consistent hole size.

And so we will always try to develop those and deliver those to our clients rather than some of the commodity product that just cover cost. And maybe during the downturn that makes sense, you are just trying to absorb your cost structure that is still fixed.

But in this environment, there is no reason for us to invest in the ability to make more of those types of products of those commodity products. We'll add capacity whether it's human capacity or investment dollars to sell more of these higher tech products and services. And you are seeing the result of those decisions in our ROIC this quarter.

And in the margins particularly in production enhancement at 18%. So the other ones you make commodity charges I think their reported margins are around zero. We don't think we are leaving valuable revenue behind. .

That's right. And I guess that's the point I am trying to get a better sense of the impact on top line.

That's where we have the biggest discrepancies where we thought the numbers could go and someone speaking about if we think it that the HERO PerFRAC and those types higher quality systems are taking market share that perhaps you could be -- growing faster than your raw market versus if relatively what the commodity systems are doing, how that can influence what we think about this business on the top line basis relative to the overall systems markets.

.

Sean, you can see that in a number that Chris gave on product sales being up 27% sequentially. So that is in response to the 21% increase in completions and it's an outperformance. So you are exactly right, the clients are demanding these higher tech products and it's been a much better as we mentioned in the release.

A much better mix of revenue that's generated these higher operating margins. .

Got it. Okay, thank you for the clarification. And then just one more on reservoir description. Just trying to sense or I guess talking about some of the -- I know FID opportunities were not -- international really were not really helpful to, material for the quarter.

But as we look out into 2018, how do we think about try to size the impact of those types of opportunities as they start to make the pay for P&L next year?.

So we said in the past that on these projects were they could take significant amount of Core say a 1000 feet at Core that we could generate $2 million, $3 million, $4 million, $5 million in revenue from each one.

And so as these FIDs actually turn into activity for us, I think that's how you can begin to put your arms around the size of the opportunity for us. .

Yes. If you look at reservoir description right now, essentially that represents OpEx budgets of all of our clients and performance or production maintenance programs around the world. There is very little impact on any of the FIDs that we have been announced to date. There is a little bit of revenue there but not much.

So essentially when you look at reservoir description, think about as about $100 million business baseline on OpEx, when you start to add FIDs in there, you start to add what Dick talk about $2 million, $3 million, $4 million, $5 million of revenue per project or core and fluid set generating incremental margins in the 60% plus range.

So you'll start to see those enter the scene probably in the first part of 2018. .

And I guess what's the timeframe or what's your - you are able to recognize this. I mean the cost of the project. .

Oh, many of them will be over several years certainly in a large scale field development and so you look at 2018, 2019 and 2020 and certainly these FIDs that have been announced especially on major field developments like [XL and Liza] that would be over a multiyear scope. .

Because we'll be drilling wells over a multiyear. So just to be clear they gave us a Core in 2018 we'll be able to recognize revenue relating to that one at that time. And then as continue to appraise and evaluate and do more science over the years, we'll able to recognize revenue for that work at that time.

So I just don't want to leave the impression that we can't recognize revenue until that entire project is complete. .

Probably 2 to 5 will be per core, so that will be multiple cores on that project. .

Correct. It's one -- or fluid. .

The next question comes from Blake Hutchinson of Howard Weil. Please go ahead..

Good morning, guys. First question, Dick, I want to hone in on a comment you made I guess regarding to nature of service base production enhancement business. And the fact that you are going from single well pump to multi well pad. And it sound like as we look at kind of completion activity versus your service related revenues in that segment.

You have a bit of invoicing mismatch which is making it more difficult to provide guidance in terms of when you might actually close that a job and it results in revenue and maybe you can just chat little bit about that and give us a little more color on that.

And I guess with that lead us to believe as you provide a Q3 outlook that I guess the outlook could brighten if you close out certain projects more rapidly. .

Okay. Let's talk from the first question. Historically, the diagnostics were done on a well by well basis for the operators trying to understand how well the completion of it in that particular well occurred. Or all my stage is flowing hydrocarbon as I saw it.

Are there issues with particular stages? And like we would be able to conduct those tests and run that analysis and diagnostics, invoice the client as we gave them the data for that one wellbore. So what we are seeing with pad is the complexity of the pad drilling environment, the question that operator have are more complex.

It's not just what horizontal spacing among these wellbore is, it's a vertical spacing as well. And so we are doing diagnostic now more on a per pad basis with multiple well so the evaluation is not really complete until the entire analysis of that pad is done.

And that's what we are talking about on the revenue recognition the really the project is not over until we evaluated all of those different wells and interplay among the wells. So you are right. It's not a revenue recognition problem or issue, it's just the way you recognize it.

We did see the impact of that in a quarter as a result of more and more pad drilling being done and the complexity of these wells being evaluated .So we did see that. We would expect though that over time that begins to become the consistent way of recognizing revenue and will reduce the lumpiness.

If we can get DUCs being either frozen at the current level or DUCs being removed from inventory, those are going to be good things for Core Lab. Those are additional revenue opportunities for us. And we just -- go ahead, Blake..

I guess as the close out period too hard to diagnose and makes it difficult to more difficult task right now to give forward quarter view. .

Yes. That the issue is, it's collaborative with the clients, they are looking at the data as we create the data and we are evaluating what the data means and what the actions of the operator could be.

So the timing of the completion of the project is a little more difficult to ascertain because you are not certain when that project is actually going to be completed. So that did cause a little bit of variability in our views going into the quarter versus what actually occurred by the end of the quarter. .

Okay. Thanks for that. And then, David, I just wanted to -- because there is some commentary in the release, it mainly looks like pertains to US sensitivity in the business around oil price faction over the second quarter.

But is that your sense from your reservoir description client base, specifically those entertaining major FIDs that push to the right from potentially the second half to early 2018.

Was it all in response to oil price deck or just the general vagaries of large project timing?.

I think, Blake, probably both. Certainly we would have thought we would had some projects underway by Q4, little more planning going into those with $45 WTI, and so some of that would have gotten pushed to the right.

Certainly and looking at additional FIDs being announced, we don't think those are going to be -- those are going to be delayed at this time owing to the fact that we are on a worldwide basis continuing to decline inventories. We think by the fourth quarter inventories will be below the five year average.

And every time we've gone below the five year average, we've had a nice increase in crude oil prices. And I think our clients are looking at that as well. .

The next question comes from Marc Bianchi of Cowen. Please go ahead..

Thank you. I guess first on reservoir description I wanted to ask because it relates to second quarter revenue here was down a little bit from the first. Typically, we see a seasonal bounce here.

Is there anything to call out? Or is just kind of the businesses evolved from where it was in prior period and we won't see those kinds of seasonality changes going forward?.

Yes, Marc, I think it was down less than 1% and that was just looking at just the business mix operating budgets essentially were flat from Q1 to Q2. So I wouldn't read into that at all. You can see that the margins got back above 18%.

So again we described this business as being about from an OpEx standpoint, about a $100 million a quarter with operating margins around 18%. As we start to put some FID revenue into that you get a lift of that level. So not much to read into Q1 to Q2 on reservoir description. .

Okay. Well thanks David and then I guess just logically following from there as we look to third quarter and the guidance that you provided. If I assume that all of the growth is in production enhancement and reservoir description is flattish. Is that sort of a good starting point or are there anything to looked at --.

Yes. I think Marc as it stands right now I think that would be a good starting point. .

The next question comes from John Daniel of Simmons and Co. Please go ahead. .

Hi, thank you for squeezing me in. Dave, you guys were early to highlight the growing benefits of more sand per well but I am sure you know yesterday Halliburton noted that it witnessed the reduction in sand per well during Q2.

Do you believe there is a trend by customers to reduce sand concentration? And if so, is that being driven by science or short-term strategies to reduce well costs?.

Yes. We are still proponents of longer laterals, more sand, closer clusters and more stages. I think the -- whether the amount of sand is pumped or not will decrease I think the complexity of the combination of sand that will be humped will continue to increase.

So from just a pure scientific standpoint, the greater amounts of proppant that can be pumped and the amount of reservoir volume to be stimulated, that's always a good thing for increasing initial production and EORs.

So if you look at it by basin by basis study, I think over the last quarter we still saw an increasing amount of sand being pumped basin by basin. I can't comment on well by well as completion techniques will change owing to the reservoir rock and what is being completed. .

And when you say increasing sand by basin, you are referring it to not in terms of total sand price but on a per well basis, is that fair?.

No. I am talking about on a basin by basin analysis. If you just look at the amount of sand consumed there. We haven't broken it down to a well by well. .

Okay, fair enough. Dick, your Q3 revenue guidance calls -- call on 1% to 4% sequential improvement.

Can you give us just a little bit of color on the split between the expected changes in the two segments?.

Yes, reservoir description is going to be flat. Is that how our expectation so the growth is going to come from production enhancement. .

Got it. And then, Dave, last one for you. I noticed in your guidance you appropriately called out the reality that rig activity could decline later this year.

I am just curious in your discussion with customers how likely is it decline and would you care to offer your view on the rig count call it by year and should we say in $45 -$50 environment?.

Yes. I think we stay in a $45 to $50 environment. You are going to have a number of the private operators probably laid down some rigs. So we wouldn't be surprised if we saw a contraction in the rig count by maybe 50 to 100 rigs by the end of the year.

That's kind of what our guidance is based on where we toned down what the expectation for revenue was for Q3. And it's based on a flat to possibly down rig count. They can't continue to outspend their free cash flow because in our view the equity markets and the debt markets will be much tighter this time around than maybe year or year and half ago.

All right, Kate, we will take one more question. .

Okay. The next question is from Stephen Gengaro of Loop Capital. Please go ahead. .

Thanks. Good morning. Dave and Dick, good morning. Hope you are well. I just I keep it relatively short.

I was like to get your take on this when any updated thoughts on kind of the stickiness of non-US non OPEC production and how you see that just kind of flushing from a macro perspective over the next several quarters?.

Yes. Steven, good question. Outside of Brazil we have a hard time adding any additional production outside of the US and OPEC. What other country is going to increase production that is non US non OPEC, outside of Brazil we can't get you that. So we think we see an expanding decline curve rate for non OPEC non US over the next couple of years.

And in our book it will have a dramatic effect on where crude oil prices go. .

Okay. Now that's helpful. And just as a just quick follow up to that. I think against this but when OPEC ratch its back production or can close production a bit, any impact on your work in those countries when that happens, I don't think so but just wanted to get your views. .

That's not really are going to affect our work very much. We need to continue doing what we are doing to keep the production going. And their reductions in production are not going to affect what we are doing in the OPEC countries. .

Yes, Steven, those are -- this tends to be very long-term projects. So they will not have any effect on the work that we are doing. .

Okay, Steven. Kate, so are going to wrap it up in summary. Core's operations continued to be positioned for activity levels in the third quarter of 2017. And we know the significant challenges away. But we've never been better operationally or technologically positioned to help our clients to maintain and 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 ahead.

The company remains committed to industry leading levels of free cash generation and returns on invested capital with all excess capital return to our shareholders via dividend and future opportunistic share repurchases. So in closing our 88th quarterly earnings release, we'd like to thank all of our shareholders and the analysts that follow quarter.

And as already noted by Monty, the executive management and Board of Core Laboratories give a special thanks to our worldwide employees that have made these results possible. We are proud to be associated with their continuing achievement. So thanks for spending your morning with us. And we look forward to our next update. Good bye for now. .

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect..