Core Laboratories N.V. (CLB) Q1 2017 Earnings Report, Transcript and Summary

Good day and welcome to the Core Laboratories First Quarter 2017 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to David Demshur, Chairman, President, and CEO. Please go ahead.

Thanks, Francesca. Well, 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’ First quarter 2017 earnings conference call. As a publicly traded company this is our 87th 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 Investor Relations. The call will be divided into five segments. Gwen will start by making statements regarding forward-looking statements. Then we'll come back and review the current macro environment, updating recent industry trends in EOR and tight oil reservoirs, the use of finer proppants, the limits of lateral length and the then comments on Core's intended use of Big Data, neural networks, machine learning and data analytics to increase efficiencies and reduce costs for our clients in evaluating their reservoirs. Then we will review 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 second quarter 2017 outlook and a general industry outlook as it pertains to Core’s prospects. Then Monty Davis 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 worldwide and major projects. Then, we’ll open the phones up for a Q&A session. I will turn it back over to Gwen for remarks regarding forward-looking statements. Gwen.

Before we start the conference call 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 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 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 GAAP financial measures is included in the press release announcing our first quarter results. Those non-GAAP measures can also be found on our website. With that said, I’ll pass the discussion back to Dave.

Great. Thanks, Gwen. I’d like to go over some macro industry trends that we are seeing and then make comments on our three financial tenets. Core has observed the emergence of four major industry trends that will shape tomorrow's oil field and Core Lab's client activates. Core is utilizing these trends to focus the company's technology to enhance the growth and profitability of Core and also its clients. The first major trends is the increasing client interest in enhance oil recovery from tight-oil reservoirs. Early work performed by Core has indicated possible increased recoveries from an average of about 9% in tight-oil reservoirs to 13% to 15% by utilizing engineered gas absorption techniques, gas cycling and the laws of physical and thermodynamics. Ongoing laboratory dynamic flow test look promising. We are now investigating the role of dense and complex completion and stimulation programs in the role in EOR's success. Increased recovery rates of these magnitudes can increase the client return on invested capital by some 40% to 50%, boosting client free cash flow and shareholder value. The second major trend is the interest in using finer proppants in the initial procedures in a hydraulic frac 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 stimulated reservoir volume. Therefore, increasing initial flow rates as well as the estimated ultimate recovery. Macro proppants pumped during the placement of the track pad could potentially boost type curves by tens of thousands of barrels with very little added cost. Afterwards pumping 70 and 40 mesh sand late in the frac process also appears to be critical for success. The third major trend is the continued increase in proppants loading and the number of stages per well. At the end of 2016 staged count had grown 34% for the year to an average of 40 stages per well with an average separation of approximately 200 feet. Proppants loading per lateral foot increased approximately 50% to 1,700 pounds during the year with an average rate well receiving now 14 million pounds of sand. However the growth in lateral length is been more muted showing only a 14% increase owing to frictional forces. However Core is currently testing friction reduction additives to try to ensure that lateral lengths can still be extended. Pad drilling and completion programs rule the day and are causing the recent disconnect in the number of wells drilled and wells completed in the last two quarters. The wells drilled and completions will start to mirror each other in the second half of 2017. Finally, the fourth major trend deals with the use of Big Data, neural networks related to machine learning, artificial intelligence and data analytics to increase our client's efficiency and reduce cost in evaluating their reservoirs. For example, Core a deckage user of Big Data will analyze data set from the company's deep water Gulf of Mexico II joint industry project to machine learn computers and scanners to describe thousands of feet of core in the project and then use data analytics to characterize and identify the key properties of superior deep water reservoirs. This can be applied not only in the Gulf of Mexico, but we believe it can be applied to worldwide deep water phases. 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 currently celebrating our 81st year of technological innovation. During the first quarter of 2017 Core generated free cash flow that exceeded net income for the 11th consecutive quarter as free cash flow has also exceeded net income in 11 of our past 14 years. Free cash flow in the first quarter was over $23 million and equaled 130% of net income, clearly one of the best in the oilfield service industry. Moreover Core converted over $0.15 of every first quarter 2017 revenue dollar into free cash flow, again leading the oilfield service companies. For Core's shareholders, free cash flow matters. Also during the first quarter Core once again produced oilfield leading return on invested capital for the 30th consecutive quarter. As activity levels continue to increase in North America and with more stable international markets with deep water bottoming in the second half of 2017, Core expects return on investment capital to continue to expand in 2017. Return on invested capital matters for Core Lab's shareholders. And finally, during the first quarter of 2017 Core returned over $24 million back to our shareholders via our quarterly dividend. Core will continue to return all excess capital back to its shareholders in future quarters via quarterly dividends and we are expected to reactivate and repurchase additional shares in the second quarter of 2017. The return of excess capital to our shareholders matters. I will now turn it back over to Chris and he will give a more detailed financial review. Chris?

Thanks, David. Before we review the income statement and balance sheet, I would like to highlight, the beginning January 1, 2017, we have revised our reporting segments. Our reservoir management operations which had revenues of approximately 7 million last quarter or less than 5% of the total company revenue are now combined and reported with our two primary segments reservoir description and production enhancement. Although this is not a material change to the segment reporting for comparison purposes, all prior periods are presented under the current reporting structure. Now looking at the income statement, revenues were 157.8 million in the first quarter, up 5.5% sequentially, which was led by the 19% growth this quarter in our production enhancement segment. The growth in both services and product sales were primarily attributable to the 32% sequential growth in our U.S. land based operations. Of this revenue service revenue was a 120.9 million for the quarter and up sequentially about 5.8 million or 5%. Product sales was 36.9 million for the quarter and up about 2.5 million or 7% sequentially. Moving on to cost of services, for the quarter are 68% of service revenue when excluding the 1.1 million of severance and other charges associated with streamlining some of the operations. Compared to the 72% last quarter, this is a nice improvement and we continue to maintain some of the strongest service operating margin amongst oil field service companies. Cost of sales in the first quarter was 84% of revenue also a nice improvement from the 87.5% last quarter as our operating leverage and the absorption of our fixed cost improves with higher levels of revenue. G&A for the quarter was 12.8 million up from 8.8 million last quarter which is primarily related to employee compensation. Using the first quarter as a basis, we expect G&A to be around 46 million to 48 million for the full year. Depreciation and amortization for the quarter was 6.4 million, which is comparable to the last several quarters. We would expect capital expenditures and associated depreciation expense to increase as the year progresses and be in line with our operations and the capital projects that support these operations. Our 2017 depreciation expense is expected to be approximately 26 million to 27 million and total capital expenditures to be in that 18 million to 20 million range. Other expense was 900,000 for the first quarter and primarily includes the severance and other charges mentioned earlier. The guidance we gave on our last call and past calls specifically excluded the impact of any FX, gains and losses and it seems an effective tax rate of 14% for the first quarter. So accordingly, our discussion today excludes any foreign exchange gain or loss for current and prior periods and also excludes to the 1.1 million of severance and other charges incur during a quarter as part of streamlining of business. To conform to our guidance, EBIT, ex-items for the quarter was 24.4 million and continues to represent best in class EBIT margins of 15.5%, a sequential increase of 80 basis points. Income tax expense for the quarter was 2.9 million at an effective tax rate of 14% which is consistent with our guidance. We expect our effective tax rate in Q2 to be approximately 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-items for the quarter was 18.7 million, up from 18.3 million last quarter. GAAP net income was 17.7 million for the first quarter. Earnings per diluted share ex-items was $0.42 for the quarter compared to our prior guidance of $0.38 per share. GAAP EPS for the first quarter was $0.40 per share. As we move on to the balance sheet I'm only going to highlight the items that materially change from previously reported balances. Receivables stood at a 121.8 million and as a result of revenue continuing to increase as the quarter progressed are up about 6 million from year end. Our DSOs are unchanged at 65 days, a testament to not only the quality of our customer base, but the company’s continued focus on managing the working capital aspects of the business. Inventory at 37.5 million, up about 3.8 million sequentially as demand for products continues to expand and we expect inventory turns to continue showing improvement throughout the remainder of the year. Intangibles, goodwill and other long term assets at 251.7 million, so down about 5 million from year end. The change is primarily related to a decrease in deferred tax assets. The net change related to both current and deferred tax substantially offset and were neutral to both the balance sheet and operating cash flow for the period. And now to the liability side of the balance sheet. Our accounts payable were up 36.5 million from 33.7 million, so an 8% increase sequentially for the quarter. Our long-term debt ended the quarter at 218.6 million, so up just slightly from 216.5 million at year end. Capital expenditures for the quarter were 6.4 million an increase from prior quarters as expected with the growth in operational activities. For example this quarter we invested to build out our footprint in Asia Pacific region. The company has the ability to increase its investments and support of these strengthening activities and we’ll continue to adhere to our strict capital discipline as we evaluate the capital expenditure opportunities throughout the year. As mentioned earlier we expect capital expenditures for the year to be in the 18 million to 20 million range. Looking at cash flow, in the first quarter, cash flow from operating activities was 29.8 million and after paying our 6.4 million in CapEx our free cash flow for Q1 was 23.3 million representing $0.15 for every dollar of revenue. 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 132% for the first quarter of 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 will now turn it over to Dick for an update on our guidance and outlook.

Thank you, Chris. As has been the case for past recoveries we expect our revenue growth to ultimately outperform the increase in industry activity rates by about 200 to 400 basis points. We expect to generate incremental operating income margins of up to approximately 60% early in the activity recovery phase followed by our historical incremental operating income margins of approximately 35% to 45%, well into the recovery phase. Our North America revenue is correlated with completions and stimulation events and large scale reservoir rock and reservoir fluid characterizations study 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. We are benefiting from increased U.S. onshore activity and do expect revenue and operating income to increase further in 2017 as international and offshore markets improve with additional major capital project announcements. We expect our deepwater revenues, which are currently 15% of the total Company revenue, to bottom in the second half of 2017. Activities relating to new project announcements should drive our revenue higher in consecutive quarters throughout 2017, further expanding incremental operating margins. As we projected, our third quarter 2016 results did establish the bottom of the expected V-shaped recovery that we expect will continue in 2017. We believe that the global crude oil market is currently under-supplied. This is indicated by recent International Energy Agency data showing that worldwide crude oil inventory has declined over six of the last seven months. From July to December of 2016, worldwide crude inventories fell by an average of approximately 770,000 barrels of oil per day. In addition, considering the January 2017 OPEC cuts of approximately 1.3 million barrels of oil per day, plus cuts from cooperating non-OPEC producers, including Russia, the world market could be under-supplied by more than 2 million barrels of oil per day. The continued under-supply of crude oil should lead to extended worldwide inventory declines and a continuing rally in energy prices throughout 2017. Now for the second quarter of 2017, we do project our business to improve further, primarily from increasing activity levels in the U.S. and stable-to-up international, offshore and deepwater markets, offsetting lower Canadian activities due to spring break-up. International rig counts have increased 3% in the first quarter, a second consecutive quarterly increase after eight consecutive quarters of decline and in the U.S. offshore market, new well permits in the Gulf of Mexico increased 13% over year-ago March levels. We project second quarter 2017 revenue for Core Lab to approximately 165 million to 170 million and EPS ranging between $0.48 and $0.52. Operating income is expected to range between $27.6 million and $29.9 million yielding operating margins of approximately 17%, and Company-wide sequential quarterly incremental margins to increase sequentially to approximately 45%. Second quarter 2017 free cash flow, once again, is expected to exceed net income and we do anticipate reactivating its share repurchase program during the quarter. We expect the effective tax rate for the second quarter to be approximately 15%. Now with that guidance we would like to turn it over to Monty to give a more details of operational review.

Thanks Dick. First quarter 2017 revenues grew up to 158 million, up more than 5% from Q4 2016. Operating earnings ex-items increased 11% to 24.4 million at an operating margin of 15% up 80 basis points. Core's talented employees around the world are continuing to bring value to our clients through service and technology. We thank every one of them for their contribution to the company. Reservoir description as previously projected at Q1, 2017 revenues at the same level approximately as Q4, 2016. Operating earnings of 17.3 million, yielded a 17% operating margin. Increased exploration and development of unconventional reservoirs in the Permian Basin, South Texas and Rocky Mountain regions of the United States continue to drive the need for enhanced oil recovery testing capabilities at our Houston advanced technology center. In the laboratory Core Lab is uniquely able to deliver the proprietary reservoir condition fluid testing, gas cycling experiments, and ultra-high frequency NMR diagnostic techniques that are required to understand how EOR programs can improve recovery in these oil plates. Many large and midsized oil and gas operators are working with Core's technical experts to design reservoir condition laboratory programs to determine how the variables of lithology, core system properties, organic matter, content and composition, oil properties and gas cycling methodologies will impact enhanced oil recovery efforts in their reservoirs. Incremental production increases are frequently being seen in the laboratory test and the gas fluid rock interactions are being evaluated from various basins around the U.S. When deployed in the field these incremental production opportunities have the potential to both improve our clients' initial rate of return and help them increase the EOR from these unconventional reservoirs. During 2016 Core began conversations with operators wanting to examine how these proprietary EOR technology techniques might be applied to unconventional reservoirs outside the U.S. Multiple large scale projects offshore South America continue to generate both rock and fluid work in Q1. These multi-well programs are testing the reservoir potential of high quality sandstone targets. Well site and laboratory work on these projects will progress into subsequent quarters as our clients accumulate and evaluate the data needed to make final investment decision on these assets. Reservoir conditions laboratory work includes a full range of basic and advanced rock property test, PVT analysis, higher resolution dual NGCP and micro CT imaging and analysis, as well as geomechanical testing for well bore stability assessment. Also in Q1 reservoir description initiated a new joint industry project, focusing on the deepwater plays of the American portion of the Gulf of Mexico. This Phase 2 study builds on our original deep water Gulf of Mexico study and will incorporate cores and data from wells and discoveries that have been made since the original study, which was supported by over 50 clients and was completed in 2012. Much of the activity since the completion of Phase 1 has been in an increasing deeper water and has targeted not only the Eocene to Paleocene reservoirs, but the lower Miocene as well. The intent of the study is to characterize deep water reservoirs, evaluate the seal [ph] capacity and examine the engineering components of the play to substantially reduce the risk associated with deep water exploration and development in the Gulf. Aside from the offshore plays, onshore plays in the U.S. remain active. The ongoing rounds of mergers and acquisitions continue to generate interest in Core Lab's controlling studies particularly in the Permian basin. Core continues to sell existing joint industry project studies and conduct proprietary work on behalf of Core's clients to evaluate various assets that are acquisition potentials. Core provides the knowledge and data that mitigates the risk associated with these reviews. Production enhancement Q1 revenue of 53 million grew 19% sequentially over Q4, 2016 with U.S. land operates leading the way with 32% sequential growth. Operating earnings of 7.2 million yielded 14% operating margins, more than doubling those of Q4. Core's ballistic engineers continue to broaden the HERO PerFRAC product line to adjust increasing client demand for a consistent hole size throughout the perforating cluster. Conventional perforating in a horizontal well results in varying hole sizes with a larger hole on the lower side and a smaller hole on a high side. Core's HERO PerFRAC provides an equal hole size throughout the perforating cluster. Specific completion designs can be satisfied with equal hole size selections resulting in lower hydraulic pressures perforating and providing optimum flow rates for the placement of proppant which intern increases the stimulated reservoir volume. Lower hydraulic pumping cost and increased SRV result in a greater return on investment for Core's clients. For the third consecutive quarter our HERO PerFRAC perforating technology experienced an increase in utilization. Usage of perforate technology and the Midland Basin, Woodford Scoop and Eagle Ford Shale was up 52% sequentially from Q4 to Q1 '17. In a recent Wolfcamp completion study, Core Laboratories has unified an opportunity for operators in the Midland Basin of the Permian to eliminate some frac stages that were not cleaning up effectively port frac and were not contributing hydrocarbon production. Core diagnostic technology shows that part of the lateral had intersected depleted faults and thus were accepting the frac treatments and communicating with offset wells in many cases, but were not proving to be productive stages. Operators using Core Lab diagnostic technologies can confirm the presence and effect of these faults and save the cost of the frac stages for those intervals where the laterals are shown to intersect these faults. This provides a cost savings for every eliminated frac stage. Core Laboratories have the number of operators in the Permian Basin that are using Core's diagnostics standard pressing questions regarding well spacing and landings zone effectives. These two issues along with diversion valuation an engineered perforating appear to be hotspots in most areas. Permian Basin activity continues to escalates in many operators are using Core Lab's completion diagnostics to answer those difficult questions on optimum well spacing and effective drainage areas. Quantifying inner well communication and evaluating a long-term effect on production is one of the most challenging issues in West Texas. Recently several operators are utilizing Core's fluid diagnostics and extensive Permian Basin knowledge to determine the viability of having two different landing zones within the upper Wolfcamp intervals. Traditionally, most operators have a single landings zone within this interval. Recent drainage area evaluations indicate that additional production points might be necessary to drain these reserves effectively for the upper Wolfcamp. Evaluation of various diversion techniques to direct the frac of each perforation cluster is also a very important question that the West Texas operators are activity addressing, Core is uniquely positioned to capitalize on this surge and diversion activity. Core's zero loss technology in conjunction with Spectro scan services provides the only direct measurement for diversion evaluation. It is specifically designed to quantify narrow well bore proppant coverage and overall perf cluster efficiency. Francesca, we'll now open the call for questions.

We will now begin the question and answer session, [Operator Instructions]. The first question comes from James West of Evercore ISI.

So a question on, so obviously the North American market, particularly the Permian is exploding with activity here on your production enhancement business, I know we hear about a lot of longer lead times or wait times for frac spreads and even water line trucks [ph], stuff like that. How do you see or what [indiscernible] manufacturing of your proppant's charges in order to catch up with the increasing demand and are you guys now running kind of full house in terms of manufacturing?

James this is Monty. On the charge production we have increased the number of active manufacturing base. Obviously during the downturn those were decreased to a lower number and we have reactivated some of those with plans through the second quarter to reactivate most of what we had active capacity when the downturn started.

And James we wouldn't count out the Stack B as being competitive with some of the sweet spots in the Permian as well.

Okay, fair enough, fair enough. And then Dave maybe a bigger broader question and I apologize if you addressed this in the earlier -- in your initial comments, if I missed this. But as we think about the global oil markets right now there is rising fear, at an industry conference right now, there's a rising fear about Permian or U.S. production this year underwhelming at least for the first part, but next year kind of overwhelming the market. Could you comment on your thoughts on your global production vis-à-vis your U.S. the non-NIM [ph], non-OPEC and how that will play out in '18, '19 and '20 and [indiscernible] view that will be under 5% a year, is that what your hearing in your review?

James first of all give me -- give us some demand growth numbers for '17, '18, and '19?

1 million plus.

Yes, 1 million plus a year, so this year people are looking a 1.1 million, 1.2 million. If you apply the worldwide -- our most recent worldwide decline curve rate which is 3.3% you add in what can be expected to be gained out of U.S. production, so maybe this year 300,000 to 400,000 maybe 500,000 barrels, you apply that worldwide decline curve with the paucity of legacy projects out there in deepwater and over the last years we've benefitted especially here in the Gulf of Mexico of adding production via legacy projects in the deepwater. We start running out of those in '18, '19 and '20 worldwide and certainly a '19 and '20 in the deepwater Gulf of Mexico. So crude oil markets right now, we see as under-supplied and only to get tighter.

And in that 2 million barrels a day, I believe that Dick mentioned, that increases from here I'm assuming?

Well, that might be offset with gains in U.S. production, but if demand is north of, I think we used 1.2 million for a couple years out, certainly that gap can grow larger.

Got it. And so do you -- I know you have look at our work and have your own views, but inventories adjusted for demand, you will see that as at least droppable [ph] 40 days here probably by end of the year, I assume.

Yes, we think Doug has done some great work on that, Doug Teneson [ph], and our projections have it below 40 days actually a little earlier than you guys.

Okay great. Thanks guys.

The next question comes from Rob MacKenzie of Iberia Capital.

Great, thank you guys. Monty, I guess a questions for you. Help us put the stat you gave us for HERO PerFRAC in the contact a little bit, if you well. I think you said the use of PerFRAC about 52% quarter-on-quarter from Q4 to Q1 in '17, how would that look more broadly across the production enhancement segment, perforating versus the diagnostics business there, which one is growing faster among the two?

Well, they are both growing at a pretty fast rate at the momentum. We kind of keep up with it. But really the growth seems to be jacked up in the second quarter. We are looking at a little bit of growth in the perforating, but they're both growing big time. Land which includes both service and product is up 38% and products being a little less of that.

Yes, to boil it down Rob, still the diagnostics is seeing faster growth over the products that probably will tend to even out as the number of completion start to catch up with the number of wells drilled. And we are seeing a disconnect there because wells are being completed and stimulated by the pad. So you do have a delay between drilling the seven or eight or five wells that might be on the pad and then bringing those services in.

So that was actually part of my next question, how does the resuming tend towards more pad or more multi-well pads upset the diagnostics business, I would think there could be a positive benefitted if you want to make sure the well's aren’t matching or even maybe are matching depending, does that affect the diagnostics business for you guys?

Yes, it should does, for us that is a big part of their business right now. As people try to concentrate wells on spacing and then landing zones in the suites spots, we are seeing more wells bash each other. It's a concern in the industry now that more bashing is leading to the loss of initial production, especially EURs. So their business on a diagnostic side is being aimed more towards that now than it ever has in the past.

Okay, and then shifting towards the SRV concept, I know you guys were talking about that for a little while, help us frame that. What do think simulated reservoir volume was say in 2014 versus today, versus where you think that might go?

Yes, I think, Rob actually on the conference calls back then, we talked to the amount of simulated reservoir volume was probably in the low 20 percentile range, now with the use of finer and micro proppants we think that that is expanding rapidly and the reason for that is the use of 400, 200 and a 100 mesh sand in the pumping the pad stage or opening up tertiary and secondary fracture systems to the exposure of surface area. That has never happened before so it is significantly increasing the amount of stimulated reservoir volume, read that the amount of surface area in reservoir that is open to a micro fracture. So I would put that right now probably in the 50% range, so we've significantly increased it since 2014, you can see that in the production in the production figures and also in the type curves, you can plot that pretty much right alongside of that. How much further it can go, we've just now entered looking at 200 and 400 mesh sand, so we'll give you an update over the next couple of quarters on the effectiveness of using those micro proppants.

Are we seeing field tests right now with 200 and 400 mesh sand and any kind of early results you can share?

Yes Rob, actually there are several good SPE papers that are out. If you want those numbers you can just send me an email or call me afterwards and I'll make -- we’ll make those available to you.

Okay thanks, and then one question for Dick if I may. Dick I guess you guys stated you are planning to reactivate your share repurchase program. Where does paying down your revolver stand in order of priorities, if at all?

At this current level, on the revolver, it’s not a priority. So on the use of free cash it would be dividend first, share repurchases second.

Thank you, I’ll turn it back.

The next question comes from Ole Slorer of Morgan Stanley.

I wonder if you could elaborate a little bit on the margin trend in the quarter and your reservoir and description? So it came in a little bit light compared to expectations and then of course you had an extraordinarily strong products production enhancements sort of margins and whether this was driven by product mix or how it's trend over the coming quarters, if so?

Yes Ole, if we look at reservoir description, a little mix there on service revenue, but more seasonal than anything there. When we look at the revenue, it stayed mainly flat on reservoir description and margins down a little bit. We expect that to start progressing up from a revenue and margin standpoint as early as the second quarter. With the incrementals and production enhancement being fueled by the rapid acceptance of HERO PerFRAC, we actually still see those incremental margins sequentially quarterly, actually continue to increase. We actually see that continuing for a number of quarters, if you go back to 2010, '11 and '12, into the '13, you will see that we can have an extended number of quarters where we have incremental margins increasing in the 50% to 60% to 70% range for production enhancement. So with continued activity levels being strong in the U.S. as they are now, and the acceptance of HERO PerFRAC by our clients there is no reason why we shouldn’t continue to see a progression in those incrementals driving the underline margins.

Okay, so the HERO charges the most profitable product line that you have and the catch up in frac activity and to drive towards, so in other words, that mix change has continued to drive the margins higher?

Yes, I would say completion for perf frac, okay, if a completion follows that in stimulation, we would agree with that.

Okay. Second question here, there are some broader implications, the use of this finer proppants becomes a success. What will some of the broader industry implications be that you can think of?

Certainly, I think of this as opening up new fraction facings within the reservoir that weren’t open yet. So what we are doing is we are adding additional macro proppants all the way down to a 100 non-API mess. Going into the secondary and tertiary fraction, we don’t think that makes a delta for, the use of, let's say a 70:40 mess, sand mix after that. But certainly the frac will become more complex over what is being pumped during that, perhaps you can see an early 400-mess sand in the early pad, mid-pad 200-mess, late-pad 100-mess followed by 70 and then a 40. There are some of our clients experimenting with that right now, we are doing dynamic flow tests right now. So that will be interesting to see how that evolves. So it might open a new market for the macro proppant and should have not a big effect on increasing demand for northern white or brown sand of the 70:40 or somewhere around that mess for the industry.

In total what does it do to the use of sand for such drilled or the proppant loading as you refer to?

Yes, proppant loading will continue to increase. There is going to be some changes on the way that proppant is being pumped. We see faster rates and greater proppant loading, that is going to be offset by greater frictional forces that we mentioned. Right now we are doing some work for clients looking at friction arrestors, so we can have faster pump rates, higher levels of proppant loading, trying to get out to longer laterals. On the laterals side, because of this frictional force, we are starting to see a limit on how far they can go unless we can overcome this frictional force. Moreover a second avenue limiting laterals is just a metallurgy on the coal tubing, how far can we go out. Today's metallurgy would suggest that we're nearing those limits once again.

Interesting and finally any overlap here in the [indiscernible] whether the EOR were expected to do from 9% to 15% that sounds pretty impressive. There are one or two companies that are working on that today, but maybe it's much broader than what they think and what are the implications and opportunities as for your company if this thing takes off?

Yes, if you go back to the first quarter conference call last year, this was when we first mentioned EOR and tight-oil, we thought this was going to replace a lot of the static testing of tight-oil reservoirs and indeed that is exactly what's happening. We've had a significant increase in the number of projects that we're working on and for EOR and tight-oil, we see that continuing to increase. The testing that we've had so far in lab is very encouraging, tied to that we think these more dense and complex completions are going to be critical for the success of the EOR to work. So if you have a mundane run of the mill completion you might not get the upscale benefit of the EOR unless you completely have surface area exposed to the fracture networks and we're seeing a tie between the 400, 200 and 100 to the success of the uptake or the increased recovery from the EOR from gas cycling in the tight-oil reservoirs. We think it’s all related.

Sounds like it could be a new interesting driver for your description business, I'm a little surprised at some of the names that you listed in your consortia, I suppose I can ask you about them, companies like Saudi Aramco, what are they trying to get out of this?

Well if you look at the companies that are involved in this consortia, and again this is a 30 year endeavor by the company looking at the importance of this, Saudi Aramco has made a very concerted effort over the last two to three years to look at exploiting tight, essentially their natural gas reservoirs in Saudi Arabia. Their target is to displace the burning of crude oil for water desalinization and power and replacing that with natural gas, freeing up more oil for export. So they're looking at it from a standpoint of what their unconventional reservoirs would take from a profit standpoint to maximize the effectiveness and efficiency of those completions and stimulations there. So just like any other company they're looking to exploit the knowledge from the consortia back to the reservoirs.

Thanks for the insight Dave, I'll hand it back.

The next question comes from Kurt Hallead of RBC.

Always very informative, so I appreciate all the color you guys provide. So one follow up on my end right, you've spent some time earlier on the call talking about some of the offshore dynamics and how you see that evolving. So there has been some recent discussion by major service company about some fields that they've been involved in and seeing accelerating decline rate particularly in the Gulf of Mexico where they might have been historically 5% decline rate and with oil companies leaning heavily on trying to generate cash flow now, kind of pushing those reservoirs hard so that decline rates are now potentially approaching 20%. Just trying to collaborate that, what kind of things have you seen on some of the fields that you have been working on?

Yes, some of the new fields of course that are have recently come on production. We would say that the depletion rates there are less, just owing to better completion stimulation techniques. If you look at a lot of the order fields, I think you are referring to the depletion rates of the reserves, indeed those are higher because we pretty much maximized what that reserve base is going to be and what the ultimate recoveries going to be. So those depletion rates are increasing and will increase even with a static decline curve with the addition of additional production. For instance, we have actually Gulf of Mexico offshore production, deepwater up again this year and then up again a little bit next year, continuing to offset some of the increasing depletion rates from some of the shelf fields that are producing in the Gulf of Mexico. So net-net, what that means is that when we look at -- and this gets back to, James West's earlier question, when you get into the '18, '19 and '20 areas, you are going to have [indiscernible] of projects that are going to be meaningful coming on for production other than a handful that we have mentioned in the past. Now we see much tighter crude oil markets.

Okay, great. Now I think in the press release you guys mentioned roughly 15% of your total company revenues come from offshore --.

Deepwater.

Sorry deepwater not offshore, okay. And then that peak was around 20% something like that?

That is.

And you mentioned that the deepwater or the -- again trying to get some metrics right here, okay. So the deepwater also market bottoming now in the second half of '16 or '17, excuse me. So how long do you think it would take before your deepwater revenues kind of get back to that 20% or prior peak level, how do you see that evolving?

You are probably in -- certainly into the second half of '18.

That's relatively short term, okay.

Yes, you have got a -- Kurt, if you look at the number of FIDs that are online, coming up, all those weigh into the amount of exposure that we have for deepwater developments. So we like that trend that we are seeing. In just recently you seen BT talk about the sanctioning of MadDog II, we believe that offshore Guyana, those projects are lining up to be FID perhaps later this year. So you have a number of major projects that we certainly will be involved in to help fuel that revenue out of deepwater.

Got it. All right thanks. Appreciate it.

Next question comes from Sean Meakim of J.P. Morgan.

So just a follow up on some of the margin question, and we talked about [indiscernible] cycle incrementals approaching 60, that’s kind of where you were in the first quarter. The HERO PerFRAC clearly helping, and thinking about the traces in diagnostics, how materially accretive are those to the market, can you help us think about their contribution?

Yes, those are some of the most accretive Sean to our incrementals. Because you think about that service, we are sending engineers at to the field and if it was a single well versus the trend now to pads, well the incremental cost for us is not that great of doing one single well versus say doing five or six wells trying to understand the communication among the wells. So in that environment and that’s the trend that we are seeing now, those are certainly very accretive.

Got it, okay. And then on reservoir description, coming up on the margin discussion there, how much -- just thinking about the mix shift would be broader, how that kind of impacted the margin this quarter? Because it's sounds like you are saying that on the one hand you don’t expect deepwater activity to bottom until the second half of the year, but you think we've already got there in terms of the margin bottoming and I'm just curious how we should be thinking about the different levers between rocks and fluids and land shallow water and deepwater?

Sean, think about the revenue stream right now from deepwater, it's really fluids based around the producing fields in deepwater. And that’s what's given such great stability in not just the revenue, but in margins in reservoir description through this down time. So our expectation with these FIDs is we'll begin to see capital projects thrown into the mix. On top of the existing OpEx project, not projects, but just OpEx budget work that we have right now. So in other words right now the revenue stream is coming from the producing fields, now let's thrown in some projects from these new FIDs that are capital oriented, that’s what really going to drive margin expansion in reservoirs description.

Got it, okay. Great thank you.

The next question comes from Gregory Lewis of Credit Suisse.

I just want, hoping to follow up you know Rob's comments on sort of trying to -- he was talking about market share gains between the -- you know the HERO and the per perf systems and diagnostics. Are you able to provide any color around -- you know I mean clearly there is a huge growth demand for these we're seeing? Is there any way to sort of parcel into which one is actually seeing more traction around pricing?

Yes, prices have not changed. So it's utilization and activity levels.

Remember Greg that's true on the downside of the cycle as well, our pricing didn't change. So on the upside of the cycle that's the same business model.

Okay great, and then just you know one real quick one from me, clearly that HERO PerFRAC, you guys mentioned that it's your best launch, what metrics are we using to sort of think about that? I am just trying to understand, I mean it seems obviously the numbers are looking good, but what do you mean by that?

Revenue generation, that's the way we measure it.

Okay, alright guys, thanks for the time.

The next question comes from Chase Mulvehill of Wolfe Research.

Couple of quick questions and maybe you've already answered this, but I'll throw it out there. On reservoir description margins did you provide any color on expectations for 2Q?

We gave general revenue guidance for Q2, nothing specific for reservoir description or production enhancement, but we would expect both of those, both revenue and margins to be up next quarter.

It helpful. And then talking about the 200 and 400-mess sands, could you talk about if there is any limitations whether it's basin, whether it's closer stresses or anything like that?

We early days on that, Chase.

Okay, all right. And when you look at it these mess sizes, is this incremental sand pumps or are you swapping kind of courser gran sands for this 200 and 400 mess sands?

No these are incremental sand pumps because of this secondary and tertiary fracture cycle that we are opening up. The courser mess sand cannot get in there. So this would be incremental sand pumped.

Okay. And when you talk about larger casing size and we've heard this from a lot of ENTs as well, how should we think about the limit zone, how big these casing sizes could go? I mean I know that some of the service equipment designs right now limit that, if you think about set back capacity or stuff like that on rigs, assuming there is no limitations on service equipment, from the science end, is there a limitation? I mean can we go to 12-inch casing, 14-inch casing, 15-inch casing, or does the science say that's just too much?

Yes, that just too much. We are talking about maybe increasing casing size an inch or two or three.

Okay all right.

We are not talking about running that large of a casing load down there.

Okay all right. And then just if we think about trying to translate all this that you're thinking about doing from your testing 200 to 400 mess sands, more SRV, how does all this kind of translate into incremental revenue for Core labs?

Well, it's an analytical testing revenue all the way around. We are testing the proppants for our consortia, where we are using dynamics flow test for our clients in their own specific proprietary fracs. If we look at the incremental amount of production out of EOR, again that’s all analytical work in the lab on rocks and fluids. So it's just our price list and the amount of work that we do either in the lab or out in the field.

Okay, also lastly and I’ll turn it back over. When you talk about SRV and talk about it being up, have you looked at it on a per lateral foot basis and how that’s increasing and how close do you think we are maximizing SRV on a per lateral foot basis?

We do look at on a per foot basis, we don’t know the answer to the second question.

Okay, awesome. I’ll turn it back over. Thanks.

The next question comes from Marc Bianchi of Cowen. Q - Marc Bianchi Just really one from me, as it relates to the buyback, you mentioned you are starting backup here in the second quarter and traditionally the formula have been to use the free cash flow after dividends for the buyback, but considering that positive outlook that you have got V-Shape recovery here, stock price maybe not reflecting all of that, would you be inclined to move outside of that guideline and perhaps use the balance sheet to buy back some stock?

It's certainly possible, yes.

Okay that’s all I have. Thank you.

Okay Francesca, we will take one more question.

The final question is from Stephen Gengaro of Loop Capital Markets.

Really one thing left that I just wanted to touch on. When you think about the industry and you see what's going on with sort whether Schlumberger, JV and Halliburton. How does this impact Core Labs, or does it? When you think about especially on the production enhancement side?

.:

So your participation is -- you're sort of agnostic to who's involved in the completion process?

Yes because our client is the oil company. They are the ones that are trying to maximize recovery from their field. The other service companies are trying to maximize the number of services they can perform for the client, which is not necessarily a positive thing for the client's IRRs.

Steven, we believe in best in class. We've never lost a job that we are aware of because we've not been part of an integrated effort with any other service companies. So we'll just ride our best in class in what we do to get that work.

Great, that’s helpful. And then just one final quick one, when you look at incremental in the second quarter and this goes back to a prior question, but does reservoir description drag incrementals in short term? i.e., should product enhancement kind of already be accelerating towards that, towards those higher levels?

Yes, that’s what we have seen towards the end of 2016 and again in the first quarter. Those incremental are being driven right now by production enhancement, but our view is as the year 2017 progresses reservoir description will begin participating too, which is what giving us comfort on driving companywide incremental from 30% in Q1 to an expected 45% in Q2.

Okay, thank you

Okay, Steven, so in summary Core's operations continue to position the company for an uptick in activity levels in the second quarter of 2017 and beyond. However, we have never been better positioned and technologically adept to help our clients maintain and expand their existing production base. We remain uniquely focused and are the most technologically advanced reservoir optimization company in the oil field service 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 excess capital being returned to our shareholders via dividends and opportunistic share purchases. So in closing our 87th quarterly earnings release, we wish to thank all of our shareholders and analyst to follow Core and as already noted Monty Davis, the Executive Management of Core and our Board of Directors, give special thanks to our worldwide employees that have made these results possible. We are proud to be associated with their continued achievements. 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 your lines, have a great day.