Core Laboratories Inc (CLB) 2017 Q1 法說會逐字稿

Good day, and welcome to the Core Laboratories First Quarter 2017 Earnings Conference Call. (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. 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, who is Executive Vice President and CFO; Core's COO, Monty Davis, who will 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 5 segments. Gwen will start by making remarks regarding forward-looking statements then we'll come back and review the current macro environment, updating recent industry trends in EOR in tight-oil reservoirs, the use of finer province, the limits of lateral length and then comments on Core's continued use of Big Data, neural networks, machine learning and data analytics to increase efficiencies and reduce cost for our clients in evaluating their reservoirs. Then, we will review Core's 3 financial tenants, 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 coming on -- commenting on Core's second quarter 2017 outlook and a general industry outlook as it pertains to Core's prospects. And Monty Davis will go over Core's 3 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 will open the phones up for a Q&A session.

I'll 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 numbers 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 of 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 risk 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 ASM.

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 financial 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 3 financial tenants.

Core has absorbed -- has observed the emergence of 4 major industry trends that will shape tomorrow's oilfield and Core Lab's client activities. 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 trend is the increasing client interest in enhanced 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 physics and thermodynamics. Ongoing laboratory dynamic flow test look promising. We are now investigating the role of dense and complex completion and stimulation programs and the role in EOR success. Increased recovery rates of these magnitudes can increase the clients return on investment 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 consortium 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 micro-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. Micro proppants pumped during the placement of the frac pad could potentially boost tight 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 sand -- trend is the continued increase in proppant loading and the number of stages per well. At the end of 2016, stage count had grown 34% for the year to an average of 40 stages per well, with an average separation of approximately 200 feet. Proppant loading per lateral foot increased approximately 50% to 1,700 pounds during the year, with an average well receiving now 14 million pounds of sand. However, the growth in lateral length has 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 2 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 clients' efficiency and reduce cost in evaluating their reservoirs. For example, Core, a decades user of Big Data, will analyze data set from the company's deepwater Gulf of Mexico to joint-industry project to machine learn computers and scanners to describe thousands of feet of Core in project and then use data analytics to characterize and identify the key properties of superior deepwater reservoirs. This can be applied not only in the Gulf of Mexico but we believe it can be applied to worldwide deepwater faces.

Now to review the 3 financial tenants 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 investment capital for the 30th consecutive quarter, as activity levels continue to increase in North America and with more stable international markets with deepwater 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 would now turn it back over to Chris and he'll give a more detailed financial review. Chris?

Thanks, David. Before we review the income statement and balance sheet, I would like to highlight that 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 revenues are now combined and reported with our 2 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 has 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 $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. Our 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 margins amongst oilfield service companies. Cost of sales in the first quarter was 84% of service revenue, also a nice improvement from the 87.5% last quarter as our operating leverage in the absorption of our fixed cost improves with higher revenue -- 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 those operations. For 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 assumed 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 the $1.1 million of severance and other charges incurred during the quarter, as part of streamlining the 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 the 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 onto the balance sheet, I'm only going to highlight the items that materially changed from previously reported balances. Receivables stood at $121.8 million, and as a result of revenue, continued 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 changes are related to about 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 to -- from $33.7 million, so an 8% increase sequentially for the quarter. Our long-term debt end of the quarter at 25 -- $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 in support of the strengthening activities and will 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 2017. We believe this is an important metric for shareholders when comparing company's 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 at 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. 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 revenue, 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 undersupplied. This is indicated by recent International Energy Agency data showing that worldwide crude oil inventory has declined over 6 of the last 7 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 17 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 undersupplied by more than 2 million barrels per day. The continued, undersupply 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 off-shore 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 8 consecutive quarters of decline. And in the U.S. offshore market, new well permits in the Gulf of Mexico increased 13% over a year ago March levels.

We project second quarter 2017 revenue for Core Lab to be 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 our 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 like to turn it over to Monty to give a more detailed 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 as 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 had 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 centers. In the laboratory, Core Lab is uniquely able to deliver the proprietary reservoir condition fluid testing, gas cycling experiments and ultrahigh frequency NMR diagnostic techniques that are required to understand how EOR programs can improve recovery in these old plays. Many large and mid-sized oil and gas operators are working with Core's technical experts to design reservoir-condition laboratory programs to determine how the variables of lithology, pore 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 tests and the gas fluid rock interactions are being evaluated from various basins around the U.S. While deployed in the field -- 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, may -- 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 in the subsequent quarters as our clients accumulate and evaluate the data needed to make final investment decision on these assets.

Reservoir condition laboratory work includes a full range of basic and advanced rock property test, PVT analysis, higher resolution dual MGCT and micro-CT imaging and analysis as well as geo-mechanical testing for wellbore 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 deepwater 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 increasingly deeper water and has targeted not only the Eocene to Paleocene reservoirs, but the lower Myocene as well. The intent of this study is to characterize deepwater reservoirs, evaluate the seal capacity and examine the engineering components of the play to substantially reduce the risks associated with deepwater 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 consortium 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 risks associated with these reviews.

Production Enhancement Q1 revenue of $53 million grew 19% sequentially over Q4 2016, with U.S. land operations 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 address increasing client demand for a consistent hole size throughout the appropriating cluster. Conventional appropriating and a horizontal well results in varying hole sizes, with a larger hole on the lower side and a smaller hole on the high side. Core's HERO PerFRAC provides an equal hole size throughout the cluster. Specific completion designs can be satisfied with equal hole size selections resulting in lower hydraulic pressure for fracturing and providing optimum flow rates for the placement of proppant, which, in turn, 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 PerFRAC technology in the Midland Basin, [ Whitford ], [ Scoop ] and Eagle Ford shales was up 52% sequentially from Q4 to Q1 '17.

In a recent Wolfcamp completion study, Core Laboratories identified an opportunity for operators in the Midland Basin of the Permian to eliminate some frac stages that were not cleaning up effectively post frac and were not contributing hydrocarbon production. Core diagnostic technology showed that part of the lateral had intersect in depleted vaults 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 has a number of operators in the Permian Basin and they are using Core's diagnostics and answer pressing questions regarding well spacing and landing zone effectiveness. These 2 issues, along with diversion evaluation and engineered perforating appear to be hotspots in most areas. Permian Basin activity continues to escalate and 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 the long-term effects 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 2 different landing zones within the upper Wolfcamp interval. Traditionally, most operators have a single landing zone within the center. 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 to each perforation cluster is also a very important question that the West Texas operators are actively addressing. Core is uniquely positioned to capitalize on this surge in diversion activity. Core's 0 wash technology in conjunction with specter scan services provides the only direct measurement for diversion evaluation. It is specifically designed to quantify near well-bore proppant coverage and overall perfect cluster efficiency.

Francesca, we'll now open the call to questions.

(Operator Instructions) The first question comes from James West Evercore ISI.

The question on, it's obviously the North American market because Permian is exploding with activity here on your Production Enhancement business. I know you hear about a lot of your longer lead times or wait times for frac spreads and even [ line ] trucks, stuff like that. How do you see -- or what have you done with your manufacturing of your per pump charges in order to catch up with the increase in demand? And are you guys now running kind of full out 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 -- the capacity at the -- 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 the in your initial comments, if I missed those, but as we think about the global oil markets right now, there's rising fear -- I'm 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 the U.S. then non-am, non-OPEC? And how that will play out in '18, '19 and '20? Are you doing (inaudible) that will be on the slide for several years. I'd love to hear again your view.

All right, 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 at a 1.1 million, 1.2 million. Okay, if you apply the worldwide -- our most recent worldwide the decline curve rate, which is 3.3%, you add in what could be expected to be gained out of U.S. production so maybe this year 3 to 4 -- maybe 500,000 barrels, you apply that worldwide decline curve, with the paucity of legacy projects out there in deepwater, and remember the last couple of years, we benefited, 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, in '19 and '20 in the deepwater Gulf of Mexico. So crude oil markets to right now, we see is undersupplied and only to get tighter.

And that 2 million barrels a day, I believe, as Dick mentioned, does that increases from here, I assume?

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 of years out, certainly, that gap can grow larger.

Got it. So Dick, I know you guys are looking at our work and have your own views but inventories adjusted for demand, you would see that at least drop in below 40 days a year, probably by the end of the year, I would assume.

Yes. We think Doug has done some great work of that -- Doug Tennyson. And our projections have it below 40 days. Actually, a little bit earlier than you guys.

The next question comes from Rob MacKenzie of Iberia Capital.

Monty, I guess a question for you. Help us put the stat you gave us for Hero PerFRAC into context a little bit if you will? I think you said that used PerFRAC about 52% quarter-on-quarter from Q4 to Q1 of '17, how would that look more broadly across the Production Enhancement segment in a perforating versus the diagnostics business there? Which one is going faster among the two?

Well, they're both growing at a pretty fast rate at the moment. We're trying to keep up with it. But the -- really the growth seems to be -- Jack, in the second quarter, we're looking at a little better growth in the perforating, but they're both growing big-time. Land is up -- land, which includes both service and products is up 38% and products being a little less of that.

Yes, 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 completions start to catch up with the number of wells drilled. And we're seeing a disconnect there because wells are being completed and stimulated by the pad. So you do have a delay between drilling the 7 or 8 or 5 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 trend towards more pad or multi-well pads affect the diagnostics business? I would think there could be a positive benefit if you want to make sure the wells aren't matching or even may be are matching depending -- does that affect the diagnostics business for you guys?

Yes, it sure 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 sweet 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 the 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 been talking about that for a little while. Help us frame that -- what do you think Stimulated 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 Stimulated Reservoir Volume was probably in the low 20 percentile range. Now with the use of finer and micro proppants, we think that is expanding rapidly and the reason for that is the use of the 400-, 200- and 100 mesh sand in the pumping the pad stage are 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 service area in the 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 figures and also in the tight curves. You could plot that pretty much right alongside of that. How much further it can go, we just now entered looking at 200- and 400-mesh sand so we'll give you an update over the next couple of quarters for the effectiveness of using those micro proppants.

How -- are we seeing fuel tests right now with 200- and 400-mesh sands? And any kind of early results you can share?

Yes, Rob. You can go -- actually, there are several good SBE papers that are out. If you want those numbers, you can just send an e-mail or call me afterwards and I'll make the -- we'll make those available to you.

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

It's -- at this current level on the revolver, it's not a priority. So on user free cash, it would be dividend first, share repurchases second.

Next question comes from Ole Slorer of Morgan Stanley.

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

Yes, Ole. If you 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 '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's no reason why we shouldn't continue to see a progression in those incrementals driving the underlying margins.

Okay, so the HERO charters are the most profitable product line that you have and a catch-up in frac activity and the drive towards that should, in other words, be that mix change continue to drive that margins higher, yes?

Yes, Yes, I would say completion for us, fracs. Okay. If a completion follows that in stimulation, we would agree with that.

Okay. The second question here, just some broader implications. If the use of this finer proppants becomes a success, what will some of the broader industry implications be that you could think of?

Shouldn't be. Think of this as opening up new fracture faces within the reservoir that weren't open yet. So what we're doing is we're adding additional micro proppants all the way down to 100 non-API mesh, going into the secondary and tertiary fracture, we don't think that makes a Delta for the use of let's say a 70, 40-mesh 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-mesh sand in the early pad, mid-pad 200-mesh, late pad 100-mesh, followed by 70 and then a 40. There are -- some of our clients experimenting with that right now. We are doing dynamic flow tests on that right now. So that will be interesting to see how that evolves. So it might open a new market for the micro proppant and should have not a big effect on the increasing demand for northern white or brown sand of the 70, 40 or somewhere around that mesh for the industry.

In total, what does it do to the use of sand per foot drilled or the proppant loading as you refer to?

Yes, proppant loading will continue to increase. There's 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're doing some work for our clients looking at friction arresters so we can have faster pump rates, higher levels of proppant loading trying to get out to longer laterals. On the lateral side, because of these frictional forces, we're starting to see a limit on how far they can go unless we can overcome these frictional forces. Moreover a Second Avenue eliminating laterals is just a metallurgy on the Core tuning. 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 work you do in the EOR work that you do, from 9% to 15% that sounds pretty impressive. Just hear 1 or 2 companies about working on that today, but maybe it's much broader than what we're thinking. What would the implications be as opportunities set 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 for EOR and tight-oil. We see that continued 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 fractured 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 was a little surprise at some of the names that you listed in your consortium. I suppose I could ask the other companies like Aramco as to what are they trying to get out of this?

Well, if you look at the companies, they're 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 2 to 3 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 proppant 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 their reservoirs.

The next question comes from Kurt Hallead of RBC.

Always very informative, so I appreciate all the color you guys provide. One follow-up on my end. You spent some time earlier on the call talking about some of the offshore dynamics and how you see that evolving. There's been some recent discussion by a major service company about some fields that they've been involved in and seeing accelerating decline rates particularly in the Gulf of Mexico where there might have been historically 5% decline rate, but the oil companies leaning heavily on trying to generate cash flow now, trying to push those reservoirs hard so that decline rates are not potentially approaching 20%. Just trying to calibrate that. What kind of things have you seen on some of the fields that you've 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 older fields, I think you're referring to the depletion rates of the reserves, indeed those are higher because we pretty much maximize what that reserve base is going to be and what the ultimate recovery is 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, it gets back to that James West's earlier question, when you get into the '18, '19 and '20 areas, you're going to have a paucity of projects that are going to be meaningful, coming on full production other than a handful that we mentioned in the past. And we see tighter -- much tighter crude oil markets.

Okay, great. And then, in the press release, you guys mentioned roughly 15% of your total company revenues come from offshore and...

Deepwater.

Sorry, deepwater, not offshore. Okay and then peak was around 20%, something like that? And you mentioned that the deepwater or the -- again, trying to get the semantics right here, okay? So the mark -- the deepwater offshore market bottoming out in the second half of '16 -- or '17, excuse me. So do you -- how long do you think it could -- would take before the deepwater revenues kind of get back to that 20% or prior peak levels? How do you see that evolving?

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

That's relatively short-term.

Yes. You've got -- Kurt, if you look at the number of FIDs that are in-line coming up, all those weigh in to the amount of exposure that we have for our deepwater developments. So we like that trend that we're seeing. And just recently, you have seen BP talk about the sanctioning of Mad Dog 2. We believe that offshore Guyana, those projects are lining up to FID perhaps later this year. So you have a number of major projects that we certainly will be involved and to help fuel that revenue into deepwater.

Next question comes from Sean Meakim of JPMorgan.

Just to follow up a little bit on some of the margin question. And you talked about early cycling and come out as approaching 60, that's kind of where you were in the first quarter. The HERO PerFRAC is clearly helping. And thinking about the changes in diagnostics, how materially accretive are those to the margin? Could help us think about that contribution?

Yes, those are some of them most accretive, Sean, to our incremental. If you think about that service, we're sending engineers out to the field and if it was a single well versus, for example, the trend now to pads, while the incremental cost for us is not that great of doing one single well versus, say, doing 5 or 6 wells, trying to understand the communication among the wells. So in that environment, and that's a trend we're 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 with deepwater, how that kind of impacted the margin this quarter, because it sounds like you're saying that on the one hand, you don't expect deepwater activities to bottom until the second half of the year, but you think you've already gotten there in terms of the margin bottoming. And just curious how we should be think about the different levels between rocks and fluids and land, shallow water and deepwater?

Sean, think about the revenue stream right from deepwater, it's really fluids based around the producing fields in deepwater. And that's what's given such great stability and not just in revenue, but in margins in Reservoir Description through this downturn. So our expectation with these FIDs is we'll begin to see capital projects thrown into the mix. On top of the existing OpEx projects and not projects but just the 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 throw in some projects from these new FIDs that are capital oriented. That's what's really going to drive margin expansion and reservoir description.

The next question comes from Gregory Lewis of Crédit Suisse.

I just was hoping to follow up on Rob's comments sort of trying to -- he was talking about market share gains between the HERO, the plug perc systems and the diagnostics. Are you able to provide any color around -- clearly there's a huge growth demand for these that 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.

Which, 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 the same business model.

Okay, great. And then just one real quick one for me. In the quarterly, that HERO PerFRAC, you guys mentioned that it's your best launch. What metrics are we using to sort of think about that? Like I'm 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.

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 and 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.

Okay, awesome. That's helpful. And then talking about the 200- and 400-mesh sands. Could you talk about if there's any limitations, whether it's basin, whether it's closure stresses or anything like that?

We're early days on that, Chase.

Okay, all right. And when you're looking at these mesh sizes, is this incremental sand pumped? Or are you swapping kind of coarser grain sands for these 200- and 400-mesh sands?

No. These are incremental sand pumps because of this secondary and tertiary fracture cycle that we're opening up. The coarser mesh sand cannot get in there. So this will be incremental sand pump.

Okay. And when you talk about larger casing sizes and we've heard this from a lot of BMPs as well. How should we think about the limits on 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 and stuff like that on rigs.

Correct.

Assuming there's no limitations on service equipment, from science end is there a limitation? Can we go to 12-inch casing, 14-inch casing, 15-inch casing? Or does the sign say that's just too much?

Yes, that's just too much. We're talking about maybe increasing the casing size an inch or 2 or 3. So we're not talking about running that large of a casing load down there.

Okay, all right. And then just -- so if we think about trying to translate all this, you are just thinking about doing from your testing 200- to 400-mesh size, more SRV, how does all this kind of translate into incremental revenues for Core Labs?

Well, it's analytical testing revenue all the way around. We're testing the proppants for a consortia, we're using dynamic flow test for our clients in their own specific proprietary fracs. If we look at the incremental amount of production out of the 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, awesome. I'll turn it back over. And when you talk about SRV and you talk about BL, have you looked at that on the per lateral foot basis and how that's increasing? And how close do you think we are to maximizing SRV on a per lateral foot basis?

We do look at it on a per foot basis. We don't know the answer to the second question.

The next question comes from Marc Bianchi of Cowen.

Just really one for me. As it relates to the buyback, you mentioned you're starting back up here in the second quarter. And traditionally, the formula had been to use the free cash flow after dividends for the buyback. But considering the positive outlook that you've got, V-shaped 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, Francesca, we'll take one more question.

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

Really one thing left that I just want to touch on. When you think about the industry, you see what's going on with sort of Weatherford and Schlumberger JV and Haliburton. How does this impact Core Labs or does it? When you think about especially on the Production Enhancement side?

We don't see impact on Core Lab because they're different services, they're different times at the well site. So like most of these JVs or integrated projects, we're not a participant by choice.

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

Yes, our client is the oil company. They're the ones that are trying to maximize the 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.

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

Okay, that's helpful. And just one final quick one. When you look at incrementals in the second quarter and this goes back to a prior question. But does Reservoir Description drag incrementals in the short term i.e. should Production Enhancement kind of already be accelerating towards that -- towards those higher levels?

Yes, that's what we've seen towards the end of 2016 and again in the first quarter. Those incrementals 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's giving us comfort on driving company-wide incremental's from 30% in Q1 to an expected 45% in Q2.

Okay, Stephen. 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 oilfield 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 the dividends and opportunistic share purchases.

So in closing, our 87th quarterly earnings release, we wish to thank all of our shareholders and analysts that follow Core, and as already noted by 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 continuing achievement.

So thanks for spending your morning with us, and we look forward to our next update. Goodbye for now.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.