Core Laboratories Inc (CLB) 2017 Q2 法說會逐字稿

Good morning, and welcome to the Core Laboratories Second 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 and CEO of Core Laboratories. Please go ahead.

Thanks, Kate. Good morning in North America, good afternoon in Europe and good evening in Asia Pacific. We would like to welcome all of our shareholders, analysts and most importantly, our employees to Core Laboratories' Second Quarter 2017 Earnings Conference Call. This is our 88th quarterly earnings release.

This morning, I'm joined by Dick Bergmark, Core's 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 IR.

The call will be divided into 5 segments: Gwen will start by making remarks regarding forward-looking statements. We will then review the current macro environment, updating industry trends in EOR in unconventional reservoirs, the use of [finer] proppants and the limits of lateral [lengths] and horizontals. We will then review Core's 3 financial tenets, which the company employs to build long-term shareholder value. Chris will then follow with a detailed financial overview and additional comments regarding building shareholder value, followed by Dick Bergmark commenting on Core's third quarter 2017 outlook and a general industry outlook as it pertains to Core's prospects. Then Monty will go over Core's 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 in major projects worldwide. Then we will open the phones to a Q&A session.

I'll turn it back to Gwen for remarks regarding forward-looking statements. Gwen?

Before we start the conference this morning, I'll mention that some of the statements that we make during this call may include projections, estimates and other forward-looking information. This would include any discussion of the company's business outlook. These types of forward-looking statements are subject to a number of risks and uncertainties relating to the oil and gas industry, business conditions, international market, international political climate and other factors including those discussed in our 34 Act filings that may affect our outcome. Should one or more of these risks or uncertainties materialize or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. For a more detailed discussion of some of the foregoing risks and uncertainties, see Item 1A Risk Factors in our Annual Report on Form 10-K up for the fiscal year ended December 31, 2016, as well as other reports and registration statements filed by us with the SEC and the ASM.

Our comments include non-GAAP financial measures, reconciliation to the most directly comparable financial measures included in the press release announcing our second quarter results. Those non-GAAP measures can also be found on our website.

With that said, I'll pass the discussion back to Dave.

Thanks, Gwen. Core has observed the emergence of 3 major industry trends that will shape tomorrow's oilfield and Core's clients activities. Core is utilizing these trends to focus the company's technology to enhance the growth and profitability of Core and its clients. The first major trend is the increasing client interest in enhanced oil recovery from unconventional reservoirs. Early work performed by Core has indicated possible recoveries increasing from an average of about 9% in shale reservoirs to 13% to 15% by utilizing engineered gas absorption techniques, gas recycling and the laws of physics and thermodynamics. Ongoing dynamic flow tests look promising, and Core has developed gaseous [tracers] that would be used to determine the positioning and effectiveness of this engineered gases in the EOR process. We are now investigating the role of dense and complex completion and stimulation programs and the role in the EOR process. Increased recovery rates of these magnitudes can increase the clients' return on their invested capital by 40% to 50%, boosting their free cash flow and shareholder value. The second major trend is the interest in using finer proppants or micro proppants in the initial procedures and a hydraulic fracture program. Core, via our industry-wide profit consortia with a 30-plus year history and consisting of over 40 companies, is boosting its evaluation of 100-, 200- and 400- non-API mesh sand. These micro proppants are thought to open secondary and tertiary fracture patterns, significantly increasing the Stimulated Reservoir Volume, therefore increasing initial flow rates as well as the estimated ultimate recovery from the wellbore. Micro proppants pumped during the placement of the frac pad could potentially boost these curves by tens of thousands of barrels with very little added cost. Pumping 70- and 40-mesh sand late in the frac process also appears critical for success.

The third major trend is that lateral lengths may have reached their maximum, owing to frictional forces of pumping the frac fluid and profit. However, Core is currently testing reduction -- friction reduction additives to once again allow for longer laterals. Pad drilling and completion programs rule the day and are causing the recent disconnect in wells drilled and wells completed in the last 2 quarters. Wells drilled and completions will start to mirror each other in the second half of 2017.

Now to review the 3 financial tenets by which Core used to build shareholder value over our 22-year history of being a publicly-traded company. Incidentally, Core, as a company, is celebrating our 81st year of technological innovation. During the first quarter, Core generated over $16 million in free cash flow, and once again produced the oilfield industry-leading return on invested capital for the 31st consecutive quarter. Also, Core returned over $30 million back to our shareholders via our quarterly dividend and share repurchases. Core will continue to return all excess capital back to its shareholders in future quarters via the quarterly dividends and additional share repurchases.

I'll now turn the call back over to Chris, and he's going to give a detailed financial overview. Chris?

Thanks, David. Now looking at the income statement. Revenues were $163.9 million in the second quarter, up 4% sequentially, which is led by the growth in our Production Enhancement segment. Of this revenue, service revenue was $117.2 million for the quarter, down sequentially $3.7 million or 3%. Product sales were $46.7 million for the quarter, up $9.8 million or 27% sequentially, which is primarily related to the improved activity levels in North America.

Moving on to cost of services, which was 69% of service revenue for the quarter and consistent with last quarter. Cost of sales in the second quarter was 79% of product sales revenue, a nice improvement from the 84% last quarter and 89% in the same quarter last year, as our operating leverage and the adsorption of our fixed cost improves with higher levels of revenue.

G&A for the quarter was $11.1 million, down from $12.8 million last quarter, primarily due to employee compensation. We expect G&A to be around $46 million to $48 million for the full year. Depreciation and amortization for the quarter was $6.3 million, which is comparable to the last several quarters. For 2017, depreciation expense is expected to be approximately $26 million to $27 million. The guidance we gave on our last call and past calls specifically excluded the impact of any FX gains or losses and assumed an effective tax rate of 15% for the second quarter. So accordingly, our discussion today excludes any foreign exchange gain or loss for the current period and prior periods.

To conform to our guidance, EBIT, ex-FX for the quarter, was $29.8 million and continues to represent best-in-class EBIT margins of 18.2%, a sequential increase of 270 basis points. Income tax expense for the quarter was $4 million at an effective tax rate of 15%. However, it will continue to be somewhat sensitive to the geographic mix of earnings between the U.S. and other regions of the world.

Net income, ex-FX for the quarter, was $23 million, up from $18.7 million, [ex-items] last quarter. GAAP net income was $22.7 million for the second quarter. Earnings per diluted share, ex-FX, was $0.52 for the quarter, and GAAP EPS for the second quarter was $0.51.

As we move on to significant aspects of the balance sheet, I'm only going to highlight the items that have materially changed from previously reported balances. Receivables stood at $129 million, up about $7 million from March 31, primarily as a result of increased revenue. Our DSO for the quarter came in at 67 days, up slightly from 65 days last quarter. The inventory at $35.6 million is down over $1.9 million sequentially as inventory turns continue to improve at the same time demand for our products continues to expand. We expect inventory turns to continue showing improvement throughout the remainder of the year.

And now on to the liability side of the balance sheet. Our accounts payable were $41.6 million, up $5 million in the quarter as the business expanded. Our long-term debt ended the quarter at $233.7 million, up from $218.6 million in March 31. Capital expenditures for the quarter were $2.9 million and $9.4 million year-to-date. We expect capital expenditures for the year to be in the $18 million to $20 million range. And we will continue to adhere to our strict capital discipline as we evaluate the capital expenditure opportunities throughout the year.

Looking at cash flow. In the second quarter, cash flow from operating activities was $18.7 million, and after paying our $2.9 million in CapEx, our free cash flow for the quarter was $15.8 million and $39.1 million for the 6 months -- first 6 months of the year.

During the quarter, we repurchased 55,000 shares under our share repurchase program at an average price of $103.48 per share. Since the inception of the company share repurchase program in 2002, Core has lowered its outstanding share count by over 39 million shares, repurchasing shares at an average of approximately $41.30 per share. Also, over this period, Core has returned over $2.4 billion to its shareholders via share count reductions and dividend distributions. Our free cash flow conversion ratio, which is free cash flow divided by net income, continues to be one of the highest in the industry at almost 97% for 2017. We believe this is an important metric for shareholders when comparing companies' financial results, particularly for those shareholders who utilize discounted cash flow models to assess valuations.

I will now turn it over to Dick for an update on our guidance and outlook.

Thank you, Chris. Let's talk about guidance for the upcoming quarter. Internationally, several FIDs have been recently announced by oil and gas companies. However, activities for Core Lab relating to those FIDs are not expected to materially increase in 2017, as the operators are currently developing their project plans and should begin to implement those plans early in 2018. Further, the international rig count does remain flat due to limited capital projects underway by international operators. That being said, OpEx is continuing to be spent by operators to maximize recovery from their existing producing fields. According to Baker Hughes, our land-based rig count in the U.S. increased 15% during the second quarter and 44% during the first half of the year. We believe this increase is in response to the improved pricing of crude oil in the first quarter when the average oil price per barrel was about $54. However, in the second quarter, crude oil prices were more volatile as prices trended down as the quarter progressed, and ultimately, ended the quarter around $46. We believe that if the crude oil price continues at the current level for a protracted period of time, then the U.S. land-based rig count will begin to flatten in the second half of 2017. If crude persists below $50 per barrel, U.S. land-based rig count may actually contract in the second half, as we do not believe operators can continue to outspend free cash flow, with debt and equity markets likely closed to them for additional capital. This observation is not withstanding the continual decline in the global crude oil inventories and the impact this will have once the decline falls below the 5-year average inventory level.

Further in the U.S., we are experiencing the impact of the prevailing market and transitory industry issues of U.S. labor and completion equipment shortages, which is expected to continue through year-end. The increasing number of DUCs, as reported by the EIA throughout 2017, is evidence that completions have not been able to keep up with the pace of drilling. The shortage of equipment is an issue for operators getting crews to complete wells, which is why DUCs went up. Many E&P analysts wrote about this as the issue became more problematic as the quarter went on. The pressure pumpers spoke about this in their own vernacular on the recent calls. The reason they are bringing equipment out of cold STACK is because they are short spreads. They wouldn't be spending money to bring them out of storages if they were not short equipment, and because they and other private pressure pumpers were short equipment and cruise, DUCs in Q2 grew rather than shrank. Remember on our last call, the discussion was about how quickly DUCs could be drawn down. Our revenue guidance assumed DUCs would go down, not up, and it was this shortage of equipment that all the pressure pumpers are now trying to rectify that caused completions to be put off, which caused DUCs to build and our revenue to be light. That's the reason for the shortfall as well as the increased use of diagnostics on multi-well pads.

A job for us is not complete until the wells have all been diagnosed, which can be over a several month period. This compares to single-well diagnostics in the past, where revenue is earned 1 well at a time. Our U.S. revenue is correlated with completion and stimulation events in large-scale reservoir rock and reservoir fluid characterization studies, rather than with immediate increases in rig count. Wells need to be drilled and subsequently completed, stimulated and cored or have reservoir fluid samples collected before we can realize a revenue event. Taking these transitory market conditions into consideration, we project third quarter 2017 revenue of approximately $165.5 million and $170 million.

As discussed in prior quarterly earnings releases, we expect to generate incremental operating income margins of up to approximately 60% early in the activity recovery phase, followed by historical incremental operating margins of approximately 35% to 45% well into the recovery phase. We project that our operating income in the third quarter may range between $30.9 million and $33.5 million, yielding operating margins of approximately 19%. And assuming a 15% effective tax rate EPS for the third quarter is expected to range between $0.54 and $0.56. Third quarter 2017 free cash flow is expected to exceed net income, and we anticipate continuing our share repurchase program during the quarter.

Now let's turn the call to Monty for an operational review.

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

Q2 revenues of $164 million increased 4% over Q1, and generated $29.8 million in operating income, excluding FX charges. Operating margins of 18.2% were up over 250 basis points from Q1 2017. Reservoir Description operations, which are mainly focused on the international areas, generated revenue of $104 million, and operating margins improved to 18.2%, a 160 basis point improvement. Most of this revenue was generated from OpEx budgets.

In the second quarter, Core continued on a large, multi-well prospect offshore South America. Fresh cores were received in Q2 to further evaluate the reservoir potential of a thick section of laminated sandstone. Core's involvement so far includes proprietary well frac core handling and stabilization techniques; dual-energy CT scanning of the cores and an extensive geological evaluation of the reservoir rocks, mineralogical, diagenetic and core system properties. Core's proprietary high-resolution, dual-energy CT deliverables provide the client with a rapid evaluation of lithology, porosity, bedding architecture, rock strength, formation, heterogeneity and net pay. In addition, it gave critical key guidance in -- on samples selection for the traditional laboratory measurements that will follow. The CT-derived information was provided to Core's clients before the rocks were removed from the inner core barrel liner. This offered the client a substantial head start on their analytical program, and greatly accelerated their understanding of the cord stratigraphic interval.

In addition, routine rock property analysis are underway and continuing to determine porosity, permeability and fluid saturations. As the client evaluates the results of this fundamental work, the project will move into advanced rock properties testing over the next several quarters. Combine the routine and advanced rock property test will be used as inputs for log calibration and for determining hydrocarbon volumetrics.

Over the past several quarters, Core has discussed reservoir condition rock and fluid testing programs that are being performed in the laboratory to evaluate the effectiveness of engineered gas cycling. These tests were conducted as a means of evaluating an enhanced oil recovery in unconventional reservoirs. Core has seen growing demand for these services over that time.

Pursuant to that, in the second quarter, Core initiated a consortium program in which member companies will collectively share in the results of laboratory tests in support of their Eagle Ford, EOR efforts. These tests will be performed at reservoir temperature and pressure on core and hydrocarbon samples contributed by the consortium member companies. Given the positive reception to both proprietary projects and this initial unconventional EOR consortium study in the Eagle Ford, Core sees opportunities for additional unconventional EOR consortia emerging in the Western hemisphere over the next several quarters. Core sees this technology gaining an acceptance, a joint task force between Reservoir Description and Production Enhancement operations was constructed to bridge laboratory and field scale test. As Core's clients look to upscale laboratory validated, gas cycling methods to field-level projects, Core has been engaged to provide diagnostic services as a way to, among other objectives, determine if the injected gases are being contained within target stratigraphic horizons.

In the second quarter, Core performed -- performed diagnostic services on several EOR field projects, and [once] multiple oil and gas phase traces were deployed within the injection gas while produced hydrocarbons in adjacent wellbores and stratigraphic horizons were tested for the presence of these traces. From this diagnostic tester -- tracer testing, our clients are gaining insight into the reservoir volume being contacted by the engineered injection gas as well as breakthrough times and inter-well communication paths. Understanding these parameters is essential to optimizing the engineered gas injection cycling programs as they will increase the adsorption efficiency on the target formation, and ultimately, oil recovery factors.

Core also initiated a joint-industry project to examine the potential of the Austin Chalk formation as an unconventional reservoir. The Austin Chalk has long been a conventional target for oil and gas explorations. But recently, unconventional drilling and completion techniques have been applied with great success. There is a challenge in applying these techniques to this formation as it is not a shale reservoir like most of the other unconventional [place] in North America. Evaluating the Chalk requires more focus on carbonate geology and the incurrence of natural fracture systems, which enhance the productivity of this reservoir. Core has the experience and the expertise to evaluate the Chalk to help consortium members better locate and orient their wells, and determine the best -- best method to complete them to maximize their return on investment.

Production Enhancement operations, more focused on North America activities, grew revenue 13% over Q1, and operating margins improved 450 basis points to 18.1%. Operators continue to adopt Core Laboratories' HERO PerFRAC perforating technology as completions in the long horizontals increased in a stage count and cluster intensity throughout North America shale place.

In Q2, demand for HERO PerFRAC shape charges doubled that of Q1, which had exceeded the total used in the prior year. HERO PerFRAC charges produced consistent entry-hole size, regardless of gun position, to allow fracture initiation to occur at the base of the borehole. They are specifically designed to improve the efficiency of fracturing operations in today's unconventional reservoirs by optimizing hydraulic horsepower and proppant pumping rates.

During the second quarter, a Permian operator visited Core Laboratories' manufacturing facility in Godley, Texas, to test the HERO PerFRAC technology in predetermined test parameters, closely replicating typical field conditions and downhole environment. All test results confirmed HERO PerFRAC performance with regard to consistent hole size, resulting in a standard deviation of just 2.2% compared to an industry norm of greater than 15% with conventional perforating technology. Based on seeing these results, the operator has decided to move forward to field testing with HERO PerFRAC charges for perforating operations.

Another Permian Base -- Permian Basin operator stated that they have been testing various diverter technologies, and since switching to the Owen Oil Tools' HERO PerFRAC charge, "We have seen a more consistent, calculated number of holes open after step-down test before introducing the diverter. It appears that the uncertainty around hole size has been reduced by using the HERO PerFRAC equal hole-size charge."

Additionally, during Q2, a study of best completion practices using Core's diagnostic technologies and expertise to optimize key parameters, such as stage containment, cluster density, frac fluid cleanup and diversion techniques was conducted by a mid-continent client. The study involved a significant number of wells across multiple basin areas. Strategies were adjusted based on the diagnostic learnings over a one-year period. Optimization yielded consistent stage containment of the frac treatments, better frac fluid cleanup and effective cluster stimulation at high-cluster density through effective diversion methodology. The operator observed dramatic production improvements in early flow data, and a longer-term data indicates an improvement in the decline [per month]. The client estimated an increase in revenue at $15 million per well, with many more wells planned for further development. Diagnostics will continue to be used to verify completion of estimates, and identify other opportunities to cost-effectively recover hydrocarbons.

Kate, we will now open the call for questions.

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

Dave, your comments about lateral lengths somewhat, I guess, hitting their peak at this point was very interesting to me. Could you perhaps expand a bit on that? And the science behind that is suggesting that perhaps we cannot drill in further lateral lengths, and there's going to have to be some, maybe, reduction in addition to that probably cluster spacing perhaps closer to the wellbore?

Yes, James. Right now, the average lateral length is about 10,000 feet. That expanded from -- a number of years ago, from an average of 7,000, 8,000 feet. The problem is the frictional forces in pumping the proppant and fluids at -- out of about 10,000 feet, you don't get enough effective pressure to actually do a good job in fracturing the reservoir. We're looking at friction reducers to enable longer laterals to be drilled, because we are still in the camp of longer laterals, more proppant, more stages, closer clusters to increase the size or the amount of the Stimulated Reservoir Volume. Because that is a critical factor, not only in initial recovery efforts, but in what we see as the next coming wave of EOR in unconventional reservoirs. The amount of proppant to be pumped probably will increase, but it will increase in its complexity as well, where we can see 400-, 200-, 100-, 70- and then 30-mesh sand being used in some of the ultra-complex completions of the future. We're not seeing that as of yet because our proppant consortia is still looking at the economic effects of pumping 400- and 200-mesh sand. Some of the earlier SPE papers do suggest that you do open up tertiary and secondary fracture networks using this fine proppant. So all of it is actually incredibly related in looking at trying to increase the recovery factors from this well. So right now, we probably, with the current technology, are going to be limited to, on average, a length of about 10,000-foot on the lateral.

Okay, that's very helpful. Very interesting, Dave. On the EOR point, maybe, more for Monty. The gas injection and I guess, sometimes, reinjection part, how widespread is that testing today as you guys see that? I know it's still early days, but are you seeing better adoption from more and more customers to drive that enhanced recovery rate?

We're seeing a lot more interest in performing the laboratory testing to verify on their rock and reservoir that this works and what's the best gas and what's the number of times you can repeat this gas -- engineered gas injection because it's a process, over time, that you can repeat and recover more. That's a diminishing return, but if you can repeat this a number of times, you're getting a lot more oil produced. So we're seeing a big increase there. As I mentioned, we're working our Reservoir Description and Production Enhancement have formed groups -- have performed -- have formed teams. We're working with clients in the field that are taking this to the field. That's early days. They are taking it to the field in certain areas. We mentioned the Eagle Ford as one that's being worked on right now, and they're seeing the results that we would expect.

I also mentioned that we're looking into other areas. We have interest from clients to expand into other areas, where we will be forming up some more consortium projects with a number of clients coming together, working on methodologies and sharing in results. But we're not at this time willing to give a roadmap to anyone as to where we're going on that. I know there's companies out there that'd love to know. So we are working on those and that would be growing, James. It's a growing segment and it's very successful.

The next question is from Rob MacKenzie of Iberia Capital.

Actually, follow-up on the last question vis-à-vis enhanced oil recovery money. Do you think you need to have the secondary and tertiary fracture matrices created by the finer proppant for this to work? Or is there a large-ish -- large enough applicable market with the existing wells for this technology?

May I actually, Rob, if you look at it, we probably need that tertiary and secondary fracture network to be remained open, because the amount of stimulated reservoir rock was just a primary fracture's system being open is probably -- we're leaving a lot of reservoir rock as unstimulated. So we think that this is going to be a critical factor in making the EOR an unconventional success.

Okay. Thanks, Dave. Question for Dick, in terms of the third quarter guidance, if I may, Dick. In that revenue guidance, what are you assuming for the number of unconventional wells that are completed and/or looking at a different way, how much do you expect to see DUCs continue to build? Because by my math, it seems like you're going to have to have -- continue to have DUCs building at a similar pace in the second quarter to get revenue in the range you're talking about.

Yes, that's right. We are expecting DUCs, unfortunately, to continue to build. It's at a diminishing rate as years progress, because more equipment has come on. It was like up 600 in Q1, 400 in Q2. We would expect it to be up somewhat still in Q3 until these pressure pumpers can get more equipment out of STACK and into the field. And it is certainly good news, we're hearing from some of the larger pressure pumpers that they expect all of their equipment to be out in the field in Q3, Q4 latest. So that's good news. But until that happens, I think DUCs will continue to build.

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

That's correct.

Okay, and then final housekeeping question. What was the tax rate [implicit] in your guidance? I might -- may have missed that if you said it.

15%.

The next question comes from Chase Mulvehill of Wolfe Research.

So on the EOR, I guess a couple of questions around that. Could you talk about the incremental cost associated with basically taking the recovery from 9% to 15%?

Yes, if you look at what is going to be needed at the wellsite, Chase, is you're going to need some compression assets or you're going to take this engineered gas and inject it into the reservoir. And then you are going to need on the production side and it might already be present, you're probably going to need some separator equipment because what we're going to do is inject this gas at pressures into the reservoir and temperatures, and then go ahead and -- in the separator, go ahead and reduce those temperatures and pressures so we get hydrocarbons dropping out of that engineered-gas solution. So if we look at what the incremental adds are, probably somewhere between $1 million and $2 million of additional assets at the wellsite or at the pad site. If you look at that versus an increase in, let's say, a recovery of EOR of 1 million barrels, taking that at 10% recovery rate to [$1.5 million, 500,000 barrels], a recovery rate of 15%, so you get an extra 500,000 barrels for $1 million or $2 million. I think that improves the return on invested capital for our client by a long way. So that's kind of what we're looking at for additional cost.

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

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

Okay. And the address -- if we think about the -- I guess from a dollar amount, then we think about the addressable market for this unconventional EORs for Core Labs. Could you help us kind of bracket the high end and the low end for the addressable market for you guys?

Don't know that yet. Still very early days but as Monty said, we are getting a lot of client interest. We have our technologically-sophisticated clients and they were out in front of this 2 and 3 quarters ago. But now we have a number of other players that are very much interested in increasing their EORs, and along with that, the return on their invested capital.

Chase, the business model is the same as all of our other services, we have a price book, and we have a cost associated with each one of these tests. So for us, even though it's very preliminary or still early days, the service is commercial. Every time we run one of these engineered gas tests to help the operator determine which component of the gas stream works best, we're going to run the test, give them the data and an invoice at that time. So broadly speaking, it could -- each project could range between, say, $50,000 and $400,000. And I think next point is what's still open is how many of those will be running.

Right, right. All right. One last quick one. When we think about the Production Enhancement business for U.S. onshore, have we seen a shift back to the higher-technology products and services yet? Or is it still kind of your customers' focus to own the commoditized product?

No, we're seeing a shift actually away from the commoditized product. This HERO PerFRAC has been the most successful introduction of new technology at Core Laboratories since we introduced the HERO charge a number of years ago. So they're looking at recovery rates and flow rates, and we've got a lot of clients that are opting for the advanced technology as opposed to the commoditized product.

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

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

The next question comes from Gregory Lewis of Crédit Suisse.

Just on the Reservoir Description. In the press release, you talked about the unconventional EOR project in the Eagle Ford. Clearly, that looks like it's up and running. Could you just sort of, kind of walk us through the life cycle of that, in terms of when we should start to see that benefiting the company? And then, as a follow up to that, clearly, it looks there's opportunities to bring that elsewhere in North America, and I guess South America as well. Could you just talk about where those -- where we should be thinking about those new JIPs coming online, also?

Greg, this is Monty. The -- we're definitely, as Dick said, this is a commercial service that we're providing to a number of clients. It's been growing quarter-over-quarter, and admittedly, you start as small and it's growing to something significant. It's producing a significant revenue for us now with the introduction this quarter of a consortium project focused on the Eagle Ford, we'll see that continue to grow in both the laboratory tests and analysis of those tests that we're providing to the clients. The future direction on these consortium projects is into areas that are active shale projects around the U.S. and perhaps in South America. But we're doing proprietary work in some of those now. It's just that we mentioned we're going to be bringing that to people as a consortium proposal in the next coming quarters. So we're already doing proprietary work in a number of those basins.

Okay, but it's maybe something like maybe where we can get an incremental, maybe 1 or 2 a year, has -- is that how we should be thinking about that?

1 or 2 consortiums?

Yes.

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

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

Well, actually, we are still proponents that we need more stages and more perf clusters. When we look at the amount of Unstimulated Reservoir Volume, it's still at an unacceptable rate. Right now, just looking at an average shale reservoir, we should have stages that are no more than 240 feet apart just due to the transmissibility of that reservoir rock in moving long-chain hydrocarbons to the wellbore. There are very few companies that have that kind of density. Among that, if you look at some of the most technologically-sophisticated companies like Pioneer Natural Resources, their average stage length? About 240 feet. So until the industry adopts, that is an average shale of what the number of stages and perf cluster should be, we should see that intensity continue to rise.

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

The next question is from Sean Meakim of JPMorgan.

So maybe a similar question to the one on mix within Production Enhancement, but from a different perspective. So you're talking about -- you've talked in the past about pivoting to a higher-end proprietary systems, not investing anymore in the commodity systems. Would you characterize that as a push from you or pull from your customers or both? And I guess, I'm just trying to get a sense for, as you think about the updated guidance, to what extent is this shift having an impact? It has a leading revenue on the table to competitors in order to focus on the higher-margin business, and the trade-off between top line and high-calorie systems?

Yes, Sean. This is a function of listening to our clients, talking about issues they're having, completing these wellbores and developing a new product that better addresses what was out there. So we will -- and that's at HERO PerFRAC that Monty talked about with consistent hole size. And so we will always try to develop those and deliver those to our clients, rather than some of the commodity products that just cover cost. And maybe during the downturn, that makes sense, you're just trying to absorb your cost structure that is still fixed. But in this environment, there is no reason for us to invest in the ability to make more of those types of products, of those commodity products. We will add capacity, whether it's human capacity or investment dollars to sell more of these higher-tech products and services. And you're seeing the result of those decisions in our ROIC this quarter, and in the margins, particularly in Production Enhancement at 18%. So the other ones who make commodity charges, I think they're reporting margins at around 0. We don't think we're leaving valuable revenue behind.

No, that's right. And I guess that's -- but my point, I'm trying to get a better sense of is the impact on top line, because that's where, I think, we have the biggest discrepancy with where we thought the numbers could go, and so I'm just thinking about if we think that the HERO PerFRAC and those types of higher-quality systems are taking market share, then perhaps you could be growing faster than the overall market versus if it's roughly the commodity systems are doing and how that can influence what we think about this business on a top line basis relative to the overall systems' market?

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

Got it. Okay. And then just one more on Reservoir Description. Just trying to get a sense for, I guess, thinking about some of the -- I know FID opportunities internationally are not really helpful to material through the quarter, but as we look out into '18, how do we think about trying to size the impact of those types of opportunities as they start to make their way through the P&L next year?

We've said in the past that on these projects where they could take significant amount of core, say, 1,000 feet of core that we could generate $2 million, $3 million, $4 million, $5 million in revenue from each one. And so as these FIDs actually turn into activity for us, I think that's how you can begin to put your arms around the size of the opportunity for us.

Yes. If you look at Reservoir Deception right now, essentially, that represents the OpEx budgets of all of our clients and performance or production maintenance programs around the world. There's very little impact on any of the FIDs that we have been announced today. There's a little bit of revenue in there, but not much. So essentially, when you look at Reservoir Description, think of that as about $100-million business, base line on OpEx. When you start to add FIDs in there, you start to add, what Dick talked about, $2 million, $3 million, $4 million, $5 million of revenue per project or core and [fluid set] generating incremental margins in the 60-plus percent range. So you'll start to see those enter the scene probably in the first part of 2018.

And I guess, what's the timeframe [or what year] you are able to recognize those revenues over the course of a project?

Many of them will be over several years, certainly in a large-scale field development. And so you look at '18, '19 and '20. And certainly, these FIDs that have been announced, especially on major field developments like Exxon, Liza. Now that would be over a multi-year scope.

Because they will be drilling wells over multiyears. So just to be clear, if they gave us a core in '18, we'd be able to recognize the revenue relating to that one at that time. And then as they continue to appraise and evaluate and do more science over the years, we'll be able to recognize the revenue for that work at that time. So I just don't want to leave the impression that we can't recognize revenue until that entire project is complete.

Was it 2 to 5 will be per core so there will be multiple cores on that project?

Correct. Or fluids.

The next question comes from Blake Hutchinson of Howard Weil.

First question, Dick. I want to hone in on a comment you made, I guess regarding the nature of service-based Production Enhancement business and the fact that you are going from the single-well pump to multi-well pad. And it sounds like, as we look at kind of completion activity versus your service-related revenues in that segment, you have a bit of an invoicing mismatch, which is making it more difficult to provide guidance in terms of when you might actually close out a job and it results in revenue, and maybe you can just chat a little bit about that and give us a little more color on that. And I guess, would that lead us to believe as you provide a Q3 outlook that I guess the outlook could brighten if you close out certain projects more rapidly?

Okay, let's talk from the first question. Historically, the diagnostics were done on a well-by-well basis, where the operators trying to understand how well the completion event in that particular well occurred. Are all of my stages flowing hydrocarbons as I thought? Are there issues with particular stages and like we've been able to conduct those tests and run out analysis and diagnostics invoiced the client as we gave them the data for that one wellbore. So what we're seeing with pad is the complexity of the pad-drilling environment, the questions that the operator have are more complex, if not just what's a horizontal spacing among these wellbores, it's a vertical spacing as well. And so we're doing diagnostics now more on a per-pad basis with multiple wells. So the evaluation is not really complete until the entire analysis of that pad is done. And that's what we're talking about on the revenue recognition, really, the project's not over until we've evaluated all of those different wells and the interplay among the wells. So you're right, it's not a revenue recognition problem or issue. It's just the way you recognize it. We did see the impact of that in the quarter as a result of more and more pad drilling being done and the complexity of these wells being evaluated. So we did see that. We would expect, though, that over time, that begins to become the consistent way of recognizing revenue and it will reduce the lumpiness. If we can get DUCs being either frozen at the current level or DUCs being removed from inventory, those are going to be a good thing for Core Lab. Those are additional revenue opportunities for us. Go ahead, Blake.

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

Yes, the issue is it's collaborative with the client. They're looking at the data as we create the data and we're evaluating what the data means and what the actions of the operator could be, so the timing of the completion of the project is a little more difficult to ascertain because you're not certain when that project is actually going to be completed. So that did cause a little bit of variability in our views going into the quarter versus what actually occurred by the end of the quarter.

Okay. And then, David, I just wanted to -- because there is some commentary in the release, it mainly looks like it pertains to U.S. sensitivity in the business around the oil-price faction over the second quarter, but is it your sense from your Reservoir Description, client base, and specifically, those entertaining major FIDs that via the push to the right from potentially the second half to early '18, was it all in response to oil-price decks? Or just the general vagaries of large project timing?

I think, Blake, probably both. Certainly, we would have thought we would have had some projects underway by Q4. A little more planning going into those with $45 WTI. And so some of that would have gotten pushed to the right, certainly. And looking at additional FIDs being announced, we don't think those are going to be -- those are going to be delayed at the -- at this time owing to the fact that we are, on a worldwide basis, continuing to decline inventories. We think by the fourth quarter, inventories will be below the 5-year average. And every time we've gone below the 5-year average, we've had a nice increase in crude oil prices. Now I think our clients are looking at that as well.

The next question comes from Marc Bianchi of Cowen.

I guess first on Reservoir Description, I wanted to ask as it relates to second quarter. Revenue here was down a little bit from the first. Typically, we see a seasonal balance here. Is there anything to call out? Or is it just kind of the business has evolved from where it was in prior periods and we won't see those kind of seasonality changes going forward?

Yes, Marc, I think it was down less than 1%. And that was just looking at just the business mix. Operating budgets essentially were flat from Q1 to Q2. So I wouldn't read into that at all. You can see that the margins [gotten] back above 18%. So again, we described this business as being about, from an OpEx standpoint, about $100 million a quarter, with operating margins around 18%. As we start to put some FID revenue into that, you get a liftoff of that level. So not much to read into Q1 to Q2 on Reservoir Description.

Okay. And then I guess just logically following from there as we look to third quarter and the guidance that you provided. If I assume that all of the growth is in production enhancement and Reservoir Description is flattish, is that sort of a good starting point? Or are there anything you'd like to add to that?

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

The next question comes from John Daniel of Simmons & Company.

Dave, you guys were early to highlight the growing benefits of more sand per well, but I'm sure you know yesterday, Halliburton noted that it witnessed the reduction in sand per well during Q2. Do you believe there is a trend by customers to reduce sand concentrations and if so, is that been driven by science or short-term strategies to reduce well cost?

Yes, we are still proponents of longer laterals, more sand, closer clusters and more stages. I think the -- whether the amount of sand that's pumped or not will decrease, I think the complexity of the combination of sand that will be pumped will continue to increase. So from just a pure-scientific standpoint, the greater amounts of proppant that can be pumped, and the amount of reservoir volume to be stimulated, that's always a good thing for increasing initial production and EORs. So if you look at it by a basin-by-basin study, I think over the last quarter, we still saw an increasing amount of sand being pumped basin by basin. I can't comment on well by well, as completion techniques will change owing to the reservoir rock and what is being completed.

And when you say increase in sand by basin, you're referring to it not in terms of total sand volumes but on a per-well basis. Is that fair?

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

Okay, fair enough. Dick, your Q3 revenue guidance calls for -- call it a 1% to 4% sequential improvement. Can you give us just a little bit of color on the split between the expected changes and the 2 segments?

Yes, Reservoir Description is going to be flat. That's our expectation, so the growth is going to come from a Production Enhancement.

And then, Dave, last one for you. I noticed in your guidance, you appropriately called out the reality that rig activity could decline later this year. I am just curious, in your discussions with customers, how likely is a decline? And would you care to offer your view on the rig count, call it by year-end, should we stay in the $45, $50 environment?

Yes, I think we stay in a $45 to $50 environment, you're going to have a number of the private operators probably lay down some rigs, so we wouldn't be surprised if we saw a contraction in the rig count by maybe 50 to 100 rigs by the end of the year. That's kind of what our guidance is based on, where we tone down what the expectations for revenue was for Q3 and it's based on a flat to possibly down rig counts. They can't continue to outspend their free cash flow because in our view, the equity markets and the debt markets will be much tighter this time around than maybe 1 year or 1.5 year ago. All right, Kate, we'll take one more question.

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

I just -- I'll keep it relatively short. I always like to get your take on this when -- any updated thoughts on kind of the stickiness of non-U. S., non-OPEC production? And how you see that just kind of flushing out from macro perspective over the next several quarters?

Yes, Stephen, good question. Outside of Brazil, we have a hard time adding any additional production outside of the U.S. and OPEC. What other country is going to increase production that is non-U. S., non-OPEC? Outside of Brazil, we can't get you that. So we think we see an expanding decline curve rate for non-OPEC, non-U. S., over the next couple of years and in our books, it will have a dramatic effect on where crude oil prices go.

Okay. Now that's helpful. And just as a -- just a quick follow up to that, I think I know the answer to this, but when OPEC ratchets back production or controls production a bit, any impact on your work in those countries when that happens? I don't think so, but just want to get your views.

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

Yes, Stephen, those are -- these tend to be very long-term projects. And so [they'll not] have any effect on the work that we're doing.

Okay, Stephen, Kate, so we're going to wrap it up in summary. Core's operations continue to be positioned for activity levels in the third quarter of 2017, and we know that significant challenges await. However, we've never been better operationally or technologically positioned to help our clients to maintain and expand their existing production base. We remain uniquely focused and are the most technologically-advanced, [reservoir-optimization] company in the oil-field services sector. This positions Core well for the challenges ahead.

The company remains committed to industry-leading levels of free cash generation and returns on invested capital, with all excess capital we return to our shareholders via dividends and future opportunistic share repurchases. So in closing, our 88th quarterly earnings release, we like to thank all of our shareholders and the analysts that follow Core, and as already noted by Monty, the Executive Management and Board of Core Laboratories gives a special thanks to our worldwide employees that have made these results possible. We are proud to be associated with their continuing achievements.

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

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