Core Laboratories Inc (CLB) 2017 Q3 法說會逐字稿

Good morning, and welcome to the Core Laboratories Quarter 3 2017 Earnings Conference Call.

(Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Dave Demshur, Chairman, President and CEO. Please go ahead.

Thanks, Rachel. I'd like to say good morning in North America, good afternoon in Europe and good evening in Asia Pacific.

We'd like to welcome all of our shareholders, analysts and most importantly, our employees to Core Laboratories' Third Quarter 2017 Earnings Conference Call. This is our 89th quarterly earnings release.

This morning, I am 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. Then we'll come back and review the current macro environment, updating industry trends that should be beneficial to Core. 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 fourth quarter 2017 outlook and a general industry outlook as it pertains to Core's prospects. Then Monty will go over Core's 2 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'll open the phones for Q&A session.

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

Before we start the conference call this morning, I'll mention that some of the statements 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. May 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 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 third 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. Let's do a little look at industry trends we're seeing. Core has witnessed and is encouraged by the increasing focus of its major clients regarding capital management, return on invested capital, free cash flow and the return of capital backs to the shareholders as opposed to just growing production at any cost and destroying capital.

The oil companies adopting these metrics tend to be even more technologically sophisticated operators and form the foundation of Core's worldwide client base.

Core will benefit from the shift in focus from [view of] production growth, to employing higher technology solutions, such as EOR methods and unconventional reservoirs or Core's exclusive HERO PerFRAC energetic systems.

The uptick in demand for these technologies is considered in the company's guidance for continued increase in our already industry-leading operating margin and the continued expansion of our incremental margins.

Clients will pay for these technologies that boost their return on invested capital and free cash flow as opposed to commoditized services such as a wireline, seismic and pressure pumping.

In addition, Core Laboratories will remain a technologically driven oilfield service company that will continue to grow and expand our service and product offering. We have no plans to start competing with our clients for acreage position and production streams.

Another trend favorable to Core is the increased demand for phase behavior studies of reservoir fluids in unconventional reservoirs.

Pressure, volume and temperature or PVT studies produced data sets used to protect reservoir performance and determine estimated ultimate recoveries from unconventional reservoirs. Core's technologically sophisticated clients use these data sets to optimize production streams and maximize their return on invested capital and free cash flow.

60% of the revenue in Core Laboratories, Reservoir Description segment is now generated by the characterization of reservoir fluid, up from less than 30% some 20 years ago. Now to review the 3 financial tenants on which Core used to build shareholder value over our 22-year history of being a publically traded company.

Incidentally, Core as a company is currently celebrating our 81st year of technological innovation.

During the third quarter, Core generated over $25 million in free cash flow and once again produced the industry-leading return on invested capital for the 32nd consecutive quarter. Also during the third quarter, 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 our quarterly dividends and share repurchases.

I will now turn the call over to Chris for a detailed financial review. Chris?

Thanks, David. Now looking at the income statement. Revenues were $166.2 million in the third quarter, which was led by the growth in our Production Enhancement segment. On September 5, we released an announcement regarding the impact from Hurricane Harvey and an estimate that there would be a $4 million negative effect to our revenue and earnings for the third quarter.

There were several significant hurricanes during the quarter, which primarily disrupted business for our Reservoir Description segment with temporary closures to both our facilities and our client facilities in the Gulf Coast and Caribbean region. However, our Production Enhancement segment was less affected from the hurricanes and actually showed stronger growth than we had originally projected for the quarter.

Of this revenue, service revenue was $117.6 million for the quarter, which is comparable to last quarter.

The $4 million impact to our revenue from the hurricanes primarily affected our service revenue in the Reservoir Description segment. However, the negative impact from the hurricanes was more than offset by the stronger-than-expected growth from our Production Enhancement well completion diagnostic services. Product sales were $48.7 million for the quarter, up $2 million or 4.4% sequentially.

The growth in U.S. sales were in line with the EIA's published completion activity. However, were offset by lower product sales to regions outside the U.S.

Moving on to cost of services, which were 71% of service revenue for the quarter and up 69% from last quarter primarily due to the impact from the hurricanes during the third quarter. Cost of sales in the third quarter was 76% of product sales revenue, a nice improvement from the 79% last quarter and 91% in the same quarter last year.

Despite the effects from the hurricane, we continued to see improvements in our operating leverage and the absorption of our fixed cost on higher levels of revenue.

G&A for the quarter was $11.9 million, up from $11.1 million last quarter, and is primarily related to increased employee headcount and compensation.

We expect G&A to be around $46 million to $48 million for the full year. Depreciation and amortization for the quarter was $6.1 million, which has been decreasing slightly over the last several quarters. We would expect some minor growth in depreciation expense, reflecting the increase in our capital expenditures and support of more recent growth activities.

For 2017, depreciation expense is expected to be approximately $25 million to $26 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 third quarter. For the third quarter, our effective tax rate is 15% and the impact from FX was minimal, as such we have reported only U.S. GAAP results.

EBIT for the quarter was $27.5 million and continues to represent best-in-class EBIT margins of 17%. Income tax expense for the quarter was $3.7 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 for the quarter was $21.1 million, down from $22.7 million last quarter due to the negative impact from the hurricanes. Earnings per diluted share was $0.48 for the quarter. As we move on to the 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 $129.7 million, which are comparable to the balance of June 30 and our DSOs remain strong at 67 days. Inventory $34.5 million, down about a $1.1 million sequentially as inventory turns continue to improve while demand for our products continues to expand. We expect our inventory turns to continue showing improvement throughout the remainder of the year.

And now to the liability side of the balance sheet. Our accounts payable were $34.9 million comparable to our balance of December 31, but down about $6.7 million from the balance of June 30. Our long-term debt ended the quarter at $234 million and remained at the same level from last quarter. Capital expenditures for the quarter were $4.9 million and $14.3 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 for the remainder of the year.

Looking at cash flow. In the third quarter, cash flow from operating activities was $29.9 million, and after paying our $4.9 million in CapEx, our free cash flow in the quarter was $25 million. 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 119% for the quarter. 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, very nice. We're encouraged by the increasing focus of our major clients regarding capital management, return on invested capital, free cash flow and returning capital back to the shareholders as opposed to just production growth goals.

The companies adopting these metrics tend to be the more technologically sophisticated operators and form the foundation of our worldwide client base. We expect that we will benefit from this shift in focus from production growth to employing higher technology solutions to maximize economic production growth and EORs.

The clients' increased use of our higher technological solutions has been considered in our guidance for the continued increases in operating and incremental operating margins into the fourth quarter.

Clients will pay for technologies that boost their ROIC and free cash flow. Internationally, a number of FIDs, final investment decisions, have been announced during the quarter by oil and gas companies. However, activities for Core Lab relating to those FIDs are not expected to materially increase this year as operators are currently developing the project plans and should begin to implement those plans early in 2018.

Further, the international rig count, remains flat due to limited capital projects underway by international operators. However, operators are continuing to spend from their operating budget on maximizing recovery from their existing producing fields.

We expect fourth quarter 2017 North America completion activity levels to continue to expand as current completion levels will be supplemented by reductions in DUCs, drilled but uncompleted inventories. And we expect fourth quarter international activity levels to be flat-to-up slightly from third quarter levels with most ongoing projects to be funded largely from the operators' operating budgets.

We project fourth quarter revenue of approximately $171.5 million. As discussed in prior quarterly earnings releases, we continue to expect our incremental operating margins to exceed 60% as recovery phase continues, followed by historical incremental operating margins of approximately 35% to 45%.

Operating income is projected for the fourth quarter to be approximately $32.8 million, yielding operating margins of approximately 19%. EPS for the fourth quarter is expected to be approximately $0.58 per share.

Fourth quarter free cash flow is expected to exceed net income again, and we also expect to continue to return all excess capital to our shareholders during the quarter.

Now with that guidance, we'll turn the call over to Monty for an operational review.

Thanks, Dick. In the third quarter, our results were negatively impacted by Hurricanes in the Gulf of the Mexico and in the Caribbean, primarily affecting client operations. Revenues for Q3 reached $166 million and generated operating earnings of $27.5 million and operating margins of 17%.

Core Lab employees have worked through various difficulties to service -- to keep our services and products ready to meet our clients' needs. We thank all of our employees for all they have done to serve clients around the globe.

Reservoir Description was the segment most impacted by 3 hurricanes. Revenues for the third quarter were $101 million, generating operating earnings of $15 million and operating margins of 14.4%. Reservoir evaluation and exploitation in the Permian Basin region of the U.S. continues to grow in activity and demand. Core's ongoing response to this continued demand in both the conventional and unconventional formations has been to continue to design and implement testing technology and techniques to allow for additional hydrocarbon reserves to be found and produced.

Continuous-flow gas chromatography isotope ratio mass spectrometry is one such automated technology that is currently being used as part of our analysis to further characterize and enhance development of shale resource place. By measuring stable isotopes signatures of CO2, methane and natural gas with extreme precision, our clients gain insight into the history and origin of hydrocarbon generation and migration within the basin. A stable isotope composition of hydrocarbon gas and CO2 is commonly used to solve exploration, development and production issues, such as gas origin, reservoir compartmentalization, [CO] location and thermal maturity of the source rocks.

Core has continued service for several clients and [wellsite], Core handling and [Core and fluid] analysis in the offshore region of South America in the third quarter as a multiple operators develop and evaluate potential reservoir deposits.

Core's newest technology at the wellsite and onshore, allow for noninvasive screening through CT tomography, enhanced gamma and acoustic velocity measurements focused on real time data acquisitions, prior to commencement of laboratory testing, continue to provide early insight into the quality of formations being encountered.

In-depth laboratory analysis is continuing on Core and fluid samples from these fields. Production Enhancement is less impacted -- was less impacted by the hurricanes and, therefore, did not suffer as much in revenue reductions. Revenue for the third quarter was a $65 million, generating operating earnings of $13 million and operating margins of 20%.

The growing industry acceptance of Core's HERO PerFRAC technology continued during the third quarter. Recently our Marcellus operator compared cluster efficiency results in a horizontal shale test well utilizing Core HERO PerFRAC, another consistent hole size charge and a conventional deep penetrating charge. The completed zones were diagnostically evaluated to determine the amount of clusters showing effective with near wellbore proppant stimulation with [0 wash] proppant [ratios].

The stages perforated with HERO PerFRAC were unknown to Core Laboratories until after the logging was performed and reported to the operator. The results of the SpectraScan post-frac log analysis showed that both the standard deep penetrating charge and the other consistent hole size charge led multiple close -- clusters unstimulated or understimulated, while the clusters perforated with the HERO PerFRAC were 100% stimulated demonstrating the importance of HERO PerFRAC in completion of wells to be frac.

An independent operator has been very active in the a wet-gas window of the Eagle Ford play asked Core Lab to help them optimize the completion designed for a 23-stage [logging perf] completion in South Texas. After experiencing problems fracking the first few stages of well, they ask Core Lab to help them determine 3 things: Why were -- are they having early screen outs preventing them from getting all the sand pump? How well are the stimulating all 10 perf clusters within a given stage and will diverters help them stimulate all of the clusters within each stage.

Core recommended and ran our SpectraScan proppant tracers in the remaining frac stages and followed with our SpectraScan gamma ray logging tool. With these 2 technologies, Core was able to determine that several of the perf clusters in a number of their frac stages were in fact, not being effectively treated. And the diversion performance of the particulate diverted that they employed was quite inconsistent with results ranging from effective diversion to no diversion to detrimental diversion.

After evaluating all of the completion diagnostic data, it was determined that the particulate diverter was ineffective and if there were other more cost-effective methods that they could employ to ensure more uniform perf cluster coverage and eliminate the early screen outs.

The new completion methods provided for an increase and Stimulated Reservoir Volume, accessing more of the reserves and ruled out the need for diverters. The operators since eliminated the application of the diverter and has applied more cost-effective methods for ensuring the uniform treatment coverage of the reservoir.

The primary benefit of the diagnostics effort was the optimization of the frac design to increase the Stimulated Reservoir Volume, leading to a significant improvements in the EUR of the wells. Moreover, it is estimated that the resulting frac design changes saved the operator $100,000 to $200,000 per well, in completion cost going forward.

Rachel, we'll now open the call for questions.

(Operator Instructions) The first question comes from Greg Lewis with Crédit Suisse.

Dave, could you talk a little bit more about Reservoir Description? And you mentioned fluid analysis is now 60%. I guess, that's doubled as a percentage of Reservoir Description over the last 20 years. But as that trends forward or going forward over the next couple of years, is that something where we think that fluid analysis is going to become a bigger share of Reservoir Description? Or do we think it could reverse? And really what does that mean for margin trajectory over the next couple of years?

Yes, all good questions. We do expect in this current climate that we will see increased amounts of reservoir fluid work, owing to the work that we're doing in EOR in unconventionals because that's a very heavily weighted towards the fluid ends and understanding how those 3-phased fluids move through that unconventional reservoir. However, in saying that, when international activity ramps up over 2018 and '19, we'll expect a lot more rock to come in. So you'll get some balance in there just from the sheer weight, no pun intended, of rock that will start to come into our laboratories, owing to projects in the international theater. So all in all, we would expect that amount of fluid work to trend up over time, which is a favorable to us because operating margins on some of our most sophisticated testing on the PVT side. For instance, being able to analyze fluids at 400 degrees Fahrenheit, 30,000 pounds per square inch in pressure, we're the only guys on the planet that can do that. So we're looking for margins also to be positively impacted by the increasing amount of fluids being done. So all in all, if you look at last peak margins for Reservoir Description, somewhere in the high 20s, at the peak of -- let's say 2018, '19 and '20, those margins could creep up over 30.

Okay, great. And then just you mentioned the, and I guess, we're seeing a shift from E&P as it looks like they're focused a little bit more maybe on value or volume. And that it seems like that has been more of a recent trend. I'm just curious, as Core Lab's already -- have you guys already started to see some of the benefits from that? Or is it more just, "hey this is -- this is how your customers are thinking about it and the conversations are now just kind of starting to get going."

I would say that we have had some benefit from that, but in most cases, these conversations are starting. We're seeing the use of more of our higher technological applications and technology. So they're getting a bigger bang for the buck. So you see companies out there that are starting to employ this. A great example of that would be EOR and unconventionals. Certainly, if you can go ahead and take your recovery factor in unconventionals from 9% up into the mid-teens for a couple of $3 million of incremental expenditure, you're going to get a much higher return on that investment leading to higher EURs and free cash flow, some of which can be returned to their shareholders. Companies mainly involved in this would be technologically advanced clients like BTE, Chevron, Shell, Conoco, Pioneer Natural Resources, OXY, EOG, Anadarko, Marathon, Apache to name a few. But those are the most active in using some of our highest technology to increase the effectiveness and the efficiency of the capital that they've invested.

The next question comes from Ole Slorer with Morgan Stanley.

Good to see you guys back on track again after that little snafu last quarter.

Ole, yes. We've got the ship righted.

Good to see, Dave. And so most -- a little bit more specifics on -- last time we met you, we were quite excited about gas cycling as a concept. Could you give an update on at that and how your customers are taking to it? And I presume that this -- is all assumed that the 30% to 40% of your revenue base that comes up from shale is where most of the growth will happen over the next, certainly 12 months before things probably even out a little bit. So I just want to focus a little bit more on that component and particularly what you're seeing with the -- what kind of a traction you're getting when it comes to tertiary fracs, secondary fracs, very fine mesh. We talked a bit at the last conference call as well as gas cycling and how that is playing out?

Okay, yes. Let's start with the gas cycling for EOR and unconventional. We have kicked off a joint industry project in the Eagle Ford that is continuing. We will be following that up because we're making proposals to the industry right now to do a joint industry project in the Wolfcamp out in the Permian Basin. That being said, the number of proprietary projects where companies are approaching us continues to grow. So this idea of looking at dollars to be invested and to try to get their best to return and the number of clients that I just mentioned, all of them certainly interested in doing that. So still early days for this, but if the results that we've achieved in the lab could be achieved in the field and we expect either later this year or early next year, field testing to begin, I think we would be on to a step function in the amount of revenue that we generate from fluids and rock work in the unconventional reservoirs.

Tied to that, ...

David, when should -- I understand industry -- joint industry study have to take time, they have to be absorbed. There's a timeline around that, getting into Wolfcamp could be very exciting and helping people assess some of the gas issues in the Permian, in general. But what's the timeline in terms of -- I'm sorry if I interrupted you, probably about to talk about that?

Yes. On the timeline, certainly, the project is being kicked off now. These projects usually last depending on the number of clients that are involved in them. We're requiring them to submit Core and fluid samples and as the project expands, it's actually ever-growing in its timeline. If you look at some of our early shale studies, where we've had 60 and 70 participants, those studies actually lasted years and this could be the case here now, [or if you just] being kicked off here in the second and third quarters. So all depends on the growth of the number of clients, what that work program is ultimately going to look at. So it's a tough question to answer but certainly it's underway. We hope and we think that these projects actually can last for years with increased interest from the client community.

The important aspect for Core Lab is, we are giving results of those studies throughout the life of the JIP and each time we distribute data and information, that's pretty much a revenue opportunity for us. So it's not like we have to complete the JIP before we get to recognize any economic benefits. So with them lasting over several, several years, that gives us many years of revenue opportunity.

Okay. Sorry, due to translate as you do -- do the participants in these studies actually get their results come back and give individual contracts to you and when does that kind of kick in?

That's the beauty of these studies: often times, that's what happens. You get an operator who is a member of the JIP become comfortable with our approach. And the protocols that we're using in the testing in the -- and certainly the outcome of the testing. And then, they will say, let us do those same studies now on just our property. So you're right, Ole, that's the traditional model of the JIP that it does spin off proprietary work.

Okay, well. If you can give one final additional color. So when you think all of this -- I think we're all sort of looking for something that could take a shift a couple of gears for your growth engine. And as I suppose, this could be it. So would you give any guesstimates on -- it is a back half '18? When do we expect a more measurable impact or is it even longer term? How should we think about it?

No. I think certainly in the back half of '18, you will see some contribution from this depending on the number of clients that do indeed join that. I think the best would be just look at our guidance going forward and when you'll start to see significant contributions from those. You'll see expanding operating margins, expanding incremental margins.

Okay. Well, thanks for that Dave.

Okay. And before I leave you, I want to tie into because you made an important point on micro proppants. For these studies to be successful, we found that the tertiary, secondary along with the primary fracture systems have to remain open and that's why we've been requested by some of the participants, and almost all of participants in our joint industry project to evaluate proppants -- why they have asked us to now study 400 and 200-mesh proppant along with our studies of 170, 60, 40, 30, more of the common proppants. But we're thinking right now that the 400-mesh proppant would be used to open up the tertiary fracture network. And 200-mesh proppant will be used to prop open the secondary fracture network along with the 170 and 30-mesh for the main network. Right now, our calculations show that if we can implement and place of 400 and 200-mesh sand that we may increase the amount of surface area exposed to flow in the reservoir by an order of magnitude. And that's what leads to these larger recoveries from these ultra-tight reservoirs. So that is an important piece of the EOR discussion as well and that's why both projects are going along in tandem.

Well, those are difficult proppants to source in quantities, so good luck.

Yes, very good.

The next question comes from Rob MacKenzie with Iberia Capital.

Good recap there on the EOR. I wanted to shift to Production Enhancement here a little bit and dig into some of the comments and success of HERO PerFRAC, if I can. Can you give us a handle, Monty or Dave, in terms of how deep you have HERO PerFRAC penetrated as percentage of your perforating charges sold today? And where can that go to in your mind?

Rob, this is Monty. The HERO PerFRAC is the fastest growing part of our business in the perforating charge business. It is not the largest, so there's a lot of room to grow in that area. I think some of the -- I mentioned, the one study that an operator had done, there are numerous trying to test out the different perforating systems and our HERO PerFRAC seems to show the best results. So everybody I talked to from the client side, their future is on free cash flow, free cash flow, free cash flow. And the HERO PerFRAC opens up so much better their frac jobs, ensures completion of the various stages as were shown in that particular study, we believe that's a very common result when using the HERO PerFRAC. And so we're seeing big growth quarter after quarter in that as more operators adopt that system. Now it's a little more expensive perforating system, but the result should generate a lot more cash flow for a long time. So we see this as a big and ever-growing part of our perforating family.

Would you say it's kind of a 20%, 30% at -- where would it be in terms of percentage of your non-commoditized charges being sold today?

Currently, we're probably at around 5% to 10%. So there's a lot of room for growth in this.

And then shifting gears, I guess, question for David. I guess, you mentioned in your prepared comments, Dave, about a number of FIDs that they have gone forward that announced here of late. Can you give us a feel, if it's not too early, in terms of how that might impact what your expected trajectory might be beyond the end of this year, particularly, relative to the activity level in 2017? Or put it in a different way, the pace of FIDs so far, how does that contrast year-over-year from what we saw this time last year looking forward?

Yes, Rob, Gwen's done a lot of good work on this. So I'm going to turn this question over to her.

Rob, so far in 2017, we've seen approximately 14 FIDs announced. And that's probably double what we saw in 2016. And there's probably another 14 to 15 potential FIDs that are on the list. We think there's probably half of those that may be announced in the last quarter of the year. And so you -- and you also see additional discoveries that are being announced from a number of the operators. You've got [BHT's] Deepwater Mexico project that they announced that is south of the Los Alamos block, so that's positive. And you've got additional discoveries from the offshore of Guyana. Turbot was the last one that they announced in October with ExxonMobil.

So out of those, Rob, right now, we're probably generating revenue out of maybe 1/3 of those. So let's say 5 projects out of the 14 that are under ramp right now with the largest contribution coming from the excellent offshore Guyana as it stands right now. But we're also generating revenue from some of the projects West Africa, Northern Caspian Sea. So fully, we'll probably be engaged in a lot of those projects by sometime midyear next year.

Is it too early to kind of put a revenue growth target for Reservoir Description out of that? High single digits, low double digits or is that too hard?

I'm still -- I would still use, Rob, the algorithm for Reservoir Description looking at industry activity levels at 200 to 400 basis points and that probably gives you pretty good guidance. I don't want to get any more specific in that because I don't think we can accurately do that.

The next question comes from Chase Mulvehill with Wolfe Research.

So I guess, a quick question on 4Q. How much revenue growth do you think that we should model for Reservoir Description? And then, do you think we can kind of get back to that 18% EBITDA range in 4Q, for Reservoir Description?

Yes. I think, I -- actually, just to hit Production Enhancement as well, I would spread it evenly, the increase in revenue between those 2 segments. And the 18% or so base margins. Remember those are EBIT margins, not EBITDA margin.

Correct, correct. Okay, and then what do you think the timing is of hitting the 20% mark in Reservoir Description?

I think you're going to see that come up in the next few quarters with the incremental revenues stacked on top of this base. Incremental margins on those are going to be strong and that's really what's going to expand the underlying margin.

Okay. I see back to unconventional EORs. What are the key reservoir characteristics that you look for to determine whether a certain area of a play is a good candidate of unconventional EORs?

Yes. Chase, we're looking at right now primarily Tier 1 properties, which are critical. And again, remember, we've got internal algorithms here at Core that uses 23 parameters to define what Tier 1 property is. So that's our first check the box, whether this is going to be a successful endeavor or not. So that's a critical issue followed by a detailed reservoir fluid analysis, determining what the composition of those fluids are and what would be the best way to absorb or absorb additional amounts of long-chain hydrocarbons, via the use of the gases that are already in that reservoir. So a ton of parameters that are involved in that. Quality of reservoir rock certainly is #1. And #2 is the viability of using the reservoir gases to capture more recovery of longer-chain hydrocarbons.

Is there a certain amount of mix when we think about either ethane or methane that these reservoirs need to have for it to be a good candidate?

All depends on what the fluid constituent composition is in the reservoir. So the answer is yes. But each one is going to have to be engineered separately and specifically for the rocks in the reservoir. So, 1 cookie cutter won't make it all for the Eagle Ford, we already know that. And 1 cookie cutter won't make it all ready for the Wolfcamp just in some of the proprietary work that we've done there.

Okay. One quick follow-up. If we think unconventional EORs are obviously going to be a big growth over the medium to longer-term. But is there any other opportunities whether organic or inorganic to drive accelerated growth at accretive returns over the next few years?

Yes. We are working on some projects in our skunkworks that we hope to talk about over the next 2 or 3 quarters, would prove to be as exciting or maybe even more so than EOR from unconventionals.

The next question comes from Sean Meakim with JPMorgan.

So last quarter, we talked about some of the timing delays of recognizing revenue associated with the diagnostics work on some of these high-well pads. Could you give us an update on how that business progressed during the third quarter?

Yes. So if you recall, just for others on the call, as the industry moved from single-well drill and complete more pad, drill them all then come in and complete them all, we saw that really impact us last quarter and as a prevalence of pad has played out, that's just worked through the system. So most of our completions now are really already on pads. And so...

So in other words, you've (inaudible) more steady state today.

That is correct.

Got it, okay. And then just thinking about EOR, maybe on more of a global basis, looking at the next couple of years. Could you maybe just compare and contrast? Just trying to think about the addressable market for large conventional resources like the Middle East compared to unconventional shale in the U.S.?

Well, that's a different sort of EOR, of course, we're looking at. We have been doing EOR studies in the Middle East for some time. And that is growing market as some of their reservoirs get to the point where EOR is more appropriate. We do those test in our Middle East laboratories, providing them with the information they need for that. It's different from the engineered gas EOR that we're the doing on the unconventional here. The engineered gas isn't for every reservoir even unconventional. So we test out and as Dave just said, it's a different gas blend that you're going to need -- i.e. that's where the engineered gas composition comes from. You have to have it for that particular reservoir or even that segment of a reservoir depending on the fluids, the rock and what's necessary to stimulate them in the best way. So it's a different EOR to the Middle East from what we're the doing in the unconventionals, but quite a bit work going on in both areas.

Yes, Sean, I would venture to say that in the Middle East, either fields are already under some type of EOR system or they are in the queue to have a study suggested for that. So you can see the importance mounted on enhanced oil recovery out of Middle East fields. If you remember back a year ago, 1.5 years ago, we consistently said that the production in the Middle East was at unsustainable levels and then we got the big OPEC cut. For their production to be sustainable at these levels, certainly EOR's going to play a large role in that, and that's why we're thinking, we're seeing the amount of work in EOR that we're doing is certainly is growing in the Middle East. Probably is our only international theater where we are seeing an uptick in activity and revenue generation.

Just to summarize a little bit, the revenue and margin potential, would you say -- so clearly U.S. more nascent today, but faster rate of change potentially as things really get underway, would you say that in terms of the opportunities size, which is bigger than the other? And just thinking about a profitability perspective, is there anything substantially different to highlight?

Well, certainly in the Middle East, those projects are ramping up and gearing up right now. The EOR and unconventionals, there's a lot of unknown parameters there as of yet. I think we're still testing theories and hypothesis on how all this is going to work. So that ramp stage might be a little bit slower.

The next question comes from Marc Bianchi with Cowen.

I guess, back to the FID discussion. Those 5-or-so projects that you're working on. Can you give us a sense of quarterly revenue that might be associated with kind of all 5 together?

Every quarter, it varies, but probably somewhere in the order of -- probably lower double-digits, something like that.

Okay. Lower double-digits as in something like $12 million, $13 million of revenue, that's the right...

Yes. But remember, it varies every quarter depending on project flow.

So historically, we've said, Marc, if we did get a core of material size, we could earn somewhere between $3 million to $5 million in revenue. It takes us a couple of quarters to generate that. So it depends on how these FIDs turn into activity that pulls the core and fluid. So let's say there's an announcement, right now for an FID, that operator has got to get their program in place, they have to get a rig under contract. That rig has to get to total depth and have to take into core, so when is that? That takes at least 6, 9, 12 months.

Right. And Dick, can you remind us how many core's per FID typically? If I don't -- I mean, I'm sure it varies widely. But just give us a sense of the range there.

It ranges from 0 to 40.

Yes, it is -- it is pretty wide.

Okay, well. That gives me something that work with.

Think about maybe a layer on top of that. Think about complexity of the reservoir, for what the operators may say publicly that probably means somewhat more data or if it's in a province that hasn't been well understood, they probably will want more data. So that would be a good thing for us. So layer some of that in.

Okay. I guess, shifting over to one that's maybe more industry related, but you guys have a pretty good insight. Last quarter, the E&P conversation became very much about GOR. That seems to be misinterpreted. Now we're hearing about frac crude efficiency being a problem. Is there anything you see as an emerging issue for E&P productivity as we go into this quarter of E&P reporting and kind of over the next couple of quarters something that could become a relevant discussion topic?

We know of no new issues.

The next question comes from Scott Gruber with Citigroup.

Kind of continuing under the same line of questioning. I found a comment in your press release interesting where you were discussing the tortuosity reduction achieved by the HERO PerFRAC charges, how that can actually reduce pumping pressures. Based on your assessment, can operators actually reduce the amount of horsepower deployed on site when using the charges?

That's the whole idea.

Absolutely.

What order of magnitude?

Somewhere between 5% and 20% depending on rock type. And if you look at these, as Monty said, these are more expensive systems. But at the end of the day, they get a much better return on their total investment because they can save money on horsepower that needs to be deployed at the surface.

And you get a better flow rate.

And they have, yes, more completion -- getting every segment stimulated is the key.

And have operators acted on this? Have they gone to pumpers and requested smaller crews to try to save on the rate?

Well, they're just -- they're requesting less horsepower at the surface. I mean, that's one of our big sales pitches to that. That you're going to pay Core Lab a little bit more but you're going to pay less for your all over frac job. And lower amounts of crews and compressive horsepower at the surface, that's a good thing for Core Lab.

Definitely. Just a quick question on the guidance? I was reviewing previous guidance. I couldn't help but notice the 4Q guide is very similar to the high end of the original 3Q guide in both revenues and EBIT, but earnings is actually a couple pennies higher at $0.58. What's the ETR assumed in the model for 4Q?

It's the same, 15%.

Same 15% and net interest? Is there anything below?

Yes. It's like $2.7 million, $2.75 million on interest expense. So it's the same, it's our thought as the incremental margins might be a little bit stronger because some of the cost that were still embedded from the hurricanes should be gone.

The next question comes from Stephen Gengaro with the Loop Capital.

A couple things. Just to start, a quick clarification, did you, in response to, I think to Chase's question, did you guide RD margins to 18% in the fourth quarter or that you'd get there soon?

We said our operating margins for Q4 companywide would be 19%, we haven't given any segment guidance, but companywide, 19%.

Okay. But the basically 100% incrementals. A chunk of that outside incremental's driven by kind of hurricane related recovery in Reservoir Description. Is that fair?

So you're going to see Reservoir Description margins improved as well. And so we did say in the commentary that, without the hurricane, that

Reservoir Description would be around 18%. So we see that as a base from which we should grow.

Got you. That's fair. And just as a more of a general comment, as you look at the inventory of these drilled but uncompleted wells and you sort of think about keys of potential growth relative to rig count activity, kind of 2 questions: one is, how long do you think those could kind of help you sustain solid growth? But more importantly, give us a sense of the inventory of uncompleted wells right now. How many of those are actually economical at current prices that will actually get completed? Is there any portion of them, which are kind of sort of hanging in that mix but really kind of useful?

Yes. Thanks, Scott (sic) [Stephen]. Let's say we're going to drill 17,000 wells over the next year. We've got about 7,000 wells that are DUCs. So you can see, we're going to -- that DUC inventory is going to be able to bolster completions for certainly over the next year or maybe even 1.5 years. We do agree with you some of the DUCs will never be completed due to the economics surrounding them. Right now, we don't have a good feel for what that is. But certainly, it's probably going the number into the 100s.

Okay. And then just one final. When you look at the world and you look at sort of massive underinvestment in non-OPEC international. Any sense for when you start to see a bigger impact on that on global production?

Well, certainly, I think you're going to see global production by the end of 2018, '19, certainly screening for international investment. We just look at the global inventories and actually Gwen's got some good information on that, why we continue to be bullish on crude. Talk about global inventories. And this ties right in with international non-OPEC production.

So we think global inventory continued to fall since July a year ago. And even more consistently, over the last 16 weeks, we've seen some consistency in the data that's been put out. In terms of those inventory levels falling. The other items that we're monitoring, are the days in inventory for consumption. And what history tells us is whenever that reaches 40 days, we see pressure on crude oil price. Today, we're at approximately 43 days. We think we get near 40 -- to 40 days in Q1 of 2018.

A follow-up question from Rob MacKenzie with Iberia Capital.

A follow-up for you, Monty, if I may. On the HERO PerFRAC. Given the success of that with operators, I would think it's probably about time start seeing competition come in there. Are you seeing competitive operators crop up yet, to try and to capture that same market?

I think in the study I mentioned, there was another supposedly consistent hole size charge that was used for part of that study and they were not successful. So people try to imitate, but they don't exactly know what we're doing, how we're doing our system. So sure, they're going to try to imitate, but they have not been successful in doing so.

Rachel, we'll take 1 additional question.

The final question comes from William Alpaugh with Simmons & Company.

Just a quick one. So last quarter, you called out labor and equipment shortages. Do you not see any of that this quarter? And can you give us just an update on that?

Yes. What we were talking about was the shortage of completion equipment, primarily the pressure pumping equipment. So we certainly heard positive news out of Halliburton. I think all of their equipments that they had in cold storage or stacked had been out in Q3 and Schlumberger says all of theirs will be out by the end of Q4. So I think that goes a long ways as to alleviating those shortages that were hitting the industry in the last couple quarters. Hopefully, William, that's behind everyone.

Okay. I just want to check and see if you were all seeing the same thing.

Okay, very good. So in summary, Core's operations continue to position the company for activity levels in the fourth quarter of 2017. And we know significant challenges await. However, we have never been better operationally or technologically positioned to help our clients maintain and expand their production existing 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 all excess capital being returned to our shareholders via dividend and opportunistic share repurchases. So in closing, our 89th quarterly earnings release, we thank all of our shareholders and the analysts who follow Core. And as already noted by Monty Davis, the Executive Management of Core and the Board of Directors of Core, gives special thanks to all of our worldwide employees that have made these results possible. We are proud to be associated with their continuing achievements. So thanks for spending your time with us this morning, 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.