David Demshur - Chairman, President, and CEO Dick Bergmark - EVP and CFO Monty Davis - COO Chris Hill - Chief Accounting Officer Gwen Schreffler - Head of IR.

Rob MacKenzie - Iberia Capital Sean Meakim - J.P. Morgan James West - Evercore ISI Marc Bianchi - Cowen Thijs Berkelder - ABN-AMRO Stephen Gengaro - Loop Capital Tom Dillon - William Blair Gregory Lewis - Credit Suisse Chase Mulvehill - Wolfe Research Benjamin Owens - RBC.

Welcome to the Core Laboratories Third Quarter 2016 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation there will be an opportunity to ask questions. [Operator Instructions] Please also note, today's event is being recorded. I would now like to turn the conference over to Mr.

David Demshur, Chairman, President, and CEO. Mr. Demshur, please go ahead..

Well, thanks Rocco [ph]. Let me 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 2016 earnings conference call.

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

Gwen will start by making remarks regarding forward-looking statements. Then we'll come back and give a review of the current macro environment updating U.S.

and worldwide crude oil supply thoughts as related to newly calculated net decline curve rates, and then comment on Core's three financial tenants, which the company employs to build long-term shareholder value. Chris will then follow with a detailed financial overview and additional comments regarding building shareholder value.

This will be followed by Dick Bergmark commenting on Core's fourth quarter 2016 outlook and a general industry outlook as it pertains to Core's prospects.

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

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

Gwen?.

Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, as well as other reports and registration statements filed by us with the SEC and the AFM. Our comments include non-GAAP financial measures.

Reconciliation to the most directly comparable GAAP financial measures is included in the press release announcing our third quarter results. The non-GAAP measures can also be found on our Web site. With that said, I'll pass the discussion back to Dave..

Thanks, Gwen. Core believes that worldwide crude oil supply and demand markets are close to balancing, and will balance by the end of 2016. On the crude oil supply side, U.S.

production peaked at 9.7 million barrels a day in March of 2015, and has since fallen by over 1.3 million barrels per day owing to high decline curve rates associated with tight oil reservoirs. These sharp declines from U.S.

land production are continuing late in 2016, and Core believes these decreases for 2016 will probably reach 1.1 million barrels of oil per day. Lower levels of new wells and delayed production maintenance will exacerbate the fall of U.S. land production going into 2017.

Remember, decline curves are linear in time, but logarithmic in scale in production decline. An excellent example that the decline curve always wins and never sleeps and the difficulty in reversing fall in production totals in tight oil reservoirs is the Bakken [ph] formation.

Bakken production is down over 233,000 barrels a day since its peak in December of 2014. Since that peak there have been 1,770 wells added to a producing base of 9,000 wells of production leading to Bakken's net 12% decline curve rate over that period from December of 2014 up through August production.

However, the average productivity for Bakken producing well is down 26% since peaking in 2014. As long as Bakken completions fall below 130 per month, Bakken production will continue to fall in 2017.

Moreover, further net gains from legacy deepwater Gulf of Mexico projects will be needed to offset the significant decreases in the existing Gulf of Mexico production base. These legacy deepwater Gulf of Mexico projects may add a net 100,000 barrels a day to U.S.

production in 2016, down from our earlier estimates of 160,000 barrels given earlier this year. This is only slightly offsetting the material onshore and shallow water declines. Core estimates that the current net production decline curve rate for U.S. production is approximately 11%, up from 10.1% reported last quarter.

Globally Core estimates that the net crude oil production decline curve is currently at approximately 3.3%.

Applying the 3.3% net decline curve rate to the worldwide crude production of approximately 85 million barrels per day means that the planet will need to produce approximately 2.8 million new barrels by this date next year to maintain current worldwide production capacity.

With limited long-term worldwide sustainable spare capacity, Core believes worldwide producers will not be able to offset the estimated 3.3 net production decline curve rate in 2016, leading to falling global production.

These net decline curve rates are supported by recent IEA data indicating declining production on a global basis through the third quarter of 2016. Therefore Core believes crude oil markets will more than rationalize in late 2016 in price stability followed by price increases, some occurring as we speak, are returning to the energy complex.

Remember the immutable laws of physics and thermodynamics means that the crude oil production decline curve always wins, and it never sleeps. On the demand side of the crude oil market, the IEA estimates increased worldwide demand in 2016 of approximately 1.3 million barrels per day. Currently, the U.S.

is using approximately 10 million barrels a day of gasoline near record levels. Recent Chinese imports coupled with strong growth in India were at all time highs. In addition, China just reported a year-over-year drop of 400,000 barrels of oil per day to 3.8 million barrels of oil per day of production which is near a six-year low.

Worldwide supply and demand will balance as they always have in past market disruptions. Now to review the three financials tenets by which Core use to build shareholder value over our 21-year history of being a publicly traded company, incidentally, Core is celebrating its 80-year history of innovation in 2016.

During the third quarter of 2016, Core generated free cash flow that exceeded our net income for the ninth consecutive quarter. Free cash flow for the first three quarters of 2016 more than doubled net income, clearly one of the best in all oil field services.

Moreover, Core converted over $0.23 of every 2016 revenue dollar in the free cash flow, again, leading all oil field service companies. So, free cash flow matters to Core Lab shareholders. During the third quarter, Core once again produced oil field industry leading return on invested capital for the 29th consecutive quarter, topping an ROC of 22%.

Producing an industry leading return on invested capital has not happened by chance. A real time concern for investor is the exposure to the Venezuelan market. Core invested in 2013 a decision at which time it was highly questioned by our analysts, shareholders, and potential shareholders.

During the Vexit [ph] in 2013, led to an apparent lower short-term revenue and earning growth rates for the company. We thought that this was at risk over the long period. This paralleled our discussion to departing in-country Mexican operations over a decade ago. Today, downsizing Latin American and South American operations are very trendy.

Core's internal risk assessment process determined that long-term risk clearly outweighed long term value for the Venezuelan market. With hundreds of millions of past write downs and with over a billion dollars of write downs to come, Core believes that the Vexit was the proper decision protecting long-term return on invested capital goals.

ROC matters to Core Lab shareholders. And finally, during the third quarter of 2016, Core returned over $26 million back to our shareholders being our quarterly dividend and share repurchases. Core will continue to return all excess capital back to its shareholders in future quarter. The return of excess capital matters to Core Lab shareholders.

I'll now turn the call over to Chris for a detailed financial review.

Chris?.

Thanks, David. Starting with the income statement, revenue for the third quarter was 143.5 million, so down sequentially only about 3% as the majority of our revenue still come from outside the U.S. where activities held up reasonably well.

North American completions, however, actually fell in the third quarter even as rig count began recover causing our revenue to be slightly lower than anticipated. That being said, as we will discuss in a moment, our operating income, net income, and EPS were all up on a sequential basis.

Of this revenue, service revenue is a little over a 114 million for the quarter. Down only 3.4% sequentially as most regions were steady and the decreases were primarily due to reduced activity in North America.

Product sales revenue, which is more tied to North American activity associated with the completion of wells, has continued to outperform market and was down less than 2% sequentially to 29.3 million. That being said, we did expect growth in the production enhancement versus Q2.

But as we have stated previously, there is some lag time between additions to rig count and when the wells are actually completed. So although rig activity in North America showed some stabilization and even increases in certain plays, average completion activity was down this quarter.

Moving on to cost of services for the quarter, they were 71% of revenue, and despite lower revenue, stayed in line with Q2. So, you can see our cost reduction actions have taken in the first half of the year are being realized, which helped us continue to generate some of the strongest margins amongst oilfield service companies.

Our cost of product sales was 91% of revenue, up just slightly, but pretty consistent from prior quarter. G&A for the quarter was $8.4 million, down from $11.1 million in the prior quarter primarily due to compensation expense. For the full year of 2016, we expect G&A to be approximately $42 million to $44 million.

Depreciation and amortization for the quarter was $6.7 million, virtually unchanged sequentially, but down slightly year-over-year from $6.9 million due to reductions in our CapEx program starting last year. We would expect depreciation to continue on these approximate run rates and to be about $27 million for the full year.

The guidance we gave on our last call for this quarter specifically excluded the impact of any FX gains or losses and effective tax rate of 11%. Having said that, FX was immaterial for the third quarter and our effective tax rate was as projected.

So accordingly, our discussion today will be comparing GAAP, EBIT, net income, and EPS for the third quarter to the pro forma EBIT, net income and EPS for Q2, which excludes this foreign exchange loss and the lower-than-projected effective tax rate last quarter.

EBIT for the quarter on a GAAP basis was $21.5 million compared to the pro forma EBIT of $20.7 million reported last quarter. GAAP EBIT margins were 15% for the quarter, which is up nicely from the 13.7% last quarter.

Interest expense in the quarter was $2.6 million, down from $3 million in the second quarter as a result of using the proceeds from our equity offering last quarter to reduce your outstanding debt by almost 50%. Income tax expense in the quarter was $2 million and is at the projected effective tax rate of 11% we guided to on our last call.

We believe our effective tax rate for the fourth quarter will approximate 6%, which includes some fin 48 tax benefits that we anticipate will be realized in the fourth quarter. Our effective tax rate for the full year is expected to be approximately 11%.

Our estimates for Q4 and the full year excluding any unanticipated discrete items that maybe recognized in the fourth quarter. Net income for the quarter on an unadjusted GAAP basis was $16.7 million. So, up about 10% sequentially when compared to the $15.3 million ex-items for the second quarter of 2016.

As you may recall, last quarter the largest adjustment that we made to our second quarter pro forma net income was associated with the lower-than-projected effective tax rate of 4%. Our GAAP net income last quarter was $16.6 million. Earnings per share for this quarter were $0.38, up about 9% from the $0.35 reported last quarter ex-items.

As we move on to the balance sheet, I am only going to highlight the items that have materially changed from previously reported balances. Cash is $17.3 million, down from $22.5 million at prior year end. Receivables stand at a $108.5 million, down just $3 million from June 30.

Our DSOs remain strong, and were 64 days in the quarter, in line with prior quarter and a nice improvement from 66 days for all of 2015. We do not anticipate any increase in our DSOs for the remainder of the year as we continue to focus on all important aspects of running the business during this difficult environment.

Inventory at $37.3 million is down from the year end balance, and down approximately $2.5 million from June 30. We expect inventory levels to continue trending down during the fourth quarter as we close out 2016.

And now on to the liability side of the balance sheet, our long-term debts stands at $208 million as we used our excess free cash flow after payment of the dividend to further reduce our outstanding debt by $2 million this quarter.

Our outstanding debt is comprised of a $150 million in senior unsecured notes and $58 million drawn on our bank revolving credit facility. Shareholder's equity ended the quarter at a $162.8 million, and it's in line with prior quarter. Capital expenditures for the quarter were $2.4 million and comparable to our investments in the second quarter.

The company expects capital expenditures for the full year to be in the $12 million to $13 million range. However, if oilfields activities pick up, Core has the ability to increase its investments and support of these strengthening activities.

Looking at cash flow, cash flow from operating activities for the quarter was almost $35 million, and after paying for our $2.4 million in CapEx, our free cash flow was $32.4 million.

Our free cash flow continues to exceed net income as it has for 10 out of the last 14 years, and for the first nine months of 2016, total of $101 million, and represents 208% of net income. During the quarter, we used our excess cash to pay our dividends, buyback shares, and reduce our long-term debt.

Our focus on managing our business during those challenging environment continues to be maximizing our free cash flow and return on invested capital. Our free cash flow conversion ratio, which is free cash flow divided by revenue, continues to be one of the highest in the industry at 23% for the third quarter and year to-date.

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

Thank you, Chris. For the fourth quarter of 2016, we expect activity levels to increase in North America, but be offset by continuing weakness in international locations, especially South America and Asia Pacific regions.

Reservoir Description margins though are expected to remain at 20% even with the anticipated weakness in the international markets, while revenues and margins are expected to increase from North American-centric production enhancement operation.

As has been the case in past industry recoveries of worldwide operating activities, our companywide revenue growth and margin expansion is not immediately correlated to increasing rig counts, but to subsequent completion and stimulation events and large scale reservoir, rock and fluid characterization projects.

Therefore, a well or a number of wells need to be drilled and either be completed, stimulated, cored, or have reservoir fluid samples collected before we can realize a revenue event.

As has been the case for past industry activity recoveries we expect our revenue growth to ultimately outperform the increase in industry activity rates by 200 to 400 basis points.

We expect to generate incremental operating income margins of approximately 60% early in the activity recovery phase, followed by our historical incremental operating income margins of approximately 35% to 45% well into the recovery phase.

With international activity weaknesses being offset by North American activity increases, we project flattish fourth quarter revenue ranging from between $143 million to $145 million, an EPS to range between $0.38 and $0.40 with the quarterly effective tax rate of approximately 6% as Chris had mentioned, and that tax rate is expected to be lower than Q3 as result of some tax benefits that we anticipate will be realized during the fourth quarter.

Free cash flow is expected to exceed net income as has been the case for the last nine quarters. We also expect to continue to making opportunistic repurchases of our shares using our free cash flow in excess of our dividend payments. And with that review over, let's pass the conversation over to Monty to talk about our operational results..

Thank you, Dick. For the third quarter of 2016, Core owned revenue of $143.5 million, which yielded $21.5 million in operating earnings, and a 15% operating margin. Our employees around the globe continue to work with our clients to add value to their most important and challenging projects.

We thank all of our employees for staying focused on helping our clients utilizing Core Lab technologies. Reservoir Description revenue of $101.3 [ph] million produced operating income of $20.4 million with operating margins of 20.3%. During the third quarter, Core Lab worked with clients on a number of significant projects.

Core's team of scientists at the Aberdeen Advanced Technology Center continued their work on a multi-well project to characterize and evaluate the potential of what the client described as a World-Class Deepwater Asset Offshore West Africa. Datasets from Core Rock and Reservoir Fluid Laboratories are being used to define the reservoir's properties.

After completing the initial phases of analysis, Core's Reservoir Fluid Lab in Aberdeen is now performing advanced testing to further characterize the key chemical, compositional, physical, and flow-assurance properties of the reservoir fluids.

These analyses are being performed using state-of-the-art, high pressure, full visualization PVT cells, a Core Lab proprietary technology. Core's geoscientists utilizing proprietary techniques and state-of-the-art laboratory equipment including high-resolution digital imaging are describing and characterizing the geological attributes of the rock.

This enables the client to determine the variability of the rock and the storage capacity of the hydrocarbon-bearing formations. Occidental has deployed Core Labs' advanced petrophysical analysis technologies in conventional reservoirs recognizing and capturing additional reserves in its EOR fields to significantly lower incremental costs.

In addition, Occi's unconventional reservoir development teams have employed Core's proprietary core-based residual water and high frequency NMR saturation models to fine-tune reserves and identify pay intervals that improve Occi's profitability.

Core Lab scientists working with the clients develop the methods and proprietary instrumentation for analyzing various EOR methods for unconventional reservoirs.

Core Lab scientists are continuing to work on many important projects including Apache's High Alpine Discovery, ExxonMobil's Liza field offshore Guyana, and a newly discovered reservoir, north of the Arctic Circle in Alaska. The production enhancement revenue of $37.6 million in Q3 as North America well completions were down from Q2 2016 levels.

Core Lab has recently adapted our diagnostic services, SPECTRASTIM and SPECTRASCAN, to provide a superior method to evaluate the effectiveness of semen [ph] isolation in offshore completions. At a recent symposium, one operator estimated cost savings using these core technologies at 1.25 million per well.

In the third quarter, another offshore operator used these diagnostics and found a way to lower well costs by an additional $1 million and eliminate the risk of a well intervention. They plan to incorporate these diagnostics into their future well completion programs. The use of Core Lab technologies is adding value for our clients.

Core Lab has also been involved in both the STACK B and SCOOP Basins in Oklahoma with multiple clients using our SPECTRASTIM tracers and SPECTRASCAN logging to evaluate the effectiveness of alternate completion systems, and of diverters in horizontal well completion designs.

Flow profiler technology is being used to assess zonal containment and oil contributions stage-by-stage. An international major oil company recently recommended Core Lab's pack perforating system for well abandonment projects in their internal newsletter. This technology adds value for our clients by saving them time and money on abandonment.

Reservoir management revenue of 5.7 million resulted in a small operating loss, primarily due to the discretionary nature of client's participation in Core Lab studies.

Reservoir management continues to work with our clients to enhance reservoir performance and identify the pays and areas that will bring the best return on investment at current commodity prices. In Q3, eight companies joined our Permian Basin studies.

Two joined our Powder River Basin studies, and one each for the Eagle Ford, Cotton Valley, Haynesville, and Missourian Tight Oil studies. Internationally, one client joined our West Africa Gabon Congo study.

In addition to the Permian Basin of West Texas, more recently the STACK B area of Oklahoma has emerged as another area that shows a very favorable economics in current market conditions.

Recent reporting from operators show the STACK B has the advantage of multiple pay zones, providing numerous targets in a mature low cost infrastructure-rich producing region. On average, the STACK B area delivers initial production rates, and irreducible eventual recovery; sorry, that are on par with the Permian.

Historically, most of the unconventional drilling in the STACK B is focused on the Silurian-aged Woodford Shale. Reservoir management has an ongoing project evaluating the Woodford. More recently, however, the overlying Mississippian-age Meramec and Osage formations have become the targets of choice.

Since the Meramec and Osage are not source rocks, the underlying Woodford is most likely the source of hydrocarbons that have migrated into these zones. Reservoir management has recently proposed a study of these two zones to focus on the key features and ultimate extent of the play. Rocco, we will now open the call for questions..

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Today's first question comes from Rob MacKenzie of Iberia Capital. Please go ahead..

Thank you. Guys, I wanted to explore how you think the Reservoir Description segment is likely to recover last year particularly in the context of what remains a pretty bearish outlook for offshore drilling activity, recognizing that the segment is in many ways largely related to production, not drilling, but it seems to have suffered nonetheless.

What get's Reservoir Description going again?.

Well, just increased work on fluids-related projects, Rob. That is continuing to actually grow in the amount of revenue it generates per quarter, and we're getting relatively less analysis of rocks. So when we look all over at Reservoir Description, it is going to become more weighted to the fluid side.

And the more we know about the phase behavior relationships of the fluids both offshore and onshore, offshore deepwater, shallow water, and then in onshore, the better that we can increase ultimate recovery rates.

So as we don't see a lot of upturn in deepwater drilling in the fourth quarter, we believe that there will be several FIDs related to deepwater projects occurring early in 2017.

So, along with the increase in the amount of fluids work that we're doing, once we start throwing in some additional rock projects from some of the deepwater, we think that's what gets it going again..

Okay, thanks. And then a question on Production Enhancement, I know you guys have talked about the PAC [ph] charge as well as the applicability of the HERO line of charges in carbonate reservoirs.

What is the market share, and how big is the market share opportunity to gain greater traction with the perforating business outside of North America, and when do you think we could start seeing some of that materially flow through?.

Monty, I'll turn that to you..

Okay. On market share in the perforating we have a significant share; we are the largest of the independent providers of perforating products. The handicap on this is there are internal providers, particularly at the major wireline companies, that we do not have any information to determine how much they are producing for their own internal use.

We, on the other hand, are selling these products, particularly our higher technology products to all of those wireline companies for use in their operations. So Rob, I can't give you specific market share numbers.

We know we are the largest provider of the independent, meaning not part of a wireline company, but we do not know what their production is..

Rob, there is a stale dated survey, and I don't think it's changed much that the industry agreed to work on together where all companies, including those non-independents that Monty was referring to, they did supply data.

And it showed that Core Lab was tied as the largest of all internationally, globally, and in North America it showed that we were the largest, including all of those large ones. And that's about five years old was the last time we did a survey.

We don't think it's changed materially other than our picking up market share because the introduction of so much of this new technology..

Got it. Okay, that really helps, Dick, thank you. I'll turn it back now..

And our next question comes from Sean Meakim of J.P. Morgan. Please go ahead..

Hi, good morning..

Good morning, Sean..

So as we think about a recovery in activity next year in North America, just trying to think about production enhancement mix, customer mix, geographic mix, project mix, thinking about how those factors could influence your opportunity to expand margins and hit those incremental that you're targeting?.

Yes, Sean, I think a good review would be to go back to '08 through '12. We think that we will closely follow that model because it should step out right along the same lines. We do like that business better because we have reduced costs due to some increased automation. And also we have a wider array of products to offer and services to offer.

So it gives us great comfort in seeing that the incremental margins for that group could be higher than the average of 60% that we said for the whole company. And if we go back and look at quarters, in '10, '11, and '12 you'll see that to be true.

So I would kind of model if we are on the pace for that type of recovery, I would use that as the model for revenue growth, margin expansion, and incrementals..

Okay, thank you for that. And then thinking about the missable gas EOR opportunity, it sounds like you're starting to get more traction outside the Eagle Ford, more talk around the Permian.

Just hoping to get an update on how customers are viewing that opportunity in the context of reloading capital budgets next year, and what's driving the uptick there, and how that opportunity set looks for you?.

Yes, I think we've got a number of our more technologically sophisticated client, Sean, that are looking at this. The prime driver is the increase, their return on invested capital.

If you can take recovery rates that right now average in shales of about 9%, and increase that into the low to mid-teens you have a remarkable response to the return on invested capital. So that is their prime focus.

Moreover, if you can spend an additional two or three million dollars for a set of wells, so not an individual well, but let's say a couple of stacked pads that are together, you get a little bit bigger bang for the buck out of these EOR missable flood-related projects.

So I think we're in very early innings here, but again it's being driven by our clients looking to increase their returns on invested capital..

Got it. Okay, great. Thank you..

All right, Sean..

And our next question comes from James West of Evercore ISI. Please go ahead. .

Hi, good morning guys..

Good morning, James..

Dave, I appreciate -- I have listened to your macro views on the oil markets, and I consider you one of the experts on supply.

I thought just you and kind of other people I think are very good on supply as well, and it seems to me that the major forecast agencies are way off on 2017 international and non-OPEC supply with folks have a slight issue up, and I think we'll see big declines.

Do you ascribe to that view that there will be modest declines, and do have some of the range in mind of how big the declines will be?.

Yes, James, we have U.S. supply down once again next year. We have international supply outside of OPEC down next year. And if you include, if indeed OPEC does cut, we have them down. So right now we don't have a solid number for that, but we would put outside-of-U.S.

declines probably somewhere on -- somewhere between, let's say right now, 1.5 million and 1 million barrels. So it's going to be somewhere in that range, and I know all the large agencies and some of the think tanks do have production flat to up almost that amount. We just can't see that happening..

Right. Okay, I absolutely agree with that. Thanks for that. And then on….

Yes, and one of the driving forces, running out of some of these deepwater legacy projects that are coming on. And we've added some production globally from deepwater. But you remember we started shutting off investment in deepwater in around 2013. So here, as we're going in to 2017, a lot of these legacy projects are already coming on.

And one of the areas that the chief example of that would be if we looked at Angola, which is a strong deepwater producer, but we certainly have production in Angola down next year due to the lack of legacy projects that are indeed timed to come on. So essentially they've exhausted that backlog on that..

Right, of course, and in North America, Dave I know that the rig counts are up, completions are delayed as we drill wells, have you started to -- now that we're well into October at this point have you started to see the fourth quarter at the natural kind of pick up in completions activity?.

Yes, we do predict that production activities will pickup in the fourth quarter. We're seeing that manifested in some enquiries and activity rates for our Production Enhancement group. And we expect their revenues to be up in Q4, followed with higher margins and incremental margins.

But just keep in the mind the example that we gave, James, in the Bakken, where, since December, we've had added 1,770 producing wells to a base of about 9,000 wells that existed in December of 2014. So we've added 20% more wells to the productive base. And during that time we've lost 233,000 barrels of production.

And each individual well producing in the Bakken, which now number about 10,700, the productivity is down 26%. So to turn that decline out of these tight reservoirs is going to take Herculean effort. We just don't see that happening in 2017, and hence we see production down in the U.S. once again..

Okay, great. And then let me maybe squeeze one last more question here. The cost savings that you're seeing through automation, and I believe a lot of that is robotics technology.

How far along do you think you are on installing this automation equipment, and how much more room do you have to go?.

James, this is Monty. I would say we're on the starting edge of that. We've done a lot. We've developed instrumentation. But as you've noticed, our capital we have kept pretty constrained in the downturn on purpose. And we will be -- have a lot of room to expand on our automation in the coming years as the market picks up..

Okay, got it. Thanks Monty and thanks Dave..

Okay, James..

And our next question today comes from Marc Bianchi of Cowen. Please go ahead..

Thank you. Good morning guys..

Morning, Marc..

Good morning. Just a follow-up on James' question on the production, I appreciate that maybe on the full-year basis for '17 it'll be down. When would you expect, based on where the rig count is now actual daily production to start to improve.

So if we look at it on a per-day is it sometime by year-end, is it sometime in the middle of next year? Curious for your thoughts on the trajectory there..

Yes, Marc, we actually -- at the current rig count rates we actually don't see a change in the trajectory of downward U.S. production. I would say at current levels, probably into second half of next year, maybe fourth quarter..

Okay.

And if it were to get an increase by year-end or first quarter, try to understand the sensitivity, what sort of rig count increase would you expect we need to see from current levels?.

We are -- for us to see a significant change in U.S. production we would need to have about 900 rigs drilling for oil for a 12 to 18-month period. And that would get us on a trajectory where we could have strong additions to production..

And what sort of barrels per day would you say that 900 equates to?.

You've got to tell me where those 900 rigs are. So it depends on where they're put. But essentially if we're losing a million barrels a day let's say net in the U.S. we're going to have to overcome that. So those 900 rigs for 12 to 18 months could probably do that. Our analysis isn't that sensitive to that time period..

Okay. Well, thanks for the macro comments. Just one modeling, as I think about the tax rate for the fourth quarter, you mentioned that you've got the FIN 48 benefit.

What would be excluding that benefit a more normalized tax rate to think about maybe as we start thinking about the beginning of 2017?.

Hi, Marc, this is Chris Hill. It does depend. It's obviously a mix of all the different countries and their various statutory rates. But as you see activities pick up in the U.S., that's one of the highest tax jurisdictions we're in.

But I think maybe a more normalized tax rate for this year excluding some of the discrete items we had is probably more in the 14% range, something like that. As you may recall, we did have a large settlement earlier this year with the U.S., and which was a positive for us.

And that made our tax rate go down in the second quarter, but probably 14% if you were to use today, and go forward..

Very good, that's helpful….

We haven't given guidance on a tax rate for next year..

Completely understand. Great, that's very helpful, gentlemen. I'll turn it back..

Okay, Marc..

And our next question comes from Thijs Berkelder of ABN-AMRO. Please go ahead..

Yes, thank you. Hello guys. I have some specific questions. I think, Chris, you said to expect G&A expense for the full year to amount between $24 million and $44 million. Does it mean that the stock options or the stock-related compensations return as always in Q4, and maybe even in a bigger amount than in previous quarters.

And secondly, related to that, I think in Q3 these expenses were down some $2.5 million, maybe $3 million versus previous quarter.

Why is that exactly happening?.

Yes. We do expect Q4 to return to maybe more of a normal quarterly run rate. We are evaluating compensation. It's driven by compensation. So it may be up. It's not necessarily related to the employee share awards, but there are other forms of compensation, bonuses, profit sharing arrangements that have to be evaluated depending on how the year comes out.

So that's the way I would characterize that. And if we do better than expected in Q4 then we may be able to adjust those. So that is a range at our best guess as of today..

Okay. But let's say the delta in Q3 was in the P&L 2.7 million.

Was that primarily in the Reservoir Description space or maybe can you give a split between Reservoir Description and Production Enhancement there of that delta?.

Well, when you think of G&A I would primarily think of the corporate supporting group, so it's really the whole company. But it's not -- I don't have the detail to split that out by segment, but think of the G&A as the corporate group..

That's assuming -- let's assume that it's $2 million in Reservoir Description then -- yes, then the margin, let's say, underlying has not improved quarter-over-quarter, but that's let's say my calculation of course. Maybe a follow-up question, I think you also guide us for CapEx between $12 million and $13 million for the full year.

Does that mean $5 million in the fourth quarter, and then where will that be spendable?.

That's probably better answered by Monty..

Yes, our CapEx will be pretty much on the same pace it has been. We have one major purchase that we are anticipating will happen in the fourth quarter, and that is the land for a new facility in Indonesia that we are moving to bringing all our operations into one facility. And like I said, we're anticipating that in the fourth quarter.

It is possible that it happens in the first quarter..

Okay, clear. Follow-on question on the weakness of the British Pound, and looking at your Edinburgh facility, can you remind me those Western African contracts you are doing in Edinburgh, are they billed in dollars on the cost pricing pounds, or -- [technical difficulty]….

Yes, remember, our advanced technology center is in Aberdeen, and that is for a European client. So, those are either billed in Euros or in Pounds..

Okay, clear. And then, may be finally a question on your V-shaped recovery expectation, I am just reading a comment from Exxon CEO, Mr. Tillerson, and he is more or less exactly saying the opposite as Core Lab.

And I think you work together on West African project, or not? And he is especially pointing at this great improvement in technology allowing companies to burn more oil and thus preventing the oil price to blow out in the future?.

Well, that's what makes the market. ExxonMobil is a great client of ours. We work with them around the world. We've got great respect for Mr. Tillerson, and he is entitled of his opinion, and we're just giving you what we think on the science-based analysis of production decline curves worldwide tell us..

One thing I would like to be real clear on that, West African project that we mentioned, we did not name the client and it is not Exxon. So I don't want people to relate those two and think it's one..

Yes, it's the Guyana project off shores….

Exactly..

…Liza prospect that we referred to ExxonMobil on..

Oh, yes, yes, okay. Yes, that was misunderstanding. Correct.

The final question maybe, oil production enhancements, can you maybe give October 1st to September, oil price up, what do you see now?.

We don't break down these..

Or months?.

Yes, we don't break down and give that granularity..

The trends have been up, which is the basis for our guidance to suggest rather than production enhancement being down in Q3, we see it being up in Q4 because of some of the trends we are seeing..

Okay, thanks very much..

Hey, very good..

And our next question comes from Stephen Gengaro of Loop Capital. Please go ahead..

Thanks. Good morning, gentlemen..

Good morning, Stephen..

I just wanted to follow-up again on the production enhancement side. It ties into a response you gave earlier. When you look at, and one of the things that came out of conference call yesterday was Halliburton saying they believe their market shares are about as high as they had ever been in the U.S.

And I was just curious if the oil service company, who is in charge of all these frac jobs has a big impact on you? And doesn't matter if it's Hall versus a lot of these smaller players, and can that impact your market penetration at all in your view?.

Yes, Stephen, we are agnostic. We work for more..

Okay, great.

And then, secondly, when you think about -- and I know you are not going quantify it specifically, but when you think about the production enhancement pricing dynamics, can you give us a sense for kind of where they were at the peak versus now and how much of that is kind of related to the margin changes versus just utilization and overhead?.

Yes, the majority of it's related to just the capacity that we have to provide services in the marketplace and the absorption on our manufacturing. So, we have tried to reduce cost there. We've not seen any significant price alteration. Since peak we certainly have seen some, but we are trying to extend terms with those clients to work through that.

So, it's more related to the capacity that we have to deliver and the absorption of that.

And we've reduced cost about as low as we want to in keeping with our -- we are seeing rebound in the activity levels and just didn't want to cut any more of that productive capacity away either from field service aspect or a manufacturing or perforating guns and perforating charge systems..

Great, thank you..

Okay, Stephen..

And our next question comes from Tom Dillon of William Blair. Please go ahead..

Following up on that question, going back to the incremental for a minute, do you still believe the fluids offering will provide margins above the 2014 levels given the recurring nature of fluid business, or the E&P is focused on in driving lower well costs or shadowing that upside?.

No, we will have higher revenues from the reservoir fluid side in 2017 at higher margins..

Okay. And then, any shift in conversations with the North American E&Ps for those types projects? Or I guess put another way, as oil prices start to stabilize is the average E&P starting the conversation about EOR? Or is the cost still the main focus for the North American E&P? Thanks..

No, we've approached -- of the six projects we have been in-house, primarily we have been approached by clients some of which have prescribed us what they want to see in the flood fields for the gases and fluids for the injection.

And the other half have come to us and said, "Okay, what can you prescribe, or what cocktail do you think would work best for a missable flood given our reservoir and our reservoir fluids?" So, it's a combination really of both..

Okay, I appreciate color..

Okay, very good..

And our next question today comes from Gregory Lewis of Credit Suisse. Please go ahead..

Yes, thank you and good morning..

Good morning, Greg..

I guess this question is either for David or maybe Monty.

And just realizing the completions in Q3 under delivered, but I guess my really is as we look at the work that was done in production enhancement, is there any sense to sort of gauge whether you want to think about whether you look at it on a revenue basis or however else you want to quantify it, and how that's trended sequentially? I am just trying to understand as we have seen longer laterals, are we seeing a noticeable increase in the amount of revenue that Core is making on a per job basis?.

Yes, absolutely. As we see longer laterals, more stages, closer clusters, all of that works for greater intensity for Core Lab revenue. And of course, we started that mantra three years ago. We think it still is the key to success.

When we look at laterals for instance in the Permian Basin, on average, a lateral somewhere around 5,000 feet going to over the next year at the 7,000 or 8,000 feet. We ultimately see those laterals in some of the core features of the Permian Basin and several of the layer cake [ph] plays there, extending out beyond 10,000 to 12,000 feet.

And you already have some technologically sophisticated clients that are actually doing that..

Is there any way to sort of gauge on a revenue per job basis, how that's trended? I mean is it mid-single digits, low-double digits, is there any sort of way to quantify that or is it just we know that something has happened or it's just going to show up in the numbers?.

Yes, it'll just show up in the numbers because depending on the reservoir, the client, the depth, the pressure, the fluid, there is just too many variables in that equation to come up with a one-rule-fits-all..

Okay, guys….

Which is very good general trend..

Okay, thank you very much..

Okay, Greg..

[Operator Instructions] Our next question comes from Stacy Mulvehill of Wolfe Research. Please go ahead..

Hey, I guess, I will change my name..

That's his long lost sister..

Yes, yes. So, I guess question on production enhancement and maybe I missed it, I have been kind of in and out going on the call.

But did you give any outlook specifically for production enhancement in the fourth quarter relative to revenue?.

What we just said was, Chase, qualitatively we see it and that's based on recent trends. So the trends because of those completions being down in Q3, began to reverse as we entered into Q4, and that was the basis for the guidance that qualitatively we expected to be slightly high..

Okay.

All right, so slightly higher and that probably implies that Reservoir Description is down, is a kind of low single-digits pretty good for Reservoir Description as we are looking 4Q?.

Yes, low, low single digits..

Okay, awesome. Thank you..

Good day. Sorry, go ahead. Go ahead..

So, back on production enhancement, you know if we think about the mix between North America and international, I think some of what's kind of playing into this when we think about the reported revenue numbers of production enhancement is probably that international accounts for a larger percentage of revenues now.

So, maybe you can help us understand the mix between North America and International and production enhancement, and then in 3Q if North America was up or down and by how much?.

Yes, traditionally for production enhancement two-thirds is U.S-related, one-third international. That's probably a shift in just because of a loss of revenue to 60% U.S., 40% International.

And international may have gained a bit on the penetration side, whereas just a sheer number of wells that are not being drilled in North America have led to the amount of fall in revenue to 60%, the 60% level North America..

Okay, awesome. Last one and I'll turn it back over, get in 9:30. If we think about fracture half links and you know how kind of things have changed from '14 to kind of today, that half links is probably not as deep as it used to be on the fractures that we were doing in '14.

And so, how does this impact your business? I know that back in '14 you talked about walking away from the basic technology products and the production heads of business, so how does this evolve -- how has this evolved over the past couple of years? Has this impacted the higher tech business positively or negatively?.

It has positively affected our higher tech as we have offered new products. We would have thought by now all of our lower technology, basic technology products would have been out of the system, but just due to increased absorption that they do provide to us, we've kept them in the product line.

We are hoping during this next cycle that we can remove those from the product offering..

Okay.

In '14, they were less than 20% of production enhancement revenues, you know, you said you wanted to get the below 10%, are we below 10% yet?.

No, not yet. There's cost concerns for many of the operators so lower tech lower cost, and while we say all the value of the higher tech as generating values, some people are focused on cost..

Yes, understood. All righty, I'll turn it back over. Thanks, I appreciate it..

Rocco, we'll take one more question..

Absolutely. And our final question comes from Kurt Hallead of RBC. Please go ahead..

Hey, good morning. This is Ben filling in for Kurt. Just one question from me, could you just talk about the pricing environment it seems from your services both in the U.S.

and internationally?.

Good morning, Ben. From a pricing standpoint, from Q2 to Q3 and the Q4, really little effect. What's having more effect on us is just the lack of activity levels through that period, so on pricing, not a big delta..

Great, thanks..

Okay, Ben, very good. So Rocco, we're going to close it up.

So in summary, Core's operations continue to be position the company for an uptick in activity levels in Q4, and we know that significant challenges await, however, we've never been better operationally or technologically positioned to help our clients maintain and expand their existing production base.

We remain uniquely focused, and are the most technologically advanced Reservoir Optimization company in the oilfield services sector. This positions Core well for the challenges ahead.

The company remains committed to industry-leading levels of free cash generation, returns on invested capital, with all excess capital being returned to our shareholders via dividends and future opportunistic share repurchases. So, in closing, we would like to thank all of our shareholders and the analysts that follow Core.

And as already noted by Monty Davis, the Executive Management Board of Core gives special thanks to our world-wise employee base 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..

And thank you, sir. Today's conference has now concluded. We thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day..