Core Laboratories Inc (CLB) 2016 Q3 法說會逐字稿

Welcome to the Core Laboratories third-quarter 2016 earnings conference call.

(Operator Instructions)

Please also note today's event is being recorded. I would now like to turn the conference over to David Demshur, Chairman, President and CEO. Mr. Demshur, please go ahead.

Thanks Rocco.

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 will present the detailed operational review; Chris Hill, Core's Chief Accounting Officer; and Gwen Schreffler, Core's Head of Investor Relations.

The call will be divided into five segments. Gwen will start by making remarks regarding forward-looking statements. Then we will come back and give a review of the current macro environment updating US 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 billing 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 in major projects worldwide. Then we will open the phones for the Q&A session.

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

Before we start the conference this morning I'll mention that some of the statements that we make during this call may include projections, estimates another forward-looking information. This would include any discussion of the Company's business outlook. These types of forward-looking statements are subject to a number of risks and uncertainties relating to the oil and gas industry, business conditions, international markets, international political climate and other factors, including those discussed in our 34 Act filings that may affect our outcome. Should one or more of these risks and uncertainties materialize or should any of our assumptions prove incorrect, actual results may vary in material aspects 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, 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 website.

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, US 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 US 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 US land production going into 2017. Remember, decline curves are linear in time but logarithmic in scale and production decline.

An excellent example that the decline curve always wins and never sleeps and the difficulty in reversing fallen production totals in tight oil reservoirs is the Bakken 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 per 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 existing Gulf of Mexico production base. These legacy deepwater Gulf of Mexico projects may add a net 100,000 barrels a day to US 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 US 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 decline in production on a global basis through the third quarter of 2016.

Therefore, Core believes crude oil markets will more than rationalize in late 2016 as 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 increase worldwide demand in 2016 of approximately 1.3 million barrels per day. Currently the US is using approximately 10 million barrels a day of gasoline near record levels.

Recent Chinese imports, coupled with strong growth in India, are 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 financial tenants by which Core used 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 into 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 investment capital for the 29th consecutive quarter topping an ROC of 22%. Producing in industry-leading return on investment capital has not happened by chance. A real-time concern for investors is the exposure to the Venezuelan market.

Core Vexited in 2013, a decision at which time was highly questioned by our analysts, shareholders and potential shareholders. Doing the Vexit 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 risks clearly outweighed long-term value for the Venezuelan market. With hundreds of millions of past write-downs and with over $1 billion 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 via 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 will 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 comes from outside the US where activities held up reasonably well. North American completions, however, actually fell in the third quarter even as rig count began to 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 $114 million for the quarter, down only 3.4% sequentially as most regions were study 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 the 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 revenues, 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 oil field 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 the 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 our 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 exclude any unanticipated discrete items that may be recognized in the fourth quarter.

Net income for the quarter on an and adjusted GAAP basis was $16.7 million, so up about 10% sequentially when compared to the $15.3 million X 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 was $0.38, up about 9% from the $0.35 reported last quarter ex items. As we move on to the balance sheet, I'm only going to highlight that 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 $108.5 million, down just $3 million from June 30.

Our DSOs remain strong and we're 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 onto the liability side of the balance sheet, our long-term debt 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 $150 million in senior unsecured notes and $58 million drawn on our bank revolving credit facility. Shareholders equity into the quarter at $162.8 million and is in line with prior quarter.

Capital expenditures for the quarter were $2.4 million in 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 oil field activities pick up Core has the ability to increase its investments in support of the 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 of the last 14 years and for the first nine months of 2016 total $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 the business during this challenging environment continues to be on maximizing 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 companies financial results, particularly 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.

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 for 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 outperformed 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 and EPS to range between $0.38 and $0.40 with a quarterly effective tax rate of approximately 6%, as Chris had mentioned, and that tax rate is expected to be lower than Q3 as a result of some tax benefits that we anticipate will be realized during 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 making opportunistic repurchases of our shares using our free cash flow in excess of our dividend payment.

Now with that review overlook, let's pass the conversation over to Monty to talk about our operational results.

Thank you, Dick.

For the third quarter of 2016 Core earned 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 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 to work on a multi-well project to characterize and evaluate the potential of what the client described as a world-class deep water asset off shore 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 PBT cells -- a Core Lab proprietary technology. Core geoscientists utilizing proprietary techniques and state-of-the-art 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 ER -- 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 improved Occi's profitability. Core Lab scientists working with the clients developed the methods and proprietary instrumentation for analyzing various EOR methods for unconventional reservoirs.

Core Lab scientists are continuing work on many important projects including Apaches high alpine discovery, Exxon Mobil'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 cement 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 an 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. FLOWPROFILER technology is being used to assess zonal containment and oil contribution stage by stage.

An international major oil company recently recommended Core Lab's ACT perforating system for well abandonment projects in their internal newsletter. This technology adds value for our clients by saving them time and money on abandonments.

Reservoir management revenue of $5.7 million resulted in a small operating loss primarily due to the discretionary nature of clients participation in Core Lab studies. Reservoir management continues to work with our clients to enhance reservoir performance and identify the pays in 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, Hainesville and Missourian tight oil studies. Internationally, one client joined our West Africa Gabon/Congo study.

In addition to the Permian Basin in West Texas, more recently the STACK-B area of Oklahoma has emerged as another area that shows a very favorable economic incurrent 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 eventual recovery that are on par with the Permian. Historically, most of the unconventional drilling in this STACK-B is focused on the Silurian age Woodford Shale. Reservoir management has an ongoing project evaluating the Woodford.

More recently, however, the overlying Mississippian age Meramac and Osage formations have become the targets of choice. Since the Meramac 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 up for questions.

(Operator Instructions)

Rob MacKenzie of Iberia Capital.

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 gets 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 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 FID's 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 charge as well as the applicability of the HERO line of charges and 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're the largest of the independent providers of perforating products. The handicap on this is there are internal providers, particularly at the major wire line 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 wire line companies for use in their operations. So, Rob, I can't give you specific market share numbers. We know we're the largest provider of the independent, meaning not part of a wire line company, but we do not know what their production is.

Rob, there is this 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's 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. That's about five years old was the last time we did a survey. We don't think it's changed materially other than perhaps 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.

Sean Meakim with JPMorgan.

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 incrementals that you are targeting.

Yes, Sean, I think a good review would be to go back to 2008 through 2012. 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 cost 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 set for the whole Company. And if you go back and look at quarters in 2010, 2011 and 2012 you will 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 miscible 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 clients, Sean, that are looking at this. The prime driver is to 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 $2 million or $3 million 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 miscible flood related projects. So I think we are 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.

James West of Evercore ISI.

Good morning, guys.

Good morning, James.

Dave, I appreciate all of this macro views on the oil markets and I consider you one of the experts on supply. I've talked to a few other people I think that are very good and supply as well and it seems to me that the major forecast agencies are way off on 2017 international and non-OPEC supply. Most have it flatish to up. And I think we will see big declines. Do you ascribe to that view that there will be large declines and do you have some of the range in mind of how big the declines will be?

Yes, James. We have US 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 US declines probably somewhere between let's say right now 0.5 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 -- .

And one of the driving forces is we are running out of some of these deep water legacy projects that are coming on. And we've added some production globally from deep water. But you remember, we started shutting off investment in deep water in around 2013. So here we're going into 2017, a lot of these legacy projects are already coming on. And one of the areas that's a 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, David, I know that the rig count's 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 the natural pickup in completions activity?

Yes, we do predict that production activities will pick up in the fourth quarter. We are seeing that manifested in some inquiries in 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 mind the example that we gave, James, in the Bakken where since December we've 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 a Herculean effort. We just don't see that happening in 2017 and hence we see production down in the US once again.

Right. Okay great. If I could squeeze one last Core question in here. The costs 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? How much more room do you have to go?

James, this is Monty. I would say we are on the starting edge of that. We've done a lot. We've developed instrumentation but as you 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. Thanks, Dave.

Okay, James.

Marc Bianchi of Cowen.

Thank you. Good morning, guys.

Good morning, Marc.

Good morning. Just a follow-up on James' question on the production. Appreciate that maybe on the full year basis for 2017 it will 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 some time by year end? Is it some time 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 US 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 US 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 addictions 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 are put. But essentially, if we are losing 1 million barrels a day, let's say net in the US, we are 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. 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 US, that's one of the highest tax jurisdictions we are 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 US 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.

But 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, Mark.

Thijs Berkelder of ABN AMRO.

Thank you. Hello, guys. I had 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 that mean that the stock options or the stock related conversations 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 the expense were down some $2.5 million maybe $3 million for 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 unless they did Delta in Q3 was in the P&L $2.7 million, was that primarily in the reservoir description space? Or maybe can you give us split between reservoir description and production [enhancement there of the 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.

Let's say assuming -- let's assume that it's $2 million in reservoir description then the margin underlying has not improved quarter over quarter. But my calculation, of course. Maybe a follow-up question, I think you also guided for CapEx between $12 million and $13 million for the full-year. Does that mean $5 million in the fourth quarter? And where will that be spendable?

That's probably better answered by Monty.

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 are 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 West [and] African contracts you are doing in Edinburgh, are they built in dollars on a cost pricing pounds or is it pound for pound?

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 maybe finally a question on your (inaudible) recovery expectation. I'm just reading a comment from Exxon CEO, Mr. Tillerson, and he's more or less actually saying the opposite as Core Lab. And I think you work together on the West African project or not. And he's especially pointing at this great improvement in technology allowing companies to [put] more oil and this preventing the oil price to blowout in the future.

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

One thing I'd 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.

It's the Guyana project offshore deepwater and the Liza prospect that we referred to Exxon Mobil on.

Yes okay. That was a misunderstanding, correct. Final question maybe on production enhancements, can you maybe give October versus September oil price up? What do you see now?

We don't break down and give that granularity.

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

Okay. Thank you very much.

Very good.

Stephen Gengaro of Loop Capital.

Thanks. Good morning, gentlemen.

Good morning, Stephen.

I just wanted to follow up again on the production enhancements side and it ties into a response you gave earlier. When you look at -- and one of the things that came out of the conference call yesterday was Halliburton saying they believe their market share is about as high as it's ever been in the US. And I was just curious if the oil service company who is in charge of a lot of these frac jobs has a big impact on you? And does it matter if it's Halliburton versus a lot of these smaller player and can that impact your market penetration at all, in your view?

Yes, Stephen, we are agnostic. We work for them all.

Okay, great. And then secondly when you think about -- and I know you're not going to 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 related to the margin changes versus just utilization and overhead?

Yes, the majority of its related to just the capacity that we have to provide services to the marketplace and the absorption on our manufacturing. So we've tried to reduce costs there. We've not seen any significant price alterations since the 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 we our -- we're seeing a rebound in the activity levels and just didn't want to cut anymore of that productive capacity away either from a field service aspect or a manufacturing of perforating guns and perforating charge systems.

Great. Thank you.

Okay, Stephen.

Tom Dillon of William Blair.

Following up on that question, going back to the incrementals for a minute, do you still believe the fluids offering will provide margins above the 2014 levels given the recurring nature of the fluids business? Or are the E&P focused on driving lower well costs over shattering that upside?

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

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

No, we've been approached -- the six projects we've been [in house] primarily we've been approached by clients, some of which have prescribed to 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 prescribed or what cocktail do you think would work best for admissible flood given our reservoir and our reservoir fluids. So it's a combination really of both.

Okay. Appreciate the color.

Okay, very good.

Gregory Lewis of Credit Suisse.

Yes, thank you and good morning.

Good morning, Greg.

I guess this question is either for Dave or maybe Monty. Realizing that completions in Q3 under delivered -- but I guess my question 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 how that's trended sequentially? And I'm 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 plays their 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 it's something that's happening and works -- it's just going to show up in the numbers?

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

Okay, guys.

It's a very good general trend.

Thank you very much.

Okay, Greg.

(Operator Instructions)

[Stacy] Mulvehill of Wolfe Research.

Hi, I guess I changed my name. (laughter)

That's that long-lost sister.

Yes. So I guess question on production enhancement, and maybe I missed this, I've 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 revenues?

What we just said was, Chase, qualitatively we see it up 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 higher.

Okay. 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 look at 4Q?

Yes, low, low single-digits.

Okay, awesome. Thank you. Sorry. Go ahead

Go ahead.

So back on production enhancement -- and if we think about the mix between North America and international I think some of what is kind of playing into this when we think about the reported revenue numbers of production enhancement is probably that international accounts for larger percentage of revenues now. So maybe you can help us understand the mix between North America and international in production enhancement and then in Q3 if North America was up or down and by how much.

Yes, traditionally for production enhancement two-thirds is US related, one-third international. That probably has shifted just because of a loss of revenue to 60% US, 40% international. And international may have gained a bit on the penetration side where as just the sheer number of wells that are not being drilled in North America have led to the amount of fall in revenue to 60% level in North America.

Okay, awesome. Last one and I'll turn it back over because I know we're getting to 9:30. If we think about fracture half links and how things have changed from 2014 to today, the half-length is probably not as deep as it used to be on the fractures that we were doing in 2014. And so how does this impact your business? I know that back in 2014 you talked about walking away from the basic technology products in the production enhancement business. So how does this evolve? How has it evolved over the past couple 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've thought by now all of our lower technology, basic technology products would've 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 2014 they were less than 20% of production enhancement revenues. You said you wanted to get it to 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 sell the value of the higher tech as generating values, some people are focused on cost.

Yes. Understood. Alright, I will turn it back over. Appreciate it.

Rocco, we will take one more question.

Absolutely. Our final question comes from Kurt Hallead of RBC.

Good morning. This is Ben filling in for Kurt. Just one question from me. Can you guys talk about the pricing environment you're seeing from some of your services both in the US and internationally?

Good morning, Ben. From a pricing standpoint from Q2 to Q3 into 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. Rocco, we are going to close it out. So in summary, Core's operations continue to be positioned -- 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 oil field 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'd 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 worldwide employee base that have made these results possible. We are proud to be associated with their continuing achievements. So thanks for spending your money with us -- morning with us and we look forward to our next update. Goodbye for now.

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