Core Laboratories Inc (CLB) 2015 Q3 法說會逐字稿

Good morning and welcome to the Core Laboratories third quarter 2015 earnings conference call.

(Operator instructions)

Please note, this event is being recorded. I would now like to turn the conference over to David Demshur, Chairman, President and CEO. Please go ahead.

Thank you Andrew. Good morning in North America. Good afternoon in Europe, and good evening in Asia-Pacific. We would like to welcome all of our shareholders, analysts and, most importantly, our employees to Core Laboratories' third quarter 2015 earnings conference call. This morning I'm joined by Dick Bergmark, Core's Executive Vice President and CFO; Core's COO, Monty Davis who will present the detailed operational review; and Chris Hill, Core's Chief Accounting Officer.

The call will be divided into five segments. Chris will start by making remarks regarding forward-looking statements. Then we'll come back and give a review of the current macro environment updating worldwide crude oil supply thoughts, and then quickly touch on Core's three financial tenets by which the company employs to build long-term shareholder value.

Chris will then follow with a detailed financial overview and additional comments regarding building shareholder value followed by Dick Bergmark commenting on Core's fourth quarter 2015 outlook and a general industry outlook as it pertains to Core's prospects in 2016. Then the call will get turned over to Monty who will look at Core's three operating segments detailing our progress, and discussing the continued successful introduction of new Core lab technology that relates to completing, stimulating and producing horizontal wells, deepwater wells, and then highlighting some of Core's operations in major projects worldwide.

Then we will open the call for Q&A. We will turn it back over to Chris for remarks regarding forward-looking statements. Chris.

Thanks David. Before we start the conference this morning, I will mention that some of the statements that we make during the call may include projections, estimates and other forward-looking information. This would include any discussion about the Company's business outlook. These types of forward-looking statements are subject to a number of risks and uncertainties relating to the oil and gas industry, business conditions, international market, international political climate and other factors including those discussed in our 34F filings that may affect our outcome.

Should one or more of these risks or uncertainties materialize or should any of our assumptions prove incorrect, actual results may vary in material respect 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 December 31, 2014, as well as other reports and registration statements filed by us with the SEC and the AFM.

Our comments include non-GAAP financial measures. Reconciliations of the most directly comparable GAAP financial measure is included in the press release announcing our third-quarter results. Those non-GAAP measures can also be found on our website. With that said, I will pass the discussion back to David.

Thanks Chris. First, a current macro view from Core Laboratories. We believe that the worldwide crude oil supply and demand markets are way on their way to balance by year-end or in early 2016. On the crude oil supply side, US crude production peaked in April 2015, at over 9.6 million barrels of oil per day.

Last quarter, Core projected US production to fall over 500,000 barrels per day by year-end 2015, owing to high decline curve rates associated with the over 5 million barrels of oil being produced from tight oil and unconventional reservoirs. These projections proved to be too conservative as US production has already fallen by 500,000 barrels a day based on current information. And Core now believes, that US production will fall over 700,000 barrels per day by year-end 2015.

This generates an estimated net crude oil decline curve rate for US production of approximately 7.8%. More than twice Core's newly estimated net worldwide crude oil decline curve rate of 3.1%, up 60 basis points over earlier estimated worldwide crude oil decline curve rates of 2.5%.

The 60 basis points increase is tied directly to the elevated early year net decline curve rates of 70%, 40% and 20% for the first three years of production, respectively, from tight oil and unconventional reservoirs. Therefore, applying the estimated 3.1% net crude oil production decline curve rate, to current worldwide crude production of approximately 85 million barrels per day means the planet will need to produce over 2.6 million barrels of new oil by this time next year, or production will yet again fall internationally.

To maintain current levels of production a year from now, the planet will need to produce 2.6 million new barrels. That's just not going to happen. To make up for some of this deficit, producers can produce crude from the world's dwindling spare capacity which currently is near zero. Internationally last quarter, Core believed that the ultra-high levels of Middle East production were not sustainable. And production cuts were announced within weeks of our last quarterly EPS release.

Core believes that Middle East production levels will continue to fall in Q4 led by declines in Iran, notwithstanding unknown and unpredictable crude oil supplies from Iran. Other than the opaque market of Iran, Core sees no large viable additions to crude oil supply in 2016 to offset the estimated 3.1% net worldwide crude oil production decline curve rate. Therefore, international production will continue to fall below today's unsustainable levels.

On the demand side, the latest IEA estimates are for demand to increase 1.8 million barrels of oil per day in 2015 followed by another 1.2 million barrels increased demand in 2016, trumping all of the mixed economic news from Asia-Pacific, especially China, recently in the news. Paradoxically, so far in 2015, China demand for crude oil continues to occur at record levels. Therefore, Core continues to see a V-shaped recovery getting underway in 2016. The industry is still left-hand side of this V going into Q4, perhaps with activity up-ticks in early 2016.

Now, a quick word on Core's three financial tenets by which the Company employs to build long-term shareholder value. This quarter marks Core's 20th anniversary as a publicly traded company. The three financial tenets has guided Core from our September 1995 IPO price of about $2.86 per share to where the shares trade today. And we will continue to adhere to these tenets as they have proven very successful for our long-term investors.

In the third quarter, Core generated free cash flow that exceeded net income for the fourth consecutive quarter and converted over $0.24 of every revenue dollar into free cash for the first nine months of 2015. Also in the quarter, Core once again produced the industry-leading return on invested capital. And finally in the quarter, Core returned over $1.22 per common share back to our shareholders and a total of $3.62 for the first nine months of 2015.

I will now turn it back over to Chris for a detailed financial overview. Chris.

Thanks, David. Looking at the income statement, revenues were $197.3 million, down only 3% sequentially. We continue to be pleased with our execution and results considering the market conditions. Of these revenues, services for the quarter: $150.1 million, down only 4.3% sequentially when compared to $156.9 million last quarter. And a strong performance given the reduced industry activity levels seen across the globe and the continued weakening in some foreign currencies. Product sales, which are tied more to North American activity are $47.1 million for the quarter, virtually unchanged from $47 million in the second quarter, in an environment where horizontal rig count in the US fell over 7% sequentially.

Moving on to cost of services for the quarter, they are 62.7% of revenue, improved slightly when compared to 62.8% in the prior quarter. So despite lower sequential revenues, our service operating margins expanded again this quarter, which confirms the benefits from our cost reduction actions are being realized and pricing did not play a big part in our results.

Our cost of product sales is 74.1% of revenues, also improved nicely from 76.9% in the prior quarter. Again, these improved profitability results were achieved with comparable revenues and lower industry activity levels. This improvement was a direct result of our cost and structure reduction efforts which are now being realized.

G&A is $4.2 million compared to $12.6 million in the previous quarter. Depreciation and amortization for the quarter, at $6.9 million, is unchanged from last quarter. Other expenses, quarter, primarily includes foreign exchange losses of $2.6 million.

The guidance we gave on our last call for this quarter specifically excluded the impact of any FX gains or losses. So, accordingly, our discussion today and pro forma EBIT and EBF excludes this foreign exchange loss. Excluding those FX losses to conform to our guidance, pro-forma EBIT for the quarter is $49.4 million, compared to $48.9 million in the second quarter.

Next item, our operation has generated best-in-class incremental EBIT margins this quarter, resulting in an even margin of 25.1%, a sequential improvement of 110 basis points. This is consistent with our previous guidance, despite the contraction of industry activity. GAAP EBIT for the third quarter is $46.8 million. Income tax expense in the quarter is $10.3 million, based on effective tax rate of 22.5%.

Net income for the quarter, next item, is $35.4 million while GAAP net income is $33.4 million. Earnings per share for the quarter is $0.83 on the same basis that our guidance was given and is up sequentially from $0.82 earned last quarter Our GAAP EPS for the third quarter is $0.78 per share.

As we move onto the balance sheet, and in the interest of time, I'm only going to highlight the items we feel are of interest to the audience, or have materially changed from previously reported balances. Cash is $18.5 million, down from $23.4 million at prior year-end. Receivables stand at $152.4 million, down $3 million sequentially and down from $197.2 million at prior year-end.

Our DSOs in the quarter are 66 days, and have not materially changed from prior quarters. Inventory at $44.5 million is also down $3 million sequentially, or almost 7%, as we continue to work off pre-year-end commitments which were based on expected activity levels existing before November 27 last year. Expect inventory to continue trending down as the year progresses.

Our other -- current assets stand at $26.9 million, down sequentially. And down from $37.9 million at prior year-end, primarily due to a reduction in current deferred-tax assets and timing of tax payments. Intangibles, goodwill and other long-term assets had no material changes in the quarter.

And now to the liability side of the balance sheet. Our long-term debt stands at $428 million compared to $421.5 million last quarter, and is comprised of $150 million in senior unsecured notes and $278 million drawn on our $400 million bank revolving credit facility. The increase in borrowings came as a result of our increased share buyback program. As of today, drawings under the credit facility are $287 million, and we have $88 million available.

Shareholder's equity ended the quarter at a deficit of $5.9 million, down from the year-end balance of $94 million, primarily due to share repurchases and dividends and excessive net income since the end of last year. As we've previously discussed, clearly, book equity does not represent the solvency of a company, and we note that early S& P 500 companies who generate significant levels of free cash also have negative book equity because they return that free cash flow to their owners just as we have done. We do not have any debt -- a debt or contract compliance requirements to report positive net worth.

Capital expenditures for the quarter are $6 million, consistent with prior quarters this year, but down from 2014 levels. We expect our CapEx program in 2015 to continue tracking client demand for our services and products. Consequently, we expect full-year CapEx to be approximately $25 million in 2015. So expect it to be down over 30% or about $12 million from 2014 levels.

Looking at cash flow. Cash flow from operating activities in the quarter is $43.5 million. And after paying our $6 million in CapEx, our free cash flow is $37.5 million for the quarter which, again, is in excess of net income. For the first nine months of the year we converted 25% of our revenues into free cash which generated $151.5 million in free cash flow, an impairment from 22% converted in the same period last year and represents over 150% of net income. Our focus on managing the business during this challenging environment continues to be on maximizing free cash flow, and return on invested capital.

During the quarter, we used our free cash flow, cash balances and borrowings to pay $23.4 million in quarterly dividends and to repurchase approximately 268,600 shares for $28.7 million. Through the close of business yesterday, in the fourth quarter, we have repurchased a further 56,000 shares at an average price of $115.37 per share for an aggregated cost of $6.5 million. Our diluted share count now stands at 42.6 million shares.

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

Thank you, Chris. Let's walk through our industry outlook and its possible impact on Core lab. We believe the balancing of worldwide crude oil markets is well underway as evidenced by the continued sharp decline in US production during the third quarter of 2015.

Additionally, the International Energy Agency estimates that worldwide demand will increase this year by as much as 1.8 million barrels of oil per day. And, as David said, a further 1.2 million in 2016, in response to these lower commodity prices. Tighter crude markets will prevail which in turn will lead to increased demand for our unique technology-related services and products.

It appears that US crude oil production peaked in April 2015. And we now believe that production could fall from that peak by over 700,000 barrels per day, which is more than our prior estimates of 500,000 barrels per day by year-end 2015. Adding support to this view, Baaken production has now peaked, while Eagle Ford production began to decline earlier this year. Currently, our estimated net decline curve rate for all US production is 7.8% due to the concentration of US production coming from high decline rate, unconventional reservoirs, more than doubling our newly increased estimated net worldwide crude oil production decline curve rate of 3.1%.

In addition to the second-half 2015 production declines in North America, including Mexico, international production declines are also likely in Europe, Russia, South America, and Africa. In 2016, looking forward, at current activity levels in North America, year-over-year production declines of over 900,000 barrels of oil per day are expected in Canada and the US, while international production levels are expected to continue to decline modestly. We believe that recent downward production revisions in Mexico and offshore Eastern South America confirm these views, which should precipitate higher commodity prices and then a recovery in our business in 2016.

So let's talk about our Q3 results and Q4 guidance from the perspective of versus this notion of a consensus. You may remember that we filed an 8-K last month updating our view on Q3 and Q4 guidance for Core Lab as a result of the now, well known, new lag down in industry activity. We stated in that 8-K that for Q3 we did not see a change in EPS, although revenue would, in all likelihood, be lighter.

Further, we discussed how Q4 results would be materially lower than Q3 as a result of the continuing decline in industry activity. In fact, this commentary was no different than most general industry discussions at that time. That being said, we also commented that we felt we should outperform the group in Q4, just as we have so for in this Q3 reporting season when measured by our more resilient revenue, higher EBIT margins, superior best-in-class incrementals and the highest free cash flow conversion as a percent of revenue.

While many in the analyst community did update their Q4 guidance as a result of our pre-announcement, surprisingly, several did not. Consequently the Street consensus for Q4 revenue and EPS is quite stale. So, just a cautionary note, for those who are trying to make comparisons of our new guidance, to this consensus.

To make that comparison more of an apples-to-apples exercise, one should use the Street estimates that were posted after our pre-announcement and not use the ones still posted up from before the pre-announcement. Those earlier estimates should have been withdrawn or amended. Using the current estimates, our new Q4 guidance is reasonably in-line with the current relevant consensus.

In spite of our view of a recovery in 2016, for the fourth quarter of 2015, we project further industry activity declines in North American tight oil plays. Currently, US rig counts are down 8% from average third-quarter 2015 levels. Oil company 2015 operating budgets are at very low levels and nearing exhaustion which, we believe, will force the North American rig count to further contract later in the fourth quarter.

Moreover, extended operating suspensions are likely during the North America holiday season. International rig counts are projected to be flat to down in the fourth quarter as well. With that as a backdrop, we project fourth quarter 2015 revenue to fall sequentially approximately 9% to $180 million with operating income falling to approximately $40 million producing sequential quarterly decremental margins in the 50% range.

Fourth-quarter 2015 EPS, is projected to be in the range of $0.63 to $0.67 with free cash flow once again exceeding net income for the fifth consecutive quarter. All operational guidance excludes any foreign currency translations, shares repurchased other than those already disclosed, any further restructuring or similar expenses and assumes an effective tax rate of 22.5%.

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

Thanks Dick. Third-quarter revenues are down 3.2% sequentially from second-quarter to $197.3 million. Operating earnings, excluding FX, increased 1.1% sequentially. And operating margins improved 110 basis points to 25.1%. We want to thank our employees around the globe for delivering important value-adding services and products to our clients.

Reservoir description revenues are down 0.8% sequentially to $118 million. Operating margins improved over the segment 1.5%, and operating margins -- sorry operating earnings improved 1.5%. Operating margins improved 60 basis points to 27.1% for reservoir description.

Core Lab's Middle East operation continues to see high demand for our EOR-related services. Several projects were initiated or expanded in scope during Q3. One of these projects involves combined rock and fluid testing at reservoir, temperature and pressure conditions.

During these lab experiments, produced natural gas is reinjected into rock that contains an ultra-sour reservoir fluid. The objective of this testing is to help our clients understand how both the rocks and fluids will behave during the pending pressure maintenance program. Core's unique experience with H2S reservoir fluids work is critical to successfully and safely performing this analytical program.

In another EOR project, Core is collecting samples, performing PVT analysis and determining asphaltene onset pressures in response to the various injected gases. This data will be used to determine if injecting CO2 lean, natural gas or an alternative gas option will optimize reservoir performance and maximize ultimate recovery. This laboratory data is critical for selection of the best injection gas to minimize or inhibit asphaltene flocculation and prevent impairment of the reservoir.

In addition to these EOR projects, Core is currently conducting field sampling, pore analysis and reservoir geology on a potential unconventional reservoir in the Middle East. Core's vast experience in evaluating shale and other unconventional reservoirs in North America and other geographical areas has us well-positioned to evaluate and rank prospective unconventional reservoirs in unproven formations.

Core Lab continues to see growing client's acceptance of its digital rock characterization services. In this endeavor, Core is effectively leveraging its position with the industry's most expansive database of laboratory expertise on reservoir rocks. Core Lab has developed proprietary algorithms for establishing petra-physical properties from CT, micro-CT and other imaging techniques. Less sophisticated attempts to predict rock properties from core imaging and CT data were in part, or in whole, based on theoretical models, an approach that often relies on gross simplification of complex core systems and lithological properties.

At Core Lab, actual rock data forms the foundation for the predictive models. In the third quarter, Core conducted DRC studies on cores from the Gulf of Mexico, onshore US and international basins, analyzing both conventional and unconventional reservoirs. Core continues to develop new offerings in this area through close collaboration amongst our senior scientists, mathematicians, and engineers. Core's CT base, lithotype and petrophysical property prediction tools now allow our clients to quickly gain insight into their reservoir rock properties, while companion samples work their way through traditional rigorous laboratory programs that will ultimately be used to determine hydrocarbon reserves and model reservoir performance.

Micro-CT imaging is now also used in a sample selection process for sophisticated reservoir condition flow studies. The high-resolution 3-D imaging of plug samples helps our clients better understand how variations in the pore system properties, will impact laboratory test results and reservoir performance. Production enhancement revenues at $65 million fell 8% sequentially resulting in a drop in operating earnings of 15% and operating margins to 19.3%.

Core Lab continues to work closely with many operators to utilize completion diagnostics, to optimize completion and stimulation design and eliminate unnecessary costs. The global technology team for the production enhancement group recently co-authored three technical papers that were presented at the SPE annual technical conference in late September. All three papers focused on how tracer technology can be extremely beneficial in determining the most cost-effective techniques to maximize production.

The cost optimization paper presented numerous case studies from multiple unconventional basis illustrating specific cost-saving examples. The refrac paper discussed the results from 70 wells and documented the challenges of getting optimum restimulation coverage and effective diversion.

The targeting -- targeted perforating paper presented the innovative approach of tracing the cement spacer to determine a potential natural fracture areas that then specifically targeting those integrals during the simulation process. The response to the topics presented has been outstanding. With the current market conditions, operators are extremely focused on optimization, and Core is perfectly positioned to provide the necessary technical support for this process.

Operators interest in restimulation of existing wells continues to increase to dramatically. Many operators are now looking at refrac as the best solution in meeting their production goals with the least capital dollars. Core has realized the significance of these developments and is dedicated to providing the technical, critical technical expertise for successful refrac programs.

The production enhancement team is being utilized to extensively help design, implement and evaluate potential wells in areas for restimulation. Core is now utilizing both the propent and fluid diagnostics and working with many operators to help define effective refrac geometry and evaluate diversion effectiveness. This may continue to be a major source of diagnostic work over the next 6 to12 months.

Reservoir management revenue of $14.4 million is flat sequentially while operating earnings of $4.8 million are increased 43%. And operating margins improved 1000 basis points to 33.6%. Core continues to develop new and sell existing joint industry products. The Permian section in the Midland and Delaware basin, the Utica formation in the Appalachian basin and the Haynesville play are some of the main areas of interest for our clients.

These studies contain a wealth of data, coupled with sophisticated analysis of key reservoir engineering and geological factors. For these and other unconventional plays across North America, much of the interest is driven by companies that are using studies to expedite the evaluation process and minimize the risks associated with acquiring new assets.

In addition to joint industry products, Core Lab experienced an increase in proprietary consulting work. Part of this work was driven by the asset evaluations noted previously. Many of these new companies are firms that lack the technical expertise to do a full work-up. Again, the focus has been on the Permian and Appalachian basins for this work, although a recent project looked at the asset value of a major play offshore in West Africa.

In all of these cases, Core provided the depth and knowledge the client needed to properly evaluate the assets. Core is also developing new services that utilize unique Core Lab technology, coupled with the geology to enhance the effectiveness and efficiency of our client's well completion.

The trend in the industry is to control costs by better planning and the customization of well completion programs. Strong geological models are required to optimize completion. When such a model is integrated with data from the completion diagnostics, specialized core analysis, down-home monitoring, perforation planning, and hydraulic fracture modeling, the cost effectiveness and efficiency of these completion jobs can be vastly increased.

Andrew, we'll now open up the call for questions.

(Operator instructions)

Blake Hutchinson of Howard Weil

Good morning guys.

Good morning Blake.

First off, just a couple of questions around 4Q guidance. I take it, given your view for 2016, and the radical move down that we've experienced here in North America, in the back half of the year as we exhaust budgets, that you're probably not racing as fast as you would normally to write your cost structure and, therefore, the decrement is maybe is hard, given the fact that you are not going to make more massive cuts given your view to 2016. Is that a good way to look at it? It creates a bit of a false economy?

Blake, some of it is being able to take the costs out quick enough in reaction to the late down. And so that's why we talked about these decrementals at 50%.

So you are not keeping the cost structure in place, it's just a timing issue?

That's correct. So we're not withholding adjusting our cost structure in anticipation of a V-shape recovery.

Okay. That's great. And then, in term of the reservoir description business, I understand the reservoir management you usually get some budget dump in the fourth quarter. Are there portions of reservoir description that usually benefit from that, that we would say are, are -- you're not going to recur this year?

No, as you pointed out Blake, primarily those year-end discretionary purchases with excess budget primarily occur in reservoir management. We do not anticipate that happening this year. Up-end reservoir description, that is really not affected at all by year-end budget dump.

Okay, great. And just, I wanted to just step back for a second and ask a more big picture question. I think we've been in -- so much of this story has been deepwater development related, and we all understand, I think, that you are not as prone to variations in today's exploration spending. But, with what we've seen with the last year, or couple of years, in terms of deepwater exploration spend, when does that create a smaller kind of targeted developmental and production pipeline for you? Is that a growth concern for 2016 and 2017, or is it more of a longer-lead multi-generational growth concern seeing the void and kind of the exploration spend today as it translates into your development project work?

As you know, less than 15% of our business revolves around exploration spending. When we work look worldwide at deepwater developments and those that need to be done, we certainly have, we'll call it backlog, but we have targeted projects for a number of years to roll out. If you just look at some of the recent reports out of FTI, and some of the ocean bottom systems they have sold, I think this is a pretty good indicator that we have got a long way to run.

I think one of the comments out of the conference call was-- this is the tip of the iceberg for some of these deepwater developments. That being said, if you look at 2015, it probably is going to be our most successful year in the deepwater Gulf of Mexico. So we look for that to continue on in the deepwater Gulf of Mexico in 2016. And some of these other deepwater plays, because enough costs have been taken out, that they will go on for development as well.

Okay, so you feel good about the pipeline for the coming years then?

Yes, that is correct.

Okay, great. Thank you guys. I will turn it back.

See you Blake.

Chase Mulvehill of SunTrust.

Hey, good morning, fellows.

Hello, Chase.

So, I will follow up on Blake's line of questioning here. The Gulf of Mexico is going to be a pretty good year this year. And, as we look out to 2016, how much visibility do you have into the Gulf of Mexico?

Well, you have got to blend in what you think crude oil prices are going to be. We think they are going to be materially higher as we go along in 2016. So right now, our project queue that we have lined up right now, looks pretty inviting. So, I would say, in the deepwater Gulf of Mexico visibility going into Q1 and Q2 are pretty good.

Other deepwater slots around the world offshore, Eastern South America, West Africa, some parts of the North Sea and Asia-Pacific, the visibility is not as clear. But certainly we think we will do as well in the deepwater that we did in Q3 and Q4 this year, in Q1 and Q2 of next year.

Okay. And if we think of Gulf of Mexico as the percentage of your deepwater revenues, is it like a quarter, a half, a third? How should we think about that?

I would think this year, probably, if we look at third and fourth quarter from deepwater, probably about half.

Okay, great. Awesome. And I'll turn to the balance sheet real quick. In this environment, is still two times leverage your comfort level?

Yes, that's right.

Okay. And, if I heard you correct, you had $287 million outstanding on the revolver?

Right. So we have got about another $100 million-plus under the revolver. If you use our bank covenant of 2.5 times we are still well within that, if we fully draw the revolver.

Right. Any thoughts on maybe terming out some of the revolver? I know you have got some interest rate hedges and stuff in there, but any thoughts on terming that out.

Well, we actually in some regard did that when we extended the credit facility for five years. So we have, if you will, termed it for five years. We take a view on floating versus fixed, and maybe that's where you're going. And that's kind of 50-50. So we fix half of our debt and the other half is floating at this time.

Okay. All right. And so lastly on buybacks, how are you guys approaching buybacks in this environment?

The buybacks continue to be opportunistic. So no change there, Chase. You know, clearly the dividend is first, and then buybacks are after that. So we have been opportunistic and will continue to be.

Okay. Awesome. That's all I have. Thanks Dave.

Okay Chase.

Brandon Dobell of William Blair.

Thanks. Good morning, guys.

Good morning Brandon.

I wanted to see if, in your conversations with customers, if they are aligned, or maybe not aligned around how you guys are approaching, or thinking about oil prices in 2016. I guess trying to get it, if they are aligned, maybe there's some indication of what they think their spending package may look like. Or if they are preparing for an environment that doesn't line up with how you guys think things will go?

Yes, I would say that's a mixed bag. The majors, because of their balance sheets, are probably going to be a little bit more aggressive. The independents and smaller independents that have to live off of cash flow, probably not so much.

So fortunately, we receive 30% of our revenue from major oil companies, 15% from national oil companies. So, those budgets will not tend to be as affected as much as some of the independents and smaller independents.

Okay. Then, along the same lines as in customer conversations, I know that there has been obviously, a pretty tight focus on costs the last nine months or so. But there is this broad idea that people at some point need to really focus on returns, as opposed to just dropping well costs lower. Do you see a shift in terms of how people are approaching the various products, the various offerings that you guys have? Is there a concerted move towards just buying the best product to get the best recovery rates, or is there still a bunch of customers out there that's trying to drive the dollar as low as they can?

Yes, Brandon, again, a mixed bag. When you look at our technologically sophisticated clients, they still are looking at returns and are buying technology to enhance their return on their invested capital. And you do have a number of independents that all they are looking at doing is to drive down costs. They do not tend to be as good a client for Core Lab as the technologically sophisticated clients.

And you can see in the third quarter, our operating margins did go up. And again, that was in response to some cost-cutting. But moreover, looking at some clients, still willing to invest in higher technology services and products.

Okay. And then final one for me. As you guys think about the -- let's call it the arc on furloughing or pulling back on hours for employees. How much more of that should we expect as you finish out year-end? Or is it really going to be actually letting people go as opposed to furloughing them as we move into 2016?

Brandon, we are using both options there. We have some further rifts that are going to take place in the fourth quarter. And we are also going to do some furloughing as activity levels allow that and call for it in any shrinking in activity. Particularly if we saw a hiatus in activity, as some people are projecting for December, we would use the furloughing more aggressively.

Okay. Great. Thanks guys.

Okay Brandon.

Rob MacKenzie of Iberia Capital Partners

Thanks, guys. I guess my question is probably for Monty or Dave. Looking at the model here, it's interesting that sales revenue was flattish quarter-over-quarter, which I have always thought was largely a big part of Owens' business. Does that indicate to me that your perforating business is holding up quite well? And, if that's the case, it seems like most of the reduction in North America is coming from the frac diagnostics protectives business. Is that correct?

You are looking at production enhancements?

He's talking about sales. And within product sales we have Core Lab Instruments. We also have Down Hole measurement instruments. So it's not 100% Owen. So just be careful on that extrapolation there.

So would you -- answer that a different way. Would you say that frac diagnostic is down probably more than Owen?

No. They are about the same.

The production enhancement, as the rig count has fallen, the fewer wells being completed, it affects both of those units.

Yes Robert, you think about it. The number of stages that are completed and stimulated would touch both of those guys equally. Perforating guns on the product side and a myriad of diagnostics on the service side.

Okay. That's helpful. Coming back to an earlier question, one of the things that Schlumberger talked about was that they are having -- they are wishing that operators would ship more towards a dollar per barrel focus versus a dollar for well focus. And indicated that they are really not having much luck selling new technology so far this down cycle. It sounds like you are not quite having the same experience. What technologies in particular, do you think, are really resonating with your customers here?

I think the technologies that Monty reviewed briefly, on his oratory and the write-up that we had for the release of the digital rock properties, the technologically driven deepwater reservoir fluids work, those margins are holding very well with respect to clients still employing those technologies, Rob.

Okay.

And as Chase mentioned earlier Rob, there are some companies that are going for just the cheapest completion, or the cheapest well they can get. So, that may be what Schlumberger was referring to. Not everybody is looking at technology. But, our client base tends to be the companies that want science in their wells.

Okay. Thanks, and then, to your point on the V-shape recovery Dave, how should we think about what your incremental margins might look like? I know we have had some pretty steep decremental; should we expect the incrementals to be similar, higher, lower?

I would think they would be similar or higher due to just cost reduction. And then, the level of automation that we have put in worldwide, which was, made more efficient by the purchase of Sanchez. And then some of the multi-skilling programs that we are working on globally, where we can have some of our operators do several tests at one time.

Okay, and my final question is -- comes to, kind of going into the first quarter. Obviously, with fourth quarter guidance being down a fair bit, would we expect to see the normal first quarter seasonality, or should that be more muted on a sequential basis this year?

At this point Rob, we're thinking typical seasonal pattern for Q1 is going to be lower than Q4.

Okay. Thank you. I will turn it back.

Thanks Rob.

(Operator instructions)

John Daniel of Simmons.

Hey guys, thanks for putting me in. I just want to follow up on Rob's questions. He touched on trajectory for revenue into Q4. I would like to get your thoughts just on the margin expectations given potential cost reduction, efforts and things like that. Would you expect to maintain margins from the Q4 levels into Q1 or would you expect to see potential drift lower up given lower revenue?

No, probably drift upwards.

We will continue to work as Monty said on the cost structure. And, with the perhaps high grading of mix on the types of revenue. So perhaps we do see as David said, an expansion of margin.

Okay, just one, and maybe if I could take a swag at Dave. If your V-shape recovery is correct, any reason to think that you would get back to Q3 revenue levels by mid next year? Is that your working assumption or do you think it takes a little bit longer to get back to those levels?

I think Q2, Q3 those are possibilities.

Okay. Two other quick ones. Dick, I missed the G&A guidance for Q4. Could you just repeat that please?

This is Chris. It should be about the same as Q3.

Okay. All right, and then just lastly on the refrac opportunity, the client interest is rising dramatically. Do you actually see that playing out in terms of increased activity levels next year, and just do you have any swag as to how many wells that we're talking about that might actually might be refracked? And out of the Haynesville, Barnett in 2016?

We are seeing, John, that is increasing steadily. We are looking at doing about 10 projects a month right now. Third quarter-ish. Now, those are multistage projects as you probably realized when they go into refrac. If done properly with the proper science, is really the lowest cost way to boost production as we are finding and many of our clients are. So we think that's going to continue to increase. And there is certainly the Haynesville, the Barnett, our areas that are primed to have a delivery system for that gas. So I think we will see that continue to increase.

Okay, thanks, guys.

Okay, John.

A follow-up from Chase Mulvehill of SunTrust.

Yes, Chase.

Sorry. Thanks for squeezing me back in. I have got a question for about what productivity, if you guys get to see a lot of wells, and you talked a lot of EMPs. So how close do you think we are to maximizing well productivity for US unconventionals? And, do you think that EURs have peaked?

No, they have not peaked. What we're seeing right now is an artifact of low commodity prices because we are looking at the operators drilling up their very best acreage. And, to that mind, I think on the last call, we spoke about the number of EOR projects that we have underway now in tight oil reservoirs. They again have expanded the number in Q3. So we will look at the implementation of EOR to occur early in 2016 throughout 2016, and into 2017. So the EURs will continue to increase. The number of wells that that will happen on, will continually shrink, though, as these sweet spots in the very best reservoir rock ends up getting drilled up.

Do you think that the completion technique has been optimized? Are we hitting?

Absolutely not, not even close. Chase, we know that we can push a long chain hydrocarbon about 120 feet in an average tight oil reservoir. So, if that is indeed the case, we should have a stage every 240 feet, or so, feet apart. Stages are still more than, on average, 400 feet apart.

So we still have some optimization going on the drilling and completion stimulation techniques. We are still proponents of longer laterals, and if you look at companies that are drilling the longest laterals out there, Pioneer Natural Resources is coming to mind. They are 10,000 footers, but looking at the number of stages they're putting in there, and the amount of profit, that is still a blueprint for success and higher EURs.

Okay. Last one. You guys have a good feel of this as well. What are you seeing for the number of ducts out there in the US and, how does this kind of compare to a normalized level at current activity conditions?

Still, a lot more than higher than the inventory. We'll see that get worked off, we believe, in Q1 and Q2 for the industry. That is a benefit to us, because, when the ducts do indeed get completed and stimulated, that brings our services and products from production enhancement to bear.

Okay awesome, that's all I have.

Okay Andrew. I think we are going to wrap. So, in summary, Core's operations have never been better positioned to increase the level of enhanced oil recovery and recovery from reservoirs around the world, especially those in tight oil plays, and unconventional shales in North America. The Company remains committed to industry leading levels of free cash generation and returns on invested capital with excess capital being returned to our shareholders.

So in closing, we would like to thank all of our shareholders and the analysts that follow Core and, especially, our employees for joining us this morning. And as all ready noted by Monty Davis, the Executive Management and Board of Core Laboratories give special thanks to our 4400 worldwide employees that have made these results possible. We are proud to be associated with their continuing achievements. So, thanks for joining us this morning. And we look forward to our next update at the end of the fourth quarter. Bye for now.

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