David M. Demshur - Chairman-Supervisory Board, President & CEO Gwendolyn Y. Schreffler - Vice President-Human Resources Chris Hill - Vice President & Chief Accounting Officer Richard L. Bergmark - CFO, Member-Supervisory Board & EVP Monty L. Davis - Chief Operating Officer & Senior Vice President.

Rob J. MacKenzie - IBERIA Capital Partners LLC Sean C. Meakim - JPMorgan Securities LLC Blake Allen Hutchinson - Scotia Howard Weil.

Good morning and welcome to the Core Laboratories Q2 2016 Earnings Conference Call. All participants will be in listen-only mode. After today's presentation there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the conference over to Mr. David Demshur, Chairman and President of Core Labs.

Please go ahead..

Thanks, Harrison. I'd like to say, good morning in North America, good afternoon in Europe, and good evening in Asia Pacific. We'd like to welcome all of our shareholders, analysts and most importantly, our employees to Core Laboratories' second quarter 2016 earnings conference call.

This morning I am joined by Dick Bergmark, Core's Executive Vice President and CFO; Core's COO, Monty Davis, who'll present the detailed operation review; and Chris Hill, Core's Chief Accounting Officer. Also this morning I have the pleasure of introducing Gwen Schreffler to new participants on this call.

Gwen will be helping Core with our Investor Relations efforts. Gwen has been with Core Lab for over 10 years, most recently as Vice President of Core's Human Resources based in the last three years in our Amsterdam office.

Her new role in Corporate Development and Investor Relations is a logical segue from her role leading our HR efforts, as Core Lab is such a people-focused, energy technology company. Our most important assets are the skills, capabilities and technologies delivered by our employees to our clients throughout the globe.

Many of our European shareholders have already met Gwen over the past few years, as she has augmented our Investor Relations efforts in Europe, while based in Amsterdam. The call will be divided into five segments. Gwen will start by making remarks regarding forward-looking statements.

Then we'll come back and give a review on the current macro environment, updating U.S. and worldwide crude oil supply thoughts as related to newly-calculated net decline curve rates, and then quickly comment on Core's three financial tenets, which the company employs to build long-term shareholder value.

Chris will then follow with a detailed financial overview and additional comments regarding shareholder value. That will be followed by Dick Bergmark, commenting on Core's second quarter and second half 2016 outlook and a general industry outlook, as it pertains to Core's prospects.

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

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

Gwen?.

Risk Factors in our Annual Report on Form 10-K for the fiscal year end 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 second quarter results. Those non-GAAP measures can also be found on our website. With that said, I'll pass the discussion back to Dave..

Thanks, Gwen. We'd like to look at the current macro view and then review our three financial tenets. Core believes that worldwide crude oil supply and demand markets are close to balancing and will balance the second half of 2016. On the crude oil supply side, U.S.

unconventional production peaked at 5.5 million barrels of oil per day in March of 2015, and has since fallen by over a million barrels a day owing to high decline curve rates associated with these tight oil reservoirs.

Offsetting these sharp production declines have been additions of approximately 160,000 barrels a day from several deep water Gulf of Mexico legacy projects that were commissioned several years ago and started to bear fruit in late 2015-2016.

These additions no way will offset what's coming from the deductions that will occur on land throughout this year and into 2017. The sharp declines from U.S. land production are continuing in 2016, and Core believes these decreases could reach 1.1 million barrels of oil per day or more by yearend.

Lower levels of new wells and delayed production maintenance will exacerbate the fall in U.S. land production going into 2016 – 2017. Remember, production decline curves are linear in time but logarithmic in production declines. A year ago, month-over-month U.S. production declines were in the tens of thousands of barrels per day, per month.

Now these month-over-month per day losses quite often reach 100,000 barrels of oil per day or more. So look for that to expand and continue to expand into late 2016 and into 2017. From these analyses, we would take the over on the drop of 1.1 million barrels per day by yearend. We will recalculate these numbers for Q3 earnings release.

Moreover, further net declines from legacy deep water projects – moreover, further net gains from legacy projects in the deep water Gulf of Mexico will be needed to offset significant increases in the existing Gulf of Mexico production base.

These legacy Gulf of Mexico projects could add a net 160,000 barrels a day in 2016, slightly offsetting the material onshore and shallow water declines that are taking place. Core estimates that the current net decline curve rate for U.S. land production is approximately 10.1%, which will continue to expand into 2017.

We are in the process of recalculating these parameters and we'll re-update in Q3. Globally, Core estimates that the net crude oil production decline curve rate has expanded to 3.3% net, up some 20 basis points from earlier year estimates.

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

With the long-term worldwide spare capacity nearing zero, Core believes worldwide producers will not be able to offset these declines, and the estimated 3.3% net production decline curve rate in 2016 will lead to falling global production in 2016.

This is supported by some of the recent IEA data indicating declining production on a global basis through Q2 2016. Therefore, Core believes crude markets more than rationalize in the second half of 2016 and price stability, followed by price increases, some occurring as we speak, return to the energy complex.

Remember, the immutable laws of physics and thermodynamics mean that crude oil production curve always wins and it never sleeps. On the demand side, if we look at the crude oil market, the IEA has increased demand in 2016 to approximately 1.4 million barrels of oil per day. The U.S. is now using over 10 million barrels per day of gasoline.

These are near record levels. Recent Chinese export, coupled with strong demand out of India, are at near all-time highs. Supply and demand will balance as they have in all past market disruptions. Now to review the three financial tenets by which Core used to build shareholder value over our 20-year history of being a publicly-traded company.

Incidentally, Core is also celebrating its 80th year of innovation in 2016. During the second quarter of 2016, Core generated free cash flow that exceeded net income for our eighth consecutive quarter. Free cash flow for the first half of 2016 more than doubled net income, clearly the best in all oilfield services.

Moreover, Core converted over $0.23 of every first half 2016 revenue dollar into free cash; again, leading all oilfield service companies. Also, during the second quarter, Core once again produced the oilfield's industry-leading return on invested capital for the 28th consecutive quarter, topping an ROIC of 26%.

Producing an industry-leading ROIC has not happened by chance. A real concern for investors is exposure to the Venezuelan market. Core closed all operations in Venezuela in 2013, a discussion at which time was highly questioned by our analysts, shareholders and potential shareholders.

Departing Venezuela in 2013 led to lower short-term revenue and earnings growth rates versus other oilfield service companies, for which we were criticized. This paralleled our discussion to depart Mexico operations over a decade ago. Now, downsizing Latin and South American operations are very trendy in our industry.

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 occurring and with over $1 billion of write-downs to come, we believe Core made the correct decision, protecting the long-term return on investment goals by departing the Venezuelan market.

And finally, during the second quarter of 2016, Core returned over $23 million back to our shareholders via our quarterly dividend. Core will continue to return all excess capital back to its shareholders, with hopes of additional share repurchases in the near future. I will now turn the call back over to Chris for a detailed financial review..

Okay. Thanks, David. Starting with the income statement, revenue for the second quarter was $148.1 million; so, down sequentially about 3.5%. But that's in an environment where we've seen the average quarterly rig count in the U.S. fall 24% this quarter, and global average rig count for the quarter is down 19%.

Of this revenue, service revenue is $118.2 million for the quarter, down almost 4% sequentially; but, again, a favorable outcome considering the significant drop in global rig count this quarter and general spending levels from the oil and gas clients.

Product sales revenue, which is more tied to North America activity, was down only 3% sequentially to $29.9 million, when average horizontal rig count for the U.S. decreased some 25% this quarter when compared to the first quarter this year.

Moving on to cost of services for the quarter, they were at 70.5% of revenue and, despite lower revenue, stayed in line with Q1, which was about 69.5%. So you can see our cost reduction actions taken in the first half of this year are being realized, which helped us continue to generate some of the strongest margins among oilfield service companies.

Our cost of product sales was 89.1% of revenue, unchanged from prior quarter. So despite the sharp decrease in North American rig count and associated activities, again, our cost reduction efforts being implemented throughout the first and second quarters helped the company retain its margins.

G&A for the quarter was $11.1 million and is consistent with prior quarter. For the full year, we expect G&A to be approximately $45 million to $46 million.

Depreciation and amortization for the quarter was $6.8 million, unchanged sequentially, but down a little year-over-year from $6.9 million due to the reductions in our CapEx program starting last year.

Considering capital expenditures in 2015 and with our anticipated capital programs for 2016, we would expect depreciation to continue on these approximate run rates and to be about $27 million for the full year. Other income and expense includes $400,000 of foreign exchange losses.

And as we have previously stated, our guidance excludes any gains or losses related to FX. The guidance we gave on our last call for this quarter specifically included the impact of any FX gains or losses and was based on an effective tax rate of 14%.

So accordingly, our discussion today in pro forma EBIT and EPS exclude this foreign exchange loss and assumes a tax rate of 14%. So, excluding those FX losses and to conform to our guidance, pro forma EBIT for the quarter was $20.7 million compared to the pro forma EBIT of $23.7 million reported last quarter.

GAAP EBIT for the second quarter was a little over $20.2 million. Interest expense in the quarter was $3 million, a decrease of about 12% from $3.4 million in the first quarter.

We expect interest expense in future quarters to continue to be materially lower than previous quarters as the proceeds from our equity offering are used to reduce our outstanding debt by almost 50%. As a result of the reduction in debt and interest expense, the equity offering will be accretive to EPS for the company.

We expect interest expense at current debt levels to be approximately $2.6 million to $2.7 million per quarter going forward. I'll provide further details related to the equity offering later in my discussion on the balance sheet. Income tax expense in the quarter, using an effective rate of 14%, would have been $2.4 million.

Our GAAP income tax expense for the quarter was about $650,000 and was lower than our guidance due to slightly lower earnings in the U.S. and adjustments like FIN 48 and other discrete items that were recognized during the second quarter.

We believe our effective tax rate for the third quarter will approximate 11%, and this excludes any discrete items that may be recognized in the quarter. Net income for the quarter, ex-items, as $15.3 million compared to $15.7 million for the first quarter of 2016, ex-items. GAAP net income was $16.6 million for the quarter.

Earnings per share for the quarter was $0.35 on the same basis that our guidance was given. Our GAAP EPS was $0.38 per share, which includes those foreign exchange losses and uses the GAAP effective tax rate. These items are reconciled in a table, which is included in our earnings release.

Now, as we move on to 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 $14.8 million, down from $22.5 million at prior-year end.

Receivables stand at $112.8 million, down from $145.7 million at prior-year end. Our DSOs for the quarter were 64 days, a nice improvement from the 67 days last quarter and the 66 days for all of 2015. Our management team and personnel continue to focus on important aspects of running the business during this difficult environment.

Inventory of $39.8 million is down slightly from the year-end balance and down approximately $1.9 million from March 31. We continue to expect inventory levels to trend down as we move through the remainder of 2016. There were no material changes on other current assets, PP&E and tangible goodwills or other long-term assets.

And now on to the liability side of the balance sheet. Accounts payable is $29.4 million, down from the balance of about $33.5 million at prior-year end.

Other current liabilities are down about $7 million during the quarter to $66.8 million, and down from the year-end balance of $87.3 million, primarily due to the timing of accruals and payments for severance tax and other various liabilities.

Our long-term debt stands at $208 million, which has reduced approximately $200 million or almost 50% this quarter, primarily from the proceeds received through the equity offering. On May 26, we completed a successful equity offering issuing about 1.7 million new common shares for net proceeds of approximately $197 million.

So for issuing less than 4% of our outstanding shares, we used those proceeds to pay down a substantial portion of the outstanding balance on the revolving credit facility and reduce our total debt by almost 50%.

Our outstanding debt of $208 million is comprised of $100 million in senior unsecured notes, $60 million drawn on our bank revolving credit facility, which is net against $2 million of debt issuance costs.

This reduction of debt this quarter has strengthened the balance sheet and positioned the company well as we manage through this difficult year and prepare for the recovering energy market. Shareholders' equity ended the quarter at $167.5 million, up primarily due to the equity offering just mentioned and net income offset by our dividend payment.

Capital expenditures for the quarter were $2.4 million, down from the $2.9 million in first quarter of 2016. The company continues to expect its 2016 capital expenditure program will be less than 2015, perhaps in the $15 million range.

However, if oilfield activities pick up, Core has the ability to increase its investments in support of these strengthening activities. Now looking at cash flow; cash flow from operating activities in the first half of 2016 was $73.8 million. And after paying for our $5.3 million in CapEx, our free cash flow is $68.5 million.

Once again, our free cash flow exceeded net income this quarter. During the first half of 2016, we used our excess free cash flow to pay $46.6 million in dividends and further reduce our long-term debt. Our focus on managing a 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% year-to-date. We believe this is an important metric for shareholders when comparing companies' financial results, particularly those shareholders who utilize discounting cash flow models to assess valuations.

In 2015 and year-to-date 2016, our free cash flow was higher than our net income, as it has been in 10 years out of the last 14 years. I will now turn it to Dick for an update on our guidance and outlook..

Thank you, Chris. Dave has already set the foundation for our broad view of the crude oil markets coming into balance and how that should provide a positive backdrop for Core Lab, particularly in 2017 when our clients are expected to begin to increase their activity levels.

But until then, based on typical seasonalities, we do project third quarter results will increase on a sequential basis from the second quarter. Revenues should range between approximately $148 million to $151 million, yielding operating margins increasing sequentially to approximately 15%.

Our effective tax rate is expected to be approximately 11% in the third quarter, as a result of lower profitability in higher tax rate jurisdictions. Third quarter EPS is expected to be in the $0.39 to $0.41 range with free cash flow exceeding net income for the ninth consecutive quarter.

On an equivalent-currency basis, Core expects third quarter 2016 revenue and operating income and margins to increase from second quarter 2016 levels.

Therefore, our second quarter 2016 results should mark the bottom of our anticipated V-shape worldwide commodity recovery, followed by increased crude oil prices and expanded industry activity levels worldwide. With that guidance discussion over, I'll now turn it over to Monty for an operational review..

Thanks, Dick. Second quarter revenues of $148 million were down 3.6% sequentially from the first quarter compared to a 19% decline in the global rig count. Operating earnings excluding foreign exchange losses were $20.7 million, yielding an operating margin of 14%.

We extend our appreciation to our dedicated employees worldwide for their continued delivery of best-in-class services and products to add value for our clients every day in a difficult market. Reservoir Description revenues for the second quarter of $103 million grew 1.4% from Q1. Operating earnings of $19.2 million yielded operating margins of 19%.

In the second quarter, Core Lab expanded work on several laboratory-based programs aimed at evaluating enhanced oil recovery opportunities in unconventional reservoirs. Fracture stimulated unconventional reservoirs often yield only a very small portion, an average of 9% of the original oil in place.

Testing and validating methods to improve recovery factors in these tight rocks can substantially change plate economics, possibly increasing recovery rates to 13% to 15%. Core's on the cutting edge of developing EOR techniques in tight oil reservoirs.

Scientists in Core Lab's Aberdeen Advanced Technology Center have been working on a multi-well evaluation project to describe, characterize and evaluate the potential of what our client describes as a world-class deep water asset offshore West Africa.

A key deliverable of the multi-well program is to delineate the physical properties and architecture of the asset. Information and datasets from Core will help the client to develop their long-term exploitation plan, focusing on maximizing production from this complex reservoir structure.

Core's geoscientists are utilizing proprietary techniques, high resolution digital imaging technologies and other state-of-the-art laboratory equipment to characterize the geological and petrophysical attributes of the rock.

Our reservoir condition measurements will be used to calibrate third-party wire line logs, yielding a much more detailed reservoir model. At the same time, Core's Reservoir Fluids laboratory in Aberdeen has been tasked with characterizing the key chemical and physical properties of the hydrocarbons in this discovery.

State-of-the-art, high pressure, full visual PVT cells manufactured by Core Lab are being used to understand the variations in fluid properties across this reservoir. The results of these tests will provide critical inputs into flow assurance models.

During this quarter, our live data systems delivered tangible savings to one of our customers, which we worked with on a pilot project. In this particular project, we used our dashboard technology to measure the efficiency for loading and discharge operations at a number of their facilities in Europe.

By using this technology, choke points in the logistical chain became visible, such as unnecessary waiting time and congestion that led to superfluous lay-time. As a result thereof, processes have been redesigned and optimized. More importantly, continuous monitoring assignments have been put in place to secure permanent improvement.

This concrete result created further leverage to our strategy of adding value to the logistical chains of our customers. A number of other pilot projects with different customers and/or partners in the distribution chain are being put in motion.

We expect Reservoir Description will recover later in the spending up-turn, as new wells must be drilled and cores and reservoir fluids taken before they can be analyzed. As mentioned in the Q1 call, we are still targeting 20% margin for Reservoir Description for Q3. Production Enhancement's second quarter revenues declined 11% to $39.1 million.

Operating margins of 2.5% yielded operating earnings of $1 million. Noble Energy and Core Laboratories coauthored a Society of Petroleum Engineers technical paper in Q2 to be presented at the fall 2016 SPE Annual Technology Conference.

This paper describes 13 frac-pack treatments performed over the past six years on Noble Energy wells in deepwater Mississippi Canyon, in which Core Laboratories proprietary diagnostic technology SpectraStim and SpectraScan/PackScan were employed to improve offshore operations, ensure complete annular packs, evaluate frac-pack efficiencies, and provide decision-making data to be used in the development of best practices for Noble Energy going forward.

According to one of the Noble engineers, without Core's diagnostic data identifying the need for and got aiding the top off (28:51) design and Core's follow-up diagnostics confirming the success of the top off, this well most likely would have been an infancy sand control failure, which would have resulted in an expensive workover.

Ultimately, the well was successfully put on production and has been producing sand-free for six years with a low skin factor, and has cumulatively produced 11 million barrel of oil equivalent and is still producing 2,000 barrel of oil equivalent per day.

As the new well drilling market continue to fall to its lowest levels in Q2 2016, Core Lab's ballistic and mechanical engineers have been having significant success in developing economical solutions for customer problems that exist with older wells that need to fix casing leaks or shut off unwanted water for increased hydrocarbon production.

As a result, Core's Production Enhancement group is realizing significant growth in the remedial market with unique solutions. The Production Enhancement team successfully adapted and tested five patented X-SPAN Casing Patch systems to meet Russian GOST standards, equivalent to API casing standards used in most oilfield regions.

During the second quarter, our first significant order was shipped to Russia to be utilized for repairing casing leaks and shutting off water in older wells.

Core's X-SPAN technology was previously tested in a Russian oilfield and proven as a more reliable and economic method for repairing casing leaks and shutting off unwanted water in old wells, versus the conventional method of cement squeezing.

Cement squeezes are often more expensive and ineffective in repairing casing leaks and shutting off water-producing zones. Core's X-SPAN system utilizes a patented, multi-dimensional metal-to-metal technology to provide a permanent seal over the damaged casing and existing perforations for zonal isolation.

In addition to the projects in Russia, the X-SPAN system has been successfully deployed in North Africa for a water shut-off program that is expected to continue over the next three quarters. We expect Production Enhancement to be an early beneficiary of increased client spending, as duct wells will be one of the first area to see increased activity.

Reservoir Management revenues for the second quarter of $6 million were down 25% sequentially. Operating margins increased to 8%, yielding operating earnings of $500,000. Early in the quarter, most client interest was in the Permian Basin studies.

Near the end of Q2, interest increased in plays that are predominantly gas-prone, the Marcellus and the Haynesville, indicating the industry is becoming more bullish on the potential for increasing domestic natural gas demand. Many of the U.S.

customers continue to be new companies that are entering the arena with good financing and a little or no debt. The key to their success is identifying the best plays with the lowest risk, a process that requires good geological and engineering data, two valued data sets that Core Lab can supply.

We anticipate an increase in steady sales as the acquisition and divestiture markets become more active. Outside of North America, Reservoir Management has been leveraging our expertise in unconventional plays to gain a foothold in some of the emerging markets.

A concentrated effort in the Middle East is paying off with a recent reward of another unconventional reservoir evaluation contract. On the conventional side, Suriname, Guyana, Angola and the East Coast of Canada are the focus of our ongoing offshore work.

The announcement of the overwhelming success of Exxon Mobile and Hess' exploration program in Guyana bodes well for future sales of Core Lab's regional studies. Harrison, we will now open the call for questions..

Okay. We will now begin the question and answer session. And our first question comes from Rob MacKenzie of IBERIA Capital. Please, go ahead..

Good morning, guys..

Good morning, Rob..

Dave, or maybe Monty, I guess my first question is, coming back to what you talked about on enhanced oil recovery and tight reservoirs.

That's something you guys have talked about for a while, and I'm just curious kind of where that stands in the development process? What hurdles or what milestones you need to achieve before that becomes kind of a more material commercially?.

Yeah. Good question, Rob. We first mentioned this at the end of the first quarter of last year.

We have a number of projects that continue to grow, and we are still currently in the experimental stage for specific reservoirs and specific crude oils on what is the proper cocktail, at what pressures and temperatures to inject that into the reservoir to recycle. So we do have a number of projects that are ongoing.

You do have one field implementation of admissible flood out in the Eagle Ford Shale. Rob, we're still probably several quarters away before we see the field-wide implementation of these projects. But sure enough, they're coming down the pike..

Okay. So it sounds like, from my prior notes, you guys were talking recovery rates up to 12% to 14%. Now you're saying 13% to 15%.

Is there something you're seeing that's making you even more optimistic about what you're able to achieve here?.

Yeah. And as we study the cocktails of which we are injecting, including miscible hydrocarbon gases, we've upped those 100 basis points on either end. We still believe that, that is doable in the field. However, taking a laboratory scale to a field scale is a big step. It's always happened before in experimental projects that we've worked on.

We have no reason to believe that, that won't occur at that level. So, the more that we study these phenomena and the cycling of these various fluids through these rocks, the more we learn..

Got it.

And then how would – A, how would billing for a service like this work and, B, how would you protect the intellectual property and all the work that's gone into designing these cocktails and prevent others from just simply copying you?.

Yeah. From the aspect of billing, these are really book-price analyses that we perform, many of which are performed at reservoir temperature and pressure. So, Rob, we're looking at relative permeability testing across using water and multiple gases. So that's a very common analysis for us that runs through our price book.

On protecting the proprietary side, we're using trade secrets for individuals in our facilities. Of course, once paid for by the client, they own that technology and the secrets associated with that. They're free to share that with whomever.

However, we must say that the variety of cocktails of gases needed to be effective are going to vary greatly, even within single plays. So when you look at it from a standpoint of being able to share what these cocktails are, what could be very effectual in one area of the play might not be all that effectual in a county or two over.

Moreover, on the proprietary side, some of these pressures and temperatures at which we are injecting, we are the only guys on the planet that have this equipment.

And so that also provides a proprietary note on others being able to simulate these in their laboratories, whether they be in major oil companies or pseudo-competitors in the North America or global space..

Great. Thanks. And one final, if I may. How should we think – or how do you think about the ultimate size of this, because on its surface, it sounds like this could be a very material contributor to earnings over time.

Just trying to see if we can put some benchmarks around that?.

Yeah. It's hard to say right now, but I think you're right, Rob. In two or three years, this will be a mainstay of Reservoir Description in North America..

Great. Thanks. I'll turn it back..

Thanks, Rob..

Our next question comes from Sean Meakim of JPMorgan. Please go ahead..

Hey, good morning..

Good morning, Sean..

Thinking about North America, given the continued ramp in volumes per stage we keep hearing about from the E&Ps, how are you thinking about that trend helping your results in Production Enhancement relative to rig counts? As we think about – you've talked about a V-shaped recovery.

How do you see the performance of that business relative to broader activity in the rig count, specifically?.

Yeah. If we look at Production Enhancement, clearly outperforming by a long stretch, but the decline in the North American, especially the U.S. land rig count, has been more of that to come. Again, the mantra for continued success are longer laterals, more stages, closer clusters, more profit.

If you look at our 2013 annual report, on the cover, we have what was then called the well of the future. It contained 256 stages. We've just worked on a well that had over 160 stages. So the well of the future will be here before we know it.

So, and that being said, you can look at and model the recovery and the growth rate in Production Enhancement to clearly outstrip the gain back in the rigs that we've added, the 70 rigs or so that we've added from the bottom in May..

And then how do we translate that into incremental margins this cycle, do you think?.

I'm going to let Dick answer that one because he's been working on these incrementals..

Yeah, Sean, you think about the cost that we would need to take out to the field, as the number of stages increase, so the lateral length increases. It really doesn't change our cost structure.

So, it's just the incremental cost of additional stages, so some additional chemicals, for example, still pretty much nil, so we're thinking incrementals are going to be 60%-plus, just as they have been on any recovery in a cycle.

Moreover, as these new services are added though, irrespective of are you in a cycle, just the incremental nature of that revenue will generate those high incremental margins through cycles..

Right. Makes sense.

And then switching gears a little bit coming back to EOR, just curious as we are at a bit of an inflection point here in terms of activity for North America, how do you expect E&P interests in those types of projects to evolve in a recovery? It's just as E&Ps are getting more cash flow, but they're also getting more interested in incremental drilling programs.

Any shift in those conversations?.

Yeah. It's interesting, Sean. We've got clients now that are talking about return on their invested capital.

And certainly if you're going to just apply these numbers to their past returns, which in many cases have not been to the level that they need to be to even recapture their cost of capital, these programs will be needed to ensure that their return on invested capital is a positive with respect to their cost of capital.

So, even as we drill additional wells and exploiting more of these major tight oil plays, you will see the more sophisticated clients using these technologies. Clients like Pioneer Natural Resources on the CO2 front. You've got a company like Occidental that has been very good in applying this technology out in West Texas.

You will continue to see that occur and actually expand over this next rebound in the cycle, keeping in mind that our most sophisticated and technologically adept clients know that they need to increase their returns on their invested capital..

Fair enough; makes sense. Thanks a lot, gentlemen..

Our next question comes from Blake Hutchinson of Howard Weil. Please go ahead..

Good morning..

Hello, Blake..

First question just a kind of a point of clarification from some of the numbers that were thrown out there relating to kind of segment outlook. I think Monty said that the goal of attaining 21% margins in Reservoir Description for the coming quarter was still intact.

I guess as we look at the overall numbers, that would entail that Production Enhancement margins were flat to perhaps down.

Is there some mix working against maybe Gulf of Mexico or international mix? First of all, is that correct? And, I guess, is there some positive mix working against Production Enhancement that may kind of mask some of those increments from the U.S.

land market, just from a quarter-to-quarter basis if that's what's at work?.

Blake, first, let me be real clear on this. We said 20% margins for Reservoir Description for Q3. That's the same number we gave out at the end of Q1. We thought by Q3 our Reservoir Description margins would be up to 20%..

Okay..

We have been dealing with our cost structure for the last year and a half. And as the bottom of the B (45:09) went deeper than most people I think expected, we have continued to deal with our cost structure, including into the second quarter, and right up to the end of the second quarter, we've been making adjustments.

So the full effect of those won't be in play – the later ones, of course – until the third quarter. So that's where we get our feeling of what's going to happen for us. We do see some pick-up in the Production Enhancement revenues.

As I mentioned, the duct wells, we think that there will be a reduction in the number of duct wells in excess of normal process over the second half of the year. And we've got pretty good reason, talking to customers, to know that that's plans of many of our customers.

So that's opportunity for us in Production Enhancement that we're pretty confident is going to happen in the second half of the year and into 2017..

So, Blake, if you use 20% margins in Reservoir Description, you still have room to grow Production Enhancement margins slightly in Q3 as well..

Yeah. That jibes more with what we're talking about in this conversation. Okay. I'm sorry, I misheard that 21%. Absolutely; got it.

And then I guess, maybe David or Monty, just because we're kind of in the starting box here and you mentioned all the costs that you've worked out of the system on Reservoir Description, specifically, as we think about kind of cycle-to-cycle margins – I'm not asking to get granular and I understand pricing hasn't necessarily impacted the whole portfolio of projects within reservoir description, but if we look over the last 12 months to 18 months, what type of price impact, and maybe on a weighted average basis, have you felt, so that we can kind of understand what's come out from that perspective and apply that kind of to our margin understanding going forward?.

I think you don't make a large amount of correction for pricing. Most of this is volume-related, Blake, and we've tried to reduce costs to offset the lack of volume coming out of this. Reservoir Description should model no differently than it did through 2008, 2009, 2010, and 2011.

So if you use that model base, you see that you can get your Reservoir Description operating margins back into the low-30% area..

Great. That's extremely helpful. Let me sneak one more in here and I'll hang up and listen. You mentioned that the Reservoir Management section has actually seen an uptick in some demand for U.S. basins.

Is that a continuation of kind of your private equity comments from the last quarter or are you starting to see some operators come back and take a look at these data sets?.

It's both, Blake. You've had a lot of small operating companies that are getting infusions of equity as they go through the process, and this is where we're seeing people that have new interest.

We're also seeing people come in and acquire management from previous operators that have plans of their own, and they're looking at these same plays that we mentioned. So it's a mix of companies that have gotten an infusion and companies that are being formulated with some expertise from their prior life..

Great. Thanks for that, guys..

Okay, Blake..

It appears we have no further questions at this time..

Okay, Harrison, thank you.

So in summary, Core's operations continue to position the company for an uptick in activity levels in the second half of 2016, and we know the significant challenges await, however, we have never been better operationally and technologically positioned to help our clients to maintain and expand their existing production base.

We remain uniquely focused and are the most technologically-advanced reservoir optimization company in all of oilfield services. This positions Core well for the challenges ahead.

The company remains committed to industry-leading levels of free cash generation and returns on investment 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 Monty Davis has already said, the executive management and board of Core Laboratories give a 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 joining us this morning, and we look forward to updating you at the end of the third quarter. Goodbye for now..

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