Core Laboratories N.V. (CLB) Q1 2016 Earnings Report, Transcript and Summary

Welcome to the Core Laboratories First Quarter 2016 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] I would now like to turn the conference over to David Demshur, Chairman, President and Chief Executive Officer. Mr. Demshur, please go ahead.

Thank you, Andrew. I’d like to say 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 first quarter 2016 earnings conference call. This morning, I am joined by Dick Bergmark, Core’s Executive Vice President and CFO; Core’s COO, Monty Davis, who’ll present the detailed operational review; 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 review the current macro environment, updating U.S. and worldwide crude oil supply thoughts, as related to newly calculated net decline cure rates, and then quickly comment on Core’s three financial tenets, which the company employs to build long-term shareholder value. And then Chris will follow with a detailed financial overview and additional comments regarding building shareholder value; this will be followed by Dick Bergmark commenting on Core’s second quarter and second half of 2016 and our 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 Chris for remarks regarding forward-looking statements.

Thanks, David. Before we start the conference this morning, I’ll 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 on 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 or uncertainties materialize or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. For a more detailed discussion of some of our 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 first quarter results. Those non-GAAP measures can also be found on our website. With that said, I’ll pass the discussion back to David.

Okay, Chris. Thank you. Core believes that worldwide crude oil supply and demand markets will balance in the second half of 2016. On the crude oil supply side, U.S. unconventional production, peaked at 5.5 million barrels per day in March of 2015, and has since fallen by over 600,000 barrels per day owing to a high decline curve rates associated with tight oil reservoirs. Offsetting these sharp production declines have been addition of approximately 200,000 barrels of oil per day from eight deepwater Gulf of Mexico legacy projects that were commissioned several years ago and that beared fruit in late 2015. The sharp declines from U.S. land production are continuing in 2016, and Core believes that decreases could reach 1.1 million barrels a day by year-end 2016. Lower levels of new wells and delayed production maintenance will exacerbate the fall in U.S. land production going into 2017. Moreover, further net gains from legacy deepwater projects in the Gulf of Mexico will be needed to offset the significant decreases in existing Gulf of Mexico and its production base. These legacy deepwater Gulf of Mexico projects could add a net 200,000 barrels of oil per day in 2016, slightly offsetting the material onshore declines that are expected in 2016. Core estimates that current net production decline curve rate for U.S. production is approximately 10.1%, which will expand as 2016 progresses into 2017. Globally, Core estimates that the net crude oil production decline curve has expanded to 3.3% net, up from 20 basis points from earlier estimates. Applying a 3.3% net decline curve rate to the current worldwide crude oil production base of about 80,000 barrels -- 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. With long-term worldwide spare capacity near zero, 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 oil production in the year. These net decline curve rates are supported by recent IEA data indicating a decline of 300,000 barrels of production per day from February to March of 2016, which is the third consecutive month of global decline. Therefore, Core believes crude oil markets rationalize in the second half of 2016 with price stability followed by price increases returning to the energy complex. Remember, the immutable laws of physics and thermodynamics mean that the production decline curve always wins and it never sleeps. On the demand side, in the crude oil markets, the IEA is still calling for increased demand in 2016 of approximately 1.2 million barrels of oil per day, notwithstanding daily market news out of China regarding their economic activity. Recent Chinese imports coupled with strong demand out of India are at all time highs. Supply and demand will balance as they always have in past market disruptions, owing into the decline curve. Now, to review the three financial tenets by which Core used to build long shareholder value over our 20-year history of being a publicly traded company. Incidentally, Core is celebrating its 80th year of history of innovation of technologies in the oilfield, in 2016. During the first quarter, Core generated free cash flow that exceeded net income for the seventh consecutive quarter. Free cash flow for the first quarter of 2016 nearly tripled net income, clearly the best in the oilfield service industry. Moreover, Core converted over $0.28 of every 2016 first quarter revenue dollar into free cash flow, again leading all oilfield service companies. Also during the first quarter, Core once again produced an industry leading return on invested capital for the 27th consecutive quarter, topping in the ROIC of 27%, producing an industry leading ROIC have not happened by chance. A real time concern for investors is the exposure of companies to the Venezuelan market. Core closed all operations in Venezuela in 2013, a discussion which at the time was highly questioned by our shareholders and potential shareholders. Departing Venezuela in 2013 led to short-term revenue and earnings growth rates that were not as robust as some other oilfield service companies for which we were criticized; this paralleled our discussion and decision to depart part Mexico operations over a decade ago. Core’s internal risk assessment process determined that long-term risk clearly outweighed long-term value for the Venezuelan market. With hundreds of millions of dollar have past write downs and with over billions of dollars of write downs to come, we believe that Core made a right and correct decision, protecting long-term return on invested capital goals. And finally, during the first quarter, Core returned over $23 million back to our shareholders via our quarterly dividend. The Company’s outstanding share count still hovers at around an 18-year low and the Company will be opportunistic in future share repurchases. I’ll now turn it back over to Chris for a detailed financial review. Chris?

Thanks, David. Looking at the income statement, revenue for the first quarter was $153.6 million, so down sequentially about 16% but that’s an environment where we’re seeing rig count in North America fall over 35% since December, and the global rig count is down 21%. We believe for the full year 2016, our client spending is expected to be down some 27%. Of this revenue, service revenues are $122.8 million for the quarter, down 13.5% sequentially but again a favorable outcome considering the significant drop in our client spending in global rig count so far this year. Product sales revenue which is tied more to North America, activity was lower for the quarter at 30.9 million, down about 24% when an average horizontal rig count in the U.S. decreased over 32% compared to the fourth quarter of 2015. Moving on to cost of services for the quarter, they were 69.5% of revenue, up from 65.1% in the prior quarter due primarily to the absorption of our fixed cost on lower revenues as we continue to implement our cost reduction initiatives throughout the quarter. Our margins on service revenue continue to be some of the strongest amongst oilfield service companies. Our cost of product sales was 89.1% of revenue, up from 79.4% in the prior quarter, again due to the absorption of our fixed cost on lower revenue, and we continue to reduce our cost structure in this part of the business. G&A for the quarter was a little over $11 million, down from last year primarily due to lower compensation expense. Depreciation and amortization for the quarter $6.8 million, down sequentially from $7.1 million due to reductions in our CapEx programs starting last year. Considering capital expenditures in 2015 and with our anticipated capital programs for this year, we would expect our quarterly depreciation expense to be about $6.8 million or lower for the remainder of the year to total approximately $27 million for 2016. Other expense this quarter was primarily included exchange losses of $800,000. The guidance we gave on our call for this quarter specifically excluded the impact of any FX gains or losses. So, accordingly, our discussion today on pro forma EBIT and EPS excludes this foreign exchange loss. The comparisons to other quarters exclude any FX, asset impairments or employee related severance costs that were recorded in prior periods. Excluding those FX losses to conform to our guidance, pro forma EBIT for the quarter was $23.7 million compared to $39.5 million reported last quarter and resulting in EBIT margins of over 15%. GAAP EBIT for the first quarter was $22.9 million. Income tax expense in this quarter was $4.4 million based on effective tax rate of 22.5%. Net income for the quarter, ex FX was $15.7 million, compared to $27.7 million in the fourth quarter of 2015 ex-items. GAAP net income was $15.1 million for this quarter. Earnings per share for the quarter was $0.37 on the same basis that our guidance was given. Our GAAP EPS was 35% -- $0.35 per share, which includes prior foreign exchange charges for this quarter as listed on the reconciliation table to our earnings release. 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 of $16.5 million is down from $22.5 million at prior year-end. Receivables stand at $122.5 million, down from a $145.7 million at prior year-end. Our DSOs in the quarter were 67 days, an improvement from 68 days last quarter and comparable to the 66 days for all of 2015. Our management team continues to focus on all important aspects running of the business during this difficult environment. And as Dave mentioned, I also wanted to mention that we excited our operations in Venezuela several years ago and as a result have no receivable exposure associated with Venezuela. Inventory at $41.7 million is up slightly from year-end balance of $40.9 million primarily due to a few pending sales of laboratory instruments that we expect to be delivered in the second quarter. We continue to expect inventory levels to trend down as we move through 2016. And now on to the liability side of the balance sheet. Other current liabilities are down to $74 million from the yearend balance of $87.3 million, primarily due to the timing of accruals and payments for severance, tax on other various liabilities. Our long-term debt stands at $409 million compared to $433 million at year-end, so reduced about $24 million, and is comprised of a $150 million in the senior unsecured notes and $259 million drawn on our bank revolver credit facility. As we stated last quarter, we have used our free cash flow in excess of the dividend to reduce the outstanding balance on a revolver this quarter. Our net debt to adjusted EBITDA for bank covenant was 1.9 at the end of the quarter, well under the threshold of 2.5 to 1. Shareholders’ equity ended the quarter at $28.3 million deficit to up a little bit from the year-end deficit of $23.7 million, primarily due to paying dividends in excess of net income during the first quarter. Clearly, book equity does not represent the solvency of a company and we note that several S&P 500 companies who generate significant levels of free cash have also negative book equity, because they return that free cash to their owners just as we have done. We do not have debt or contract compliance requirements to report positive net worth. Capital expenditures for the quarter were $2.9 million, down from the $4.5 million last quarter. The Company continues to expect that its 2016 capital expenditure program will be less than 2015, perhaps in the $12 million to $15 million range. However, if oilfield activities pick up, Core has the ability to increase its investment in support of the strengthening activities. Looking at cash flow, cash flow from operating activities in the quarter was $46.2 million, and after paying our $2.9 million in CapEx, our free cash flow is $43.3 million, an industry-leading $0.28 for every dollar of revenue earned. In the quarter, we used our cash to pay $23.3 million in dividends and reduced our long-term debt by $24 million. Our focus on managing the business during this challenging environment continues to be on maximizing free cash flow and return on invested capital. Our conversion of revenue into free cash flow continues to be one of the highest in the industry at 28% for this quarter, and our free cash flow conversion ratio, which is free cash flow divided by net income, ex-FX, was over 280% for the quarter. We believe these free cash flow metrics are important for shareholders when comparing Company’s financial results, particularly for those shareholders who utilize discounted cash flow models to assess valuations. In 2015 and 2016 year-to-date, our free cash flow was higher than our net income as it has been for 10 of the last 14 years. I will now turn it over to Dick for an update on our guidance and outlook.

Thanks, Chris. David has discussed our industry outlook. So, let’s layer in our thoughts on how that may impact Core Lab. The balancing of worldwide crude oil markets continue as evidenced by this continued sharp decline in U.S. onshore oil production, beginning in the second of 2015. Further, the IEA estimated that worldwide demand did increase in 2015 by 1.8 million barrels a day and will increase an additional 1.2 million barrels per day in 2016, in response to these low commodity prices. We believe tighter crude markets will prevail in the second half of 2016, which in turn will lead to higher energy prices and subsequent increased demand for our unique technology related services and products. We believe that continuing decline in global production and the continuing increase in global energy consumption should create a tight crude oil supply market in the second half of 2016, which should leave first to increase crude prices in an higher industry activity levels worldwide. Based on typical seasonality, we project second quarter results will decrease slightly on a sequential basis from first quarter with revenue ranging from approximately $145 million to $150 million, yielding operating margins of approximately 14%. Our effective tax rate is expected to be approximately 14% in the second quarter, as a result of lower profitability in higher tax rate jurisdiction. Second quarter EPS is expected to be in the $0.34 to $0.36 range with free cash flow exceeding net income for the eighth consecutive quarter. On an equivalent currency basis, we expect 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-shaped commodity recovery that should lead to increased crude oil prices followed by increased industry activity levels. Our free cash flow, as a result of earnings and continued working capital management programs, will continue to be used to provide liquidity for our future quarterly dividend program, as well as debt reduction. Further, our $400 million bank revolving credit facility remains available as we continue to be and expect to be going forward, in full compliance with terms and conditions of that facility. All operational guidance excludes any foreign currency translations, shares repurchased other than those we have already disclosed, and any further restructuring or similar expenses and does assume an effective tax rate of 14%. Now with that let’s turn the discussion over to Monty for an operational review.

Thanks, Dick. First quarter revenues were down 16% from the fourth quarter of 2015 to $153.6 million. Operating earnings excluding foreign exchange losses were $23.7 million, yielding an operating margin of 15.4%. We think our dedicated employees worldwide are delivering the best services and products to our clients every day. Reservoir description revenues for the first quarter of $101.5 million were down 11.5% from the fourth quarter. Operating earnings of $18.7 million yielded operating margins of 18.4%. The Nuclear Magnetic Resonance Group of Core’s Huston Advanced Technology Center has designed, built, validated, and commissioned proprietary reservoir condition high frequency NMR instrumentation capable of quantifying in situ oil and water volumes in very low porosity formations. Core Lab is the only commercial laboratory offering this type of reservoir condition test. This new technology is currently allowing operators in the Permian and Delaware basins to further characterize moveable versus non-moveable hydrocarbon in these extremely tight formations. Compilation of these, Core analysis datasets with detailed petrographic and sedimentology studies are assisting these West Texas operators in field completions and well placement strategies. In the Putumayo Basin in Southwest Colombia, Core continues to evaluate fluid and core samples for enhanced oil recovery studies. Core is providing reservoir rock and fluid based behavior data supporting our clients secondary recovery program design. Digital rock characterization, micro-CT scan services, micro-scan have been employed as a tool for detailed Core’s sample assessment and selections for advanced rock properties. These samples are being use in reservoir condition flow test that will provide greater certainty in projecting reservoir performance. Core expects additional core and fluid samples on this project during 2016. A large NOC is currently conducting extensive core floods on rock samples from offshore field in the Middle East by using Core’s newest state-of-the-art flow studies technology. The steady state relative permeability live fluid recirculation system is allowing reservoir condition datasets to be acquired while using very low volumes of reservoir fluids. This ensures sufficient quantities of live fluid are available to test the large number of core samples that are required to generate a rigorously defined reservoir model. In light of that continuous effort to optimize the efficiency of processing our field data for our customers, a further step has been made by the launch of a state-of-the-art, in-house developed software program called Sail 4, [ph] which is fully integrated in our processing system connect. This will enable us to reduce a number of steps in our administrative workflow with corresponding improvements in our cost efficiency. Our locations around the world, fields [ph] of field data interconnect contain global secured and validated datasets. Through our authentication protocol, clients have real time access to status information on their product flow and more importantly, the quality datasets. The information is provided through live reports and dashboards for multiple platforms including mobile devices such as smartphones and tablets. Production enhancement revenues for the first quarter of $44.1 million were down 22% from Q4 compared to the North American rig counts which was down 35%. Operating earnings of $4.5 million yielded operating margins of 10.1%. Core’s completion diagnostic experts and services have been called upon in the first quarter to partner with several operators to develop completion and development strategies to better navigate the current crude oil, low crude oil and natural gas price environment. Core initiated several new diagnostic projects to answer many questions about completion tradeoffs. One multi-well project which has been going on from last year has determined that a new completion approach reduces completion costs by 25%, while improving production performance by 50%. These [indiscernible] are dependent on what stage of the optimization process a company maybe in and the quality of the reservoir. Core’s customers continue to innovate ways to improve performance through the use of Core’s diagnostic services. As new techniques, ideas, and technologies are tested, Core’s variety of diagnostic services are necessary to quickly determine, which ones are successful and to suggest new ways to overcome suboptimal completions. As operators continue to optimize their well-site efficiency and reservoir production, Core Laboratories’ KODIAK Enhanced Perforating System and HERO line of perforating charges have seen increased utilization in North American shale plays. These production enhancement technologies have been successfully used by operators to increase production by as much as 15%. In the last 12 months, the HERO PerFRAC system has experienced significant market acceptance, with a 23% increase in utilization, while the North America rig count has fallen 50% over that time. During the first quarter, Core Lab conducted testing utilizing its state-of-the-art CT scan facilities to evaluate the HERO charge performance against other perforating technologies. The testing was conducted under simulated reservoir conditions and revealed that the HERO patented technology achieved 15% to 40% more total depth penetration as compared to competitive charges, following a significantly less debris, resulting in a larger tunnel volume. Deeper penetration, minimal debris, and larger tunnel volume increases frac flow efficiency due to lower breakdown pressures and fewer screen-outs, providing operators lower stimulation costs and higher production rates. Reservoir management earned revenue of $8 million in Q1 2016 and operating margins of 6.8%. Core continues to shift its focus to products that add value to our customers through efficiencies and cost savings, particularly as it relates to completion practices. As an example, our X-ray fluorescence and hardness testing product allows us to the define rock mechanical properties using inexpensive non-destructive Core analysis techniques. As the global merger and acquisitions market begins to pick up, Core’s positioning itself as the go to provider of strategic services. Core’s leveraging off its 30-year history of conducting geological studies and collecting proprietary reservoir data to provide companies with an asset evaluation service that is unique to the industry. Strategic evaluations conducted by Core Lab have been instrumental and saving our clients tents or even hundreds of millions of dollars during acquisition, merger and joint venture negotiations. Outside of North America, the market for geological studies is more stable. Much of the activity is focusing on the Atlantic margin with offshore plays in West Africa and South America dominating. Core Lab continues to see interest in our studies of these areas. Core Lab initiated a new study of the presalt section off the coast of Angola in the first quarter. Today this has been well received by the industry and we anticipate additional subscription as the study nears completion. Andrew, we’ll now open the call for questions.

We will now begin the question-and-answer session. [Operator Instructions] The first question comes from James West of Evercore ISI. Please go ahead.

Dave, you -- or Monty, have you noticed any discernable changes in demand for certain products as you’ve gone from the back half of ‘15 and saw another dip in oil prices in early ‘16; has there been any shift in certain product lines or certain markets or is it still -- anything for enhanced recovery?

I would say, James, from a micro view, we are seeing less demand for analysis of reservoir rock read, that being core samples. But that’s being somewhat offset by an increase in the amount of fluids work that we’re doing especially fluids work revolving around increasing daily production and increasing recovery over the life of the field. So, even though it’s not totally offsetting it, I would say that would be the biggest macro shift that we have seen.

Okay. And that’s good for you. You have really no competition in fluid analysis; is that correct?

Correct. And margins there are indeed better.

And then question on the second quarter guidance, it seems to me like we were exiting the first quarter at fairly low rate in terms of this new North American rig count and of course internationals continuing to fly. But it looks like you are looking for a much less of a sequential decline in earnings. Can you help us with that on what you are seeing in your business that maybe different than what other more or more commoditized product lines companies are seeing?

Couple of things; I think we are showing a repeat of historical performance where we tend to outperform the broad metrics. So, our revenue in this down cycle, yes, it has come in but not as much as any of the rig counts that you want to use or any spending surveys that you want to use. And I think that’s a result of some of the things that David just talked about, fluids, some of the products that we have, the diagnostic services that we have that are fairly unique, but create high value for the customer. So, I think that’s why our business has held up better than the broad markets, and that’s our perception for Q2 going forward as well.

And even though it’s a bad house and terrible neighborhood, deepwater Gulf of Mexico now is the most active deepwater province in the world as they now outstrip offshore deepwater Brazil.

The next question comes from Kurt Hallead of RBC. Please go ahead.

So, I just wanted to get -- you guys laid out the macro perspective really well. So, the context of how you see the rest of the year progressing, are you getting direct indications from E&Ps that they are getting ready to get more active or in the process of getting more active? And can they turn things around from an activity level, back quickly such that you’re going to have higher revenues in the third quarter? I just wanted to get a little bit more color around that.

Kurt, what we are thinking as the year progresses is that it will be the normal seasonal pattern. So, we are not saying that there is an increase in activity yet from what we expect to be higher oil prices; that will come. What we are saying is just as the year rolls out, we are expecting Q3 will be better than Q2, just as it has 12 out of the last 14 years.

Okay. And then, you guys put us a very strong -- much better than kind of industry average decrements in the production enhancement in the quarter. Obviously reservoir description was somewhat challenged. So, is it my understanding that it is the timing dynamic with reservoir description and you think your decrements will improve in that segment as you move forward?

Yes, Kurt, I think that’s right because you look at the way we provide services in the reservoir description that’s the laboratory based businesses where we are conducting experiments, tests and projects are underway throughout the quarter. We are not able to effectuate a cost reduction in that group until those projects are over. So, we were doing that throughout the quarter. So, we had cost that remained within that segment, probably longer period of time in that quarter compared to production enhancement where we were able to take cost out more quickly earlier in the quarter and got benefit of that as the quarter progressed.

Yes. And I think as we look towards an outlook for the third quarter, we will see margins that that actually in reservoir description, the decrementals may shrink to zero and we will actually see maybe an increase, a slight increase in operating margins because a lot of those costs now have come out.

Okay, great. And then, how would you guys describe the pricing environment for your services right now?

Still pretty good, on the commodity side where we still have some of those commodity products and production enhancement; essentially those prices can go over any lower because we’re kind of selling them at cost but still on the high tech side margins are holding up quite well.

The next question comes from Bill Herbert of Simmons. Please go ahead.

So, back to the fluid analysis and the uptake on this; I’m just curious with regard to Lower 48. What the client mix is in terms of the adoption of -- and the more sort of the use of the technology is. Is it combined to biggest investor breed or is it becoming broader than that right now where the resource holders using this technology?

Yes, Bill. Good question. The heavy users are certainly the majors and the major independents, some of the more innovative companies that are out there. But we are seeing a broader reach now to some of the mid independents and smaller independents. So, just for instance in the deepwater Gulf of Mexico where you are running up to temperatures as high as 300 degrees Fahrenheit, 29,000 PSI, of course those are the majors and some of the super independents like Anadarko bay users and once you get on shore, you find the EOGs, the pioneer in natural resources, the con shows [ph] are heavy users and that is now spreading to some of the smaller independents as well.

Okay. And then a question with regard to the macro outlook days. So, I’m curious as to what your views are with regard to the threshold oil price and time line required to grow U.S. oil output significantly, call it 500,000 barrels per day or higher. So, oil price, timeline required data please?

And actually you must have seen my notes that we prepared. Recently -- we believe it’s somewhere between $65 and $75 per barrel would be the U.S. threshold price to grow production some 500,000 barrels. Now that’s going to be pushed out about six months, as we retool and re-rig back up and getting crews running. So, even though we have that sustainable price for a period, you can look at a lag and maybe six more months before we start to add towards that 500,000 barrels per day of growth.

And finally, your views with regard to year-over-year deltas with regard to non-OPEC ex-U.S.; any thoughts on that with regard to magnitude of declines as what I’m assuming you are looking at for 2016?

Say that again.

The magnitude of the production decline for non-OPEC ex-U.S. in 2016 year-over-year, assuming you are processing an actual decline this year.

Yes. We are, and I would say -- and I’ll get you some better clarity on that. But that’s going to be somewhere on the order of 2 million barrels per day in loss production.

Okay, that’s -- but what I’m asking was net actually?

Let me get back to you on that.

Okay, great. Thank you.

The next question comes from Byron Pope of Tudor, Pickering, Holt. Please go ahead.

You said in your earnings release on just how resilient some of your activity in the deepwater Gulf has been in addition to your response to one of the prior questions. And if I recall correctly, it seems though offshore services and products were somewhere in the ballpark of 40you’re your revenue mix with deepwater being half of that. And so, just given what’s happened with the North American onshore landscape, could you refresh us on what that mix looks like today in terms of offshore, as a percent of the total, and then deepwater within that?

Yes. 30% of all oil worldwide is produced offshore; prior to this downturn, 40% of our revenue came from offshore. That has actually remained pretty resilient and probably now is pushing somewhere in the high 40% range for offshore and then the corresponding downturn for onshore or worldwide as fallen from somewhere in the 60s probably to the low 50s.

Okay. And then, I know a lot of your reservoir fluid phase behavior work in the Gulf isn’t necessarily tied to rig count activity but do you expect that part of the business to be relatively resilient as we progress through this year?

Yes, should be, because you still have operators that are conducting a lot of tests and projects that are covered by their operating budgets. And they are using the information to boost not only daily production but to make sure they increase ultimate estimated recovery from those deals.

The next question comes from Chase Mulvehill of SunTrust. Please go ahead.

I guess first question, I’ll kind of come back to reservoir description margins that kind of came in a little bit lighter than what we expected. So, can you walk us through the main drivers for the sequential decline, maybe as we think about mix versus pricing versus the cost burden that you mentioned?

Yes. When you think about the sequential change, we have talk about our cost structure in past that we believe those costs are coming out, so that will be an improvement. On the higher tax services and more proprietary in nature, Dave has already talked about how pricing on those reasonable. But on the commodities, services and products, we talked about how there is pressure on those. You throw all that in the mix, that’s part of the reason why we’ve got the sequential decline. So, it’s a little of that. So, little bit of just activity levels are down; if you look at the average rig count in Q2, it will be lower than the average rig count in Q1.

And I was trying to call some of the commentary around the margin profile for reservoir description, was that commentary around 2Q or 3Q, when you are talking about potentially zero decrementals?

Yes, that was going -- that would be Q3, Chase. So, we would see the bottom or decrementals maybe crossing over to incrementals in the third quarter release.

And so, as we look at 2Q margins for reservoir description, care to take a stab on what you think they might be?

Monty?

They will be -- in the reservoir description in particular, they’ll be around 20%, I think a little better than what we had in the first quarter and that’s due to the way the cost structure is being handled, reductions there. So reservoir -- is that what you’re asking, just reservoir?

Yes, just reservoir description.

Yes. We should be plus or minus 20%.

And then for 2016 reservoir description revenues, any sense about order of magnitudes that be down?

It just depends on second half; that’s a hard one, Chase.

Should we think about international CapEx, global CapEx, what’s the -- if we think about modeling this, how should we think about it?

Yes, I am thinking you’re going to have to have heavy reliance on what you think international CapEx and spending in activity levels will be, because we don’t see a substantial increase in North America until going into 2017.

Right, okay.

And operating budget too as well, Chase; don’t forget that.

I am going to shift gears real quickly. So, bear with me on this hypothetical but let’s assume that things don’t rebound in the second half and you need to get coveted relief to a max leverage ratio of three times, can you talk about the dividend and whether it’s safe under this scenario?

We believe it’s safe under the current scenario. And it would be even more safe under the scenario you just mentioned, if we increase bad debt to EBITDA ratio with the bank.

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

I want to kind of attack maybe that back half progression of reservoir description top line a bit differentially, and maybe David you could help us out with a bit of a history lesson? I guess as we started this year, I think the business got hit a little more by deferred maintenance, maybe some major field projects set downs. Have you typically, I guess in terms of reactivity of top line of reservoir description, do we simply need to think about kind of that being the long lead investor or their buckets of that you would argue get turned on more quickly, given their production nature -- production related nature and maybe can you talk about those buckets for us?

Yes. On the international side, we have seen some decrease but actually those are lot longer term projects. The majority of the impact in reservoir description was North America and land. So projects owing to tight oil and then just some pressure maintenance projects or some EOR for conventional fields onshore.

Okay. So, maybe going back to the reset that you did deepwater for us, I mean you usually talk about kind of 70-30, 75-25 international-domestic for that business; have you reached extremes on that or 80-20, 90-10…

I would say, we are probably pushing a little bit over 80 and little less 20, North America.

And then just point of clarification on production enhancement margins maybe for Dick. I guess we should take away that you feel like you attack the cost structure that you noted in the release early, and so are comfortable with the levels that were achieved in 1Q. There wasn’t necessarily an additive, a mix additive or a Gulf of Mexico additive that helped that. And so, we kind to keep the progress we made on that cost structure as we head into 2Q?

There weren’t one-off items. So, you are right; it was a normal flow, given this environment. But we do think margins, Monty, talked about 20% margins for reservoir description, perhaps production enhancement is low single digit but not negative.

The next question comes from Rob MacKenzie of Iberia Capital. Please go ahead.

The question I guess for you Dave. With seemingly pick up in the number of E&Ps transacting properties -- property changing hands, including the number of private equity shops, in that where -- how much of an opportunity do that represent to you in terms of being able to characterize and help the buyers some of the properties, understand what they’re buying?

Yes, I’ll let Monty make some comments because in the reservoir management we are seeing more private equity folks than we’ve seen in quite a while and it’s for those datasets. Monty?

Yes. We have a dedicated effort to helping not only the private equity but anyone that’s assessing properties as to what they might be looking at, what might be a good deal and what might not be a good deal. We have a vast knowledge, as you know, through our studies. Plays all over North America and the international arena, more of the activities are probably going to be in North America. And we’ve got a pretty good handle on what you can expect to produce and then of course they have to run their models on what they think to price for them to sell that for. But we can tell them what the best plays are and then they’ve got to decide the valuations. But we’ve got a dedicated effort and we are working with people on that now.

Yes. And Rob, actually adding to that we’re doing a lot of major proprietary in-house work trying to evaluate acreage as we mentioned in the release; we just finished up our largest proprietary project. And this was essentially looking at drilling locations going forward in this price environment. So, not only are we seeing private equity but also some of our clients looking to use a microscope to find where those drilling -- best drilling locations will be where they can find the highest production rates, greatest return on their investment capital.

Okay, thanks. I guess I was also hoping to get a little bit of a feel for how material some of that might be to you all?

At the current time, I wouldn’t say it’s material; it could build material, but there has not been that much activity in acquisitions at this point in time. We keep expecting it to pick up soon but that’s hard to say; everybody is being a little cautious.

Got it, okay. And in terms of picking up, I wanted to try and dig a little deeper on some of that where you expect to see the uptick come first. Obviously, I would think it would be more North America related versus international, and correct me if that’s correct. But would you expect to see it kind of concurrently in terms of reservoir description characterizing rocks and fluids along with the completion side of production enhancement or would you expect production enhancement to be the first to show signs of recovery?

Usually the canary in the coal mine is the reservoir description group. So, I would -- we would see the delta take place because we haven’t had that much of downshift internationally that would have to be North America, where we would see the delta on the uptick, and it could happen commensurately with production enhancement, as you get either recompletions re-fracs or the completion of some of the ducks.

Great. And have you seen any signs of the duck inventory starting to be drawn down yet, Dick?

Yes, I would say that that’s not a material number at this point, but actually the ducks account let’s just say that background ducks [ph] is about 1,500 and right now there is probably a little over 4,000. We’re starting to see that get sizzled away.

The next question comes from Igor Levi of Morgan Stanley. Please go ahead.

Good morning, guys. Great job on navigating the worst quarter we’ve seen the long time, especially on free cash flow. Could you talk a bit about what you’ve seen in market share trends for various products and service lines that you have over the course of this downturn? I mean how many of these 2,000 fields that you are targeting in reservoir description are you on now and or more oil companies now in-sourcing work or outsourcing to Core Labs? And then similarly on the production enhancement segment, what are market share trends like in North America and international?

Yes, Igor, couple of good questions, actually. If you look at reservoir description, the last count we had is we were active on about 1,250 fields; we still have commitments to do work in those fields although some of that workflow may have slowed down or been postponed for a period of time. On more of an acute side, before we leave reservoir description, yes, we are seeing some of the majors do more of their work in-house because they are at lower levels of work. So, we see market share anywhere, it could be back to our best clients. So, we look for that to return back to status when activities pick up.

That being said, Igor, we did put in the release project that we’re doing in South America for major IOC; it clearly has in-house capabilities but it’s just technology that we have that’s more applicable to what they are trying to do. So, it’s hard to say they are trends; it’s kind of go on both ways.

Yes. That’s good point. And then on more an acute side for production enhancement, because we don’t share a lot of those technologies or other oilfield service companies don’t offer lot of those technologies, I wouldn’t say that share has swing, [ph] just the sheer of volume of number of wells that have been drilled or not drilled has really affected their revenue and profitability.

And just one question on the technology, the new technology side; in the second quarter of last year, you talked about the new recirculation system focusing on can they work in the North Sea and then you mentioned that again in last night’s release seeing increased acceptance. I was just hoping you could talk a bit more about the acceptance of this technology is type of share gains perhaps you are seeing? And has this actually driven an increase in can they [ph] work since we know a lot of that has been delayed during the course of downturn?

What we have done, Igor, is it’s much more efficient from a cost standpoint and a time standpoint system. So, what we are doing is helping them make it less costly and more timely. It’d be hard pressed to say that’s going to make them do more plug and abandon faster in this environment. But having said that, we are defiantly doing more of that type work, reaching that product grow continually over the last year, since we introduced it. And it’s a very easy sell on the value add to the client. So, where they’re going to do plug-in abandonment, we have got a great system that they are adapting to very quickly. So that’s been a growing segment, as our several of the technologies I mentioned in my previous discussion points where this technology that benefits the client is grown.

And then finally, this is the first quarter where we haven’t seen share buybacks in the long time where you using the excess free cash flow after the dividend to pay down debt? And now your leverage ratio is over half a turn within the covenants. So, what is the level that you guys, could you just remind us, are comfortable with and when could we expect to return back to the market to buy back share before the end of the year?

We are -- what we are doing right now is behaving similar to what we did in 2008-2009 where we actually backed in, put cash on the balance sheet because we just weren’t certain with great clarity when the market would improve. So, we have a view that the market is improving and will continue to improve but we in the interim periods will probably use our excess free cash beyond the dividend to repay our revolver debt. That way, we take the question of that debt to EBITDA off the table because it doesn’t come into play, as we pay down debt, and we will continue to pay the dividend. And so right now that’s our capital allocation is dividend first, pay down debt, stock buybacks however continue to be viewed as an opportunistic allocation of capital. So, we are not saying we’ve suspended the program; we have just said currently we are going to pay the dividend and pay down debt.

The next question comes from Matt Marietta of Stephens. Please go ahead.

Solid quarter, obviously the guidance and outlook much more stable than I think many of the other companies we all cover in oilfield services. So, congrats to that. When we look at the V-bottom, can you help us maybe understand what the upwards slope of the V may look like from kind of a rig count, oil price? And then ultimately production perspective, the down slope of the V has been very steep, very long. But obviously there is going to a lot of constrains to re-ramp production, given the deep cuts that have occurred, primarily in North America. I am just hoping to maybe get some color into how this V or the upwards slope of this V unfolds in your crystal ball with respect to domestic, international rig count spending levels activity and maybe offer you an opportunity to hedge a little bit here on what in this outlook, if there is anything that can derail the outlook of a V-shaped kind of recovery as we had into the back half of the year?

Yes, Matt, I think that the slope of that upward V is going to be directly related to the slope of the upward V on the price of the energy complex with North America certainly natural gas and crude oil. That’s where we’re going to have the biggest delta in activity levels take place in response to those higher oil prices. I think the earlier question on what kind of price we need to really start building back production gains in the U.S. was somewhere between $65 and $75 a barrel. So, as quick as you can ramp to that level is probably will determine the up slope of the V-shape. Internationally, yes, activity levels have been down but not anywhere near sharply as they had been in North America. So, really the controlling factor on that upside is going to be the price accrued and the response in activity levels in North America. So, other than that, I don’t think we can get more granular.

So, I guess a lot of the folk is in U.S. production and activity, but in light of the meetings really in recently in Doha and the rhetoric from Russia and Saudi, so they can increase their output, there is obviously challenges ongoing and would be another other places in North Africa. But do you think -- how do you think about the potential for further production increase without of OPEC and other major players; are they possible from here and what could that possibly due to the V-shaped recovery? I guess what I’m after is what about the other 90% of the oil market outside of U.S.; what are those net declines going to look like in the back half of the year and what do we think demand is going to be in the back half of the year to help us kind of calibrate how to think about the V bottom.

Yes. But right now, our suggestion is that our net worldwide decline curve rate is going to be 3.3%. When we look at OPEC and really globally, we don’t see a lot of sustainable spare capacity. You may have some producers in the Middle East that could sharply raise crude production for a short period of time but on a sustainable rate, probably cannot occur. So because of the lack of spare capacity worldwide, we don’t think any crude comes on the market unexpectedly due to just raising current production rates; that’s probably not going to happen. So, what could delay the backend of that is you have piece that breaks out everywhere and get lithium production back, and those that are off to market because of political turmoil, we really see that not happening either. So, that’s based on our 3.3% net global decline curve rate. We’ve plugged that into the recovery of the commodity markets in the second half of 2016. I hope that helps.

It does. And on the demand side, I guess are we kind of sticking to the IEA?

Yes. We are not demand guys, so we just -- that’s why we always use the IEA number. Because you guys are far better on demand than we are; and we’re supply side guys.

Sir, would there be time for any further questions today?

We’ll take two more questions.

Okay. First, we have Darren Gacicia of KLR Group. Please go ahead.

I’ve been writing a lot, couple of months about non-OPEC rig counts being down, now it looks like it’s going to be closer to 40% and thinking it about that having an impact on production; it doesn’t seem to be in IEA numbers. Today you’ve increased your decline rate forecast to 3.3% from 3.1%; in this last quarter, you did it up from 2.5%. What I really wanted to get to is, what are the drivers that are bringing that up; is it looking at what’s happening with the rig counts; is there other things that you think are happening with the way people are managing the reservoirs that are changing the decline rates; is it just maintenance expenditure alone? Can you tell us a little about the component of what leads you up that decline rate?

Yes, I think you -- Darren, I think you touched on all three of them. Certainly, the lack of new drilling and fresh production coming on, probably then followed closely by the lack of production maintenance projects undergoing, and then thirdly the delay in the start of enhanced oil recovery projects that are needed to bolster that. So, you add those three together. I think still the biggest component is the drill bit and then followed by lack of maintenance CapEx and then delays on enhancement or recovery projects. So, you add those into the mix and that’s why we’ve upped from 2.5 to 3.1 now to 3.3.

Do you think that since the international activities are down to recover, the bigger lag given investment [ph] cycles, North America we’ve been betting it around on the calls, a little of the wildcard in terms of how quickly that comes back depending on the price recovery. Does the propensity of that 3.3 have the potential to continue to go up higher, the longer the activities stays at depressed levels? I’m just trying to get a sense, [Indiscernible] revision track yet, [indiscernible] expect that to continue to decline according to what you are thoughts are?

Yes, in current activity levels absolutely, positively that will continue to increase.

Does that inherently imply that the IEA numbers for international production is probably needed to come down?

Our prediction is that they will come down.

And last question will come from Brandon Dobell of William Blair. Please go ahead.

Maybe some color on how you guys think about the stage count per well dynamics. I know the general trend obviously up. Do you think that trend is stalled given spending constraints at a higher oil price; do you see stage count well accelerating maintenance in trajectory, just trying to get a feel for how that curve may look in a recovery scenario for oil prices?

We still think they increase. You have some fairly sophisticated operators that are now drilling 12,000-foot laterals and using 60 stages. We talk to those two and three years ago to the amazement of folks. And so, we still see that continuing. And so, longer laterals, more stages, higher degrees of profit. That is the recipe for success.

The spending constraint of last year or so; has it caused people to take a slower path up on trying to get to what some of those leading edge producers are in terms of stage count and you kind of say we’ll stick here for a while then think should better will accelerate toward where those leading edge guys are or is there still pretty steady increase overall?

No. I think you are right on. That has certainly slowed the innovation on completion and completion design and that entails the longer laterals in the more stages.

This concludes our question-and-answer session. I would like to turn the conference back over to David Demshur for any closing remarks.

Thanks Andrew. So in summary, Core’s operations continue to position the Company for slightly lower activity levels in the Q2 and we know that significant challenge is away. However, we have never been better positioned operational and technologically to help our clients maintain and expand their existing production base. We remain uniquely focused and are the most technologically advanced reservoir optimization Company in the oilfield service sector. This positions Core well for the challenges ahead in 2016 and in the 2017. The Company remains committed to industry-leading levels of free cash generation, returns on invested capital with excess capital being returned to our shareholder via dividends and possible opportunistic share repurchases. So, in closing, we’d like to thank all of our shareholders and the analysts that follow Core. And as already mentioned by Monty Davis, the executive management and Board of Core Laboratories give special thanks to our worldwide employees that have made our results possible. We are proud to be associated with their continuing achievements. So, thanks for spending your morning with us, and we look forward to our next update. Good bye for now.

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.