Core Laboratories Inc (CLB) 2015 Q4 法說會逐字稿

Good morning, and welcome to the Core Laboratories' fourth quarter 2015 earnings conference call.

(Operator Instructions)

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

Thank you, Andrew. Good morning in North America, good afternoon in Europe and good evening in Asia-Pacific. We would like to welcome all of our shareholders, analysts and most importantly, our employees, to Core Laboratories' fourth quarter 2015 earnings conference call.

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

Chris will start by making remarks regarding forward-looking statements. Then we'll come back and give a review of the current macro environment, updating worldwide crude oil supply thoughts and then quickly touch on Core's three financial tenets by which the Company employs to build long-term shareholder value. Chris will follow with a detailed financial overview and additional comments regarding building shareholder value followed by Dick Bergmark commenting on Core's first quarter 2016 outlook and a general industry outlook as it pertains to Core's prospects in 2016.

Then Monty will go over Core's three operating segments, detailing our progress and then discussing our continued successful introduction of new Core lab technologies as they relate to completing, stimulating and producing wells, and then highlighting some of Core's operations in major projects worldwide. Then we will open the phones for a Q&A session. I'll now turn it over to Chris for remarks regarding forward-looking statements. Chris?

Thanks, David. Before we start the conference this morning, I will mention that some of the statements that we make during this call may include projections, estimates and other forward-looking information. This would include any discussion of the Company's business outlook.

These types of forward-looking statements are subject to a number of risks and uncertainties relating to the oil and gas industry, business conditions, international markets, international political climate and other factors including those discussed in our 34-F 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 our 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, 2014, as well as other reports and registration statements filed by us with the SEC.

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

Thanks, Chris. I'd like to talk about some of our current macro views and then touch on the three financial tenants. Core believes that the worldwide crude oil supply and demand markets will balance in the second half of 2016. On the crude oil supply side, US unconventional production peaked at approximately 5.5 million barrels of oil per day in March of 2015, and has since fallen by over 600,000 barrels a day owing to high decline curve rates associated with tight oil reservoirs.

Offsetting these sharp production declines have been surprising and unsustainable additions of over 250,000 barrels of day from deepwater Gulf of Mexico projects that were commissioned several years ago and that beared fruit in late 2015. The sharp declines from US land production will continue into 2016 and Core believes these decreases could reach 900,000 barrels a day by the year-end 2016.

Lower levels of new wells and delayed production maintenance will exacerbate this 2016 falling US land production. Moreover, the sharp gains from legacy deepwater Gulf of Mexico projects will not materialize in 2016 to offset the significant decreases in US land production as they did in late 2015. Core estimates that the current production decline curve rate for US production is approximately 7.8% net, which will expand as 2016 progresses and could reach 10% net by the end of the year 2016.

Globally, Core estimates that crude oil production decline curve has expanded to 3.1% net, up some 60 basis points from year earlier estimates. Applying the 3.1% net decline curve rate to the worldwide crude oil production base of approximately 85 million barrels a day, means that the plant will need to produce approximately 2.6 million new barrels by this date next year to maintain current worldwide production totals.

With the long-term worldwide spare capacity nearing zero, Core believes that worldwide producers will not be able to offset the estimated 3.1% net production decline curve rate in 2016, leading to falling global crude oil production by the second half of 2016. Therefore, Core believes crude oil markets rationalize in the second half of 2016 and price stability, followed by price increases return to the energy complex. Remember, the immutable laws of physics and thermodynamics mean that the crude oil production decline curve always wins and that it never sleeps.

On the demand side on the crude oil market, the IA is still calling for increased demand in 2016 of approximately 1.2 million barrels per day, notwithstanding daily news out of China regarding their economic activity. Supply and demand will balance as they all have in the 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 in history in 2016.

Applying these tenants lead Core to be the top performing company in the Philadelphia oilfield services index in 2015. During the fourth quarter of 2015, Core generated free cash flow that exceeded net income for the fifth consecutive quarter. Free cash flow for all of 2015, equaled 140% of net income in 2015 ex-items, clearly the best in all oilfield services.

Moreover, Core converted over $0.24 of every 2015 revenue dollar into free cash flow. Again, leading all oilfield services companies. Also in the fourth quarter of 2015, Core once again produced oil industry leading return on investment capital for the 26th consecutive quarter topping an ROIC of 40%. Finally during the fourth quarter of 2015, Core returned over $38 million back to our shareholders and over $4.50 per common share in 2015, via dividends and share count reduction.

At year's end 2015, Core had reduced its share count to an 18-year low having returned over $53 per diluted share over the last 13-year period. Core will continue its share repurchase program in the first quarter of 2016. I will now turn it back over to Chris for a detailed financial review. Chris?

Thanks, David. Looking at the income statement, revenues were $182.7 million in the fourth quarter, slightly higher than our guidance and down only 7% sequentially. Comparing favorably to the global rig count, which is down more than 9%. For the full-year, revenues were $798 million, down 27% but on a constant currency basis, down only 23% and a nice outcome considering the global rig count was down almost 35% over the same period.

Of these revenues services for the quarter, $142 million, which are more international and are down only 5% sequentially. This is a very favorable outcome when you consider the average crude oil price fell 20% during the quarter and global rig count decreased 9%. For the full-year, service revenues were at $612 million, down about 22% from last year. However, a better performance compared to industry given average crude oil prices decreased almost 50% and again, the average global rig count was down almost 35% during 2015.

Product sales, which are tied more to North America activity, were $40.7 million for the quarter, down 14% sequentially but comparing favorably to US land rig count, which is down 16%. For the full-year, product sales were $85.6 million, compared to $304.4 million in the prior year. A decrease of 39%, but in an environment where average rig count in North America was down 48% compared to last year.

Moving on to cost of services for the quarter, or 65.1% of revenue, up sequentially from 62.7% in the prior quarter. For the full-year, cost of services were 63.4% and up from 57.6% in 2014. Although this was up slightly for the quarter and the year, our service operating margins continued to be strong, which confirms pricing did not play a big part in our lower margins. Rather, it was the absorption of our fixed cost structure on lower revenue.

Cost of sales in the fourth quarter was 79.4% of revenue, which was up from the 74.1% in the third quarter. For the full-year, cost of sales was also up at 78.1% compared to 70.9% last year, and again, this is due to absorption of our fixed costs over lower revenues.

G&A for the quarter was $12.3 million, comparable with prior quarters. For the year 2015, G&A was $49.7 million, and up from $45.7 million in the prior year.

Depreciation and amortization for the quarter was $7 million, comparable sequentially and with that incurred for the last several quarters. For the full-year 2015, depreciation and amortization was $27.5 million, so just up slightly from $26.7 million in the prior year. Considering capital expenditures in 2015, and with our anticipated capital programs for next year, we would expect depreciation to continue on these approximate run rates into next year.

Severance and other charges, as mentioned in our earnings release, we have taken additional actions during the quarter to appropriately line our cost structure and as a result, we have recorded $15.8 million in charges for severance compensation, asset impairment and other charges, all of which were recorded during the fourth quarter. Other expense this year primarily includes foreign exchange losses of $4.5 million for the year, however, for the fourth quarter, it was negligible.

The guidance we gave on our last call and past calls specifically excluded the impact of any FX gains or losses, so accordingly, our discussion today excludes any foreign exchange gain or loss for current and prior periods. So to conform with our guidance, EBIT, ex items for the quarter, was $39.5 million and represents best-in-class EBIT margin of 21.6%. For the full-year 2015, EBIT ex items, was $188.5 million and also generated industry-leading margin of 23.6% for the full-year.

Income tax expense ex items in the quarter, was $8.3 million, at an effective tax rate of 23%. Our full-year annual effective tax rate was a little under 23%. We expect our effective tax rate in Q1 2016, to be approximately 22.5%.

Debt income ex items for the quarter, was $27.7 million, down from $35.4 million last quarter. For the full-year 2015, ex items, it was $136.1 million, and GAAP net income was $15.4 million for the quarter, and $114.8 million for the year.

Earnings per diluted share ex items, was $0.65 for the quarter compared to our prior guidance of $0.63 to $0.67 per share. EPS for the full-year, ex items, was $3.17 and GAAP EPS for 2015, was $2.68. 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 recorded balances.

Cash, $22.5 million, compared to the prior year end balance of $23.4 million. Receivables stood at $145.7 million, down about $7 million this quarter, and down from $197.2 million at prior year-end. DSOs for the quarter were 68 days, and 66 days for the full-year of 2015, so up slightly from 65 days in 2014.

Inventory stood at $40.9 million at year-end, down 8% or about $3.6 million sequentially and down over 17% from its peek earlier in the year as we have worked to reduce inventory levels to align our inventory to current product demand. We expect inventory to continue trending down as we move into 2016. For PP&E, intangibles, goodwill and other long-term assets, the only material change during the quarter is the asset impairment charges of $4.9 million, mentioned earlier.

Now on to the liability side of the balance sheet, our long-term debt at year-end, was $433 million, so up slightly from $428 million last quarter-end. Our debt is comprised of our senior notes at $150 million, as well as $283 million under our bank revolving credit facility. The increase in borrowings during the year came as a result of our increased share buy back program. Since the end of the year, we have not made any share repurchases and with that excess cash, we expect to reduce the balance on our revolver to $275 million this Friday.

Shareholders equity, the end of year is a deficit of $23.7 million, down from the prior year end balance of $94 million, primarily due to share repurchases and dividends in excess of net income since the end of last year. As we have previously discussed, 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 also have 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 $4.5 million, so consistent with prior quarters this past year, but down from 2014 levels. For the full-year, they were $22.8 million, down about 38% from $36.6 million in 2014. The Company anticipates that its 2016 capital expenditure program will be less than 2015. However, if oilfield activities do pick up, Core has the ability to increase its investments in support of these strengthening activities.

Looking at cash flow. In the fourth quarter, cash flow from operating activities was $49.3 million, and after paying for our $4.5 million in CapEx, our free cash flow in Q4 was $44.8 million and an industry-leading $0.245 for every dollar of revenue earned. In the quarter, we used our cash to pay $23.3 million in dividends and to repurchase approximately 133,000 shares. For the full-year 2015, cash flow from operating activities was $219.1 million, while free cash flow after paying for our CapEx program, was $196.3 million. So almost $0.25 for every revenue dollar.

For the full-year, we used our free cash flow and borrowings under our credit facility to pay $94.2 million in dividends and $159.7 million in share repurchases. Our free cash flow conversion ratio, which is free cash flow divided by net income ex items, continues to be one of the highest in the industry at 144% for 2015.

We believe this is an important metric for shareholders when comparing companies financial results, particularly for those shareholders who utilize discounted cash flow models to access valuations. In 2015, our free cash flow was higher than our net income as it has been for 10 out of the last 14 years. I will now turn it over to Dick for an update on our guidance and outlook

Thanks, Chris. In 2016 at current activity levels in North America, year-over-year production declines of over 900,000 barrels of oil per day are expected in Canada and the US, while international production levels are expected to continue to decline modestly. We believe that recent downward production revisions in Mexico and offshore Eastern South America confirm these views and that should precipitate higher commodity prices and the beginning of a recovery in our business in the second half of 2016.

In spite of that view of the recovery in the second half of 2016, for the first quarter of 2016, we project further industry activity declines in North America tight oil plays as US rig count is already down from year-end 2015 levels by approximately 10%. Oil company 2016 operating budgets are still uncertain, which will force a North America rig count to further contract. Additionally, international activity is projected to be down in the first half of 2016.

In response to these lower industry activity levels, we continued to reduce our internal operating cost through further automation of service and product offerings and various multi-skilling programs, asset rationalization and employee reductions. We'll continue to right-size the operations until energy markets balance and we'll then respond to lower supplies and higher demands.

To give you a broad directional perspective by segment, we believe the sequential impact to our reservoir description segments revenue will be reflective of that lower international activity expected in 2016, perhaps causing that revenue to decline approximately 7% in the first quarter of 2016, compared to the fourth quarter of 2015.

Our production enhancement segment will also be impacted as a result of the continuing slowdown in North America, causing that revenue to fall sequentially by approximately 9%. Our revenue management segments revenue is expected to decline 25% sequentially given the discretionary nature of our joint industry projects. Therefore, on a consolidated basis, we project first quarter 2016 revenues to fall sequentially approximately 10% to $164 million, with operating income falling in the range of approximately $26 million to $28 million.

Sequential quarterly decremental margins are expected to be approximately 65% as a result of continuing steps being taken to optimize our operational structure to match the global needs of our clients. First quarter 2016 EPS, is projected to be approximately $0.41 to $0.43. For the remainder of 2016, we envision a return to more typical seasonal business patterns with activity increasing after spring break up in Canada in the second quarter with sequential quarterly improvements through the end of year.

Because of our working capital management programs, our free cash flow is projected to exceed net income as well as the amount of our dividend providing liquidity for our future quarterly dividend payments and the opportunistic continuation of our stock repurchase program. Moreover, our $400 million bank credit facility remains available as we continue to be, and expect to be going forward, in full compliance with the terms and conditions of the facility. Our operational guidance excludes any foreign currency translations, shares repurchased, other than those already disclosed, any further severance and other charges, and assumes an effective tax rate of 22.5%.

Let's talk a moment about decrementals, both in this cycle and in comparison to other companies. We find ourselves in a bit of a repeat of what happened at the beginning of last year. We are facing another leg-down in activity which is causing us and others in the oil service base to make further rounds of cost reductions. And for us, being people serviced and very asset light, that means we reduce our costs by reducing head count. That can only be done when projects are completed and results delivered to our clients. It can't be done on the first day of a quarter.

Asset heavy companies, however, like those large ones who have already reported, can impact their decrementals by writing off assets that no longer have commercial value. And we have already heard about billions written off on calls the past week or so. By writing off assets, depreciation is immediately reduced. So if those assets are written off with the effect from the first day of a quarter, then depreciation is immediately removed, which gives the appearance of improved decrementals.

What is being missed is that optical benefit of lower decrementals came at the expense of prior investment dollars being written off as commercially unviable. Our decrementals for the most part are not created with that baggage of writing off prior investment. So just be mindful that headline decremental margins are not necessarily comparable across companies. Okay. Let's turn the call now over to Monty for an operational review.

Thank you, Dick. Fourth quarter revenues were down 7.4% sequentially from the third quarter, to $182.7 million. Operating earnings ex items, were $39.5 million yielding an operating margin of 21.6%.

Energy Point Research has completed their annual 2015 customer satisfaction survey of a broad spectrum of oil and gas companies, and Core Laboratories ranked first overall in oilfield services as well as first in several categories. Core Lab ranked first in core and fluid analysis, as we have every year that this category has been surveyed starting in 2008.

2015 was also our safest operating year ever due to the efforts of all of our employees. We congratulate our 4,400 employees worldwide on these achievements. We also thank all of our employees for working to deliver value to our clients every day.

Reservoir description revenues for the fourth quarter of $114.8 million, were down 2.7% sequentially. Operating and earnings of $28.6 million, yielded operating margins of 24.9%. An international oil company has commenced an extensive coring program to evaluate reservoir properties on a potential giant oilfield discovery offshore South America. Core Lab has been working with this client since the inception of the analytical program.

Core Lab's measurements will be used to define rock properties, determine reservoir fluid saturations and measure flow properties of these reservoirs. These will form the foundation for calculating hydrocarbon volume in place and the production potential of the various reservoir zones.

Our geological staff is helping the operator understand detailed rock properties and reservoir heterogeneity. As wells are planned and core and fluids are acquired, this program will expand over the next several years. As the lab analytical program proceeds, we'll conduct reservoir testing -- we'll conduct testing at reservoir conditions that will provide the physical basis for modeling reservoir performance and be used to calibrate down-hole loss.

In the Middle East, Core Lab continues to support our clients through newly renewed multi-year projects in Qatar, Iraq and the United Arab Emirates, which compliment the existing long-term projects in other countries in the region. During the fourth quarter, laboratory capabilities in Abu Dhabi were expanded through capital investment and flow testing under reservoir temperature and pressure.

This proprietary equipment, designed and manufactured by Core Lab, will determine relative permeability relationships and be used to optimize the design of enhanced oil recovery programs. Core Lab has demonstrated that safety mapping in the oil industry is an appropriate methodology to enhance safety awareness throughout the industry with the aim to evaluate areas of specific risk.

Core Lab has introduced an internally developed safety monitoring tool called Safe Site. This newly developed safety mapping technology is currently used at an increasing number of field locations where we operate. These unique data sets are being shared with operators to support and initiate ongoing improvement measures for safer oilfield operations. Our customers have recognized the added value of such systems as they significantly contribute to minimizing the risk of expensive incidents and potential reputation damage.

Production enhancement fourth quarter revenue of $56.6 million yielded $7.3 million in operating earnings and a 13% operating margin. Core Lab is playing a major role in addressing the technological challenges of the deepwater Gulf of Mexico with completion diagnostic service.

Core Lab provided completion diagnostic services in several major Gulf of Mexico deepwater fields, including the lower tertiary play in the Walker Ridge area, the deepwater Keathley Canyon area and three Mississippi Canyon fields. Core's completion diagnostics helped prove the value of a single trip multi-zone stimulation technology that enabled the operator to cut the completion time to 18 hours to 20 hours per zone, resulting in a major savings in rig time.

During the quarter, production enhancement operations performed services in the ongoing Wolf Camp hydraulic fracturing test site program joint industry project. This project is managed by the gas technology institute with significant funding from the Department of Energy. Core is providing all of the completion diagnostic services, permanent down-hole centers and core analysis for this project. Ultimately, the data from this project will help answer many technical questions about stimulation and development optimization which can be applied to various shale plays.

During the current reduction in North America completions, our customers are evaluating technology for well site efficiency and production enhancement. Currently Core's production enhancement division is gaining traction on numerous patented and proprietary products supported by science and testing.

During the fourth quarter, an Eagle Ford operator completed a multistage well utilizing Core's per frac erode charges on numerous stages versus an alternative charge on other stages. The operator noted that during frac operations, the intervals perpetrated with per frac erode charges broke down at significantly lower pumping pressure.

In understanding the Bernoulli equation and its impact on the drawdown pressure across an individual perforation, our engineers have been able to optimize the uniformity of the whole diameter around the production casing, reducing the friction pressure, resulting in lower hydraulic horse power provided for formation breakdown, over 30% in some cases. Lower horse power reduces the pumping costs while more uniform hole size facilitates proppant placement evenly throughout each curve cluster, positively contributing to the fracture treatment.

More than 300,000 per frac erode technology charges were used in the fourth quarter by various customers throughout North America, demonstrating the high acceptance of this 2015 technology. Outside North America, Core Lab's global footprint and operational support provided perforating charges and gun systems to numerous international and national oil companies in over 60 countries. These customers often required deeper penetrating perforations for natural unfractured completions.

Core Lab's HERO HR hard rock plan of charges and gun systems provide industry-leading penetration in addition to our patented low debris, high wolfram-molybdenum technology. This combination of penetration and low debris performance resulting in a 33% year-over-year increase in customer usage. With our industry leading deepest penetrating 39-gram, 69.3 inch penetration HERO HR having the greatest usage ever.

Fourth quarter reservoir management revenue was $11.4 million, and operating earnings of $3.7 million, yielded operating margins of 32.2%. Core Lab had numerous sales for our geological studies during the quarter. Much of this activity is driven by private equity frac companies that are using the studies to expedite the evaluation process and minimize the risk associated with acquiring new assets. Our customers recognize that it is considerable value in having access to good reservoir and engineering data before they make multi-million or billion-dollar decisions.

Core Lab has developed new products that add value for its clients by reexamining and analyzing the existing cores. The focus of this new work is on optimizing completion practices. We are helping them implement more efficient and more effective hydraulic fracture stimulations by integrating new geological and engineering data.

Creating a geological and rock mechanical line from an existing core is a low-cost process that can eliminate stage failures and save operating companies hundreds of thousands of dollars for each completion. It can also provide answers on the best methods to refrac existing wells to maximize production and increase reserves.

Outside of North America, West Africa and the East Coast of South America continue to be the focus of potential development activity. Recent offshore discoveries in Senegal, Guiana, the Ivory Coast and the Sierra Basin of Brazil have renewed interest in these play areas.

Core Lab is either actively working on new geological studies in these areas or has recently completed studies that are available to clients. These studies provide basin-wide geological models for operating companies. They use these models to better understand the geology of their leases, which significantly reduces the risk of drilling very expensive deepwater dry holes.

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

(Operator Instructions)

The first question is from Rob MacKenzie of IBERIA Cap. Please, go ahead

Thanks, guys. Dick or Chris, did I hear you correctly that you expect to have paid down the revolver to $370 million by Friday?

Well, the revolver balance at the end of the year was $283 million, and we expect to pay it down to $275 million by Friday

Okay. Got it. And then the other tranche of your long-term debt remains unchanged?

Yes, that is fixed debt at $150 million.

Right. Okay. And so it seems to me you guys have shifted now. Is this a policy change to spending buybacks here in order to protect the dividend and preserve liquidity?

I wouldn't say it's a policy change. I think it's probably following our policy. Remember, we talked about the dividend being extremely important to us. We want our investors to feel comfortable with it to be able to put it in their valuation models. So for us, the dividend is always first and then the opportunistic nature of our share buybacks would come second. So we don't see a change in that policy.

Okay. And what about, is the prospect of acquisitions in this downturn? Clearly, there are a lot of companies in distress. Is there anything out there that you think might be an interesting bolt-on that would help you be better positioned in the next up cycle?

Rob, one thing about down cycles is better valuations do not make bad companies into good companies. So our perspective is we have not seen good companies to acquire that fit our three segments, so this recent change in valuation really has not changed that. So we don't see acquisitions really adding to this at this moment.

Great. Thanks. Turning to decremental margins, totally understand your comment about how long it takes to reduce the headcount. Given that though, shouldn't we expect to see decremental margins lighten up perhaps in the second quarter as projects wind down and headcount is further reduced?

Yes. I think the analogy is look at last year. So first quarter last year, same thing, high decrementals. Second quarter, we'd gotten the cost out. Actually, we showed incrementals in Q3, as well. So I think that's what we're seeing, is a replay of that as a result of this next leg down. So we need to adjust our cost structure, we'll get those costs out in the first quarter and if activity levels being in the flat, I think you're going to see an improvement as we go forward.

Great. Thanks. I'll turn it back.

Okay, Rob. Thanks.

The next question comes from Ole Slorer of Morgan Stanley. Please go ahead.

Thank you. Just following up on that note, Dick. So you highlighted the usual sort of seasonal pattern once you get after the first quarter, Canada, down a little bit, but margins normalizing. Of course, you highlighted [decrementals] as of last year. Does that mean that the second quarter should be the trough or is it a chance that the first quarter of an earnings standpoint was the trough?

It could be second quarter is trough depending on the activity levels that we see as a result of the Canadian break-up. But if it's light, this could be the trough quarter. So first or second.

I suppose the silver lining here is that probably not going to be much of Canadian breakup this year. There's just not much to break up.

Yes, not much to break up.

Can we get back to some of the comments you made on the macro side? You highlighted Latin America as a source of declines biting hard in the new production coming on. What is the aura -- maybe seen of oil about the Middle East? There seems to be an enormous debate at the moment about spare capacity in that region and the ability to open taps and let things flow for a very long time without any negative impacts to be seen on CapEx cuts. What is your latest view here?

Ole, on the Middle East, we see spare capacity there across the Middle East at a very low amount. Actually, long-term spare capacity, we see near zero. You could probably generate another one million barrels or 1.5 million barrels on a short-term basis. But on a long-term basis, we would put spare capacity nearing zero. In South America, we see continued declines in production in Venezuela and Colombia and in Ecuador, with maybe some flattening of production in Argentina.

Okay. Well, thanks for that and thanks for the clarification around the quarter. I'll hand it back here.

Okay, Ole. Thank you.

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

Good morning, fellows.

Good morning, Chase.

Bear with me. I'm losing my voice, so I apologize about that. So I guess the first thing I want to hit, on the first quarter, margin guidance, 16%, 17% seems to be the implied guidance. Can you help us understand the moving parts when we look at the sub segments?

Yes. When you think about the three segments that we have, reservoir description being the most international. And so, when we gave our broad directional views by segment, you could see it being the least impacted of the three segments. But our production enhancement group, clearly more North America focused, that's where we're seeing or expecting the largest decline in revenues. And we suggested maybe 9% on a sequential basis in Q1 for production enhancement.

And then our reservoir management group, remember, these are consortium studies, joint industry projects for the most part. Because they are very discretional in nature by our oil companies' clients, we're expecting that group to probably fall in the 25% sequential. So broadly speaking, add that all up together, around a 10% decline in revenues sequentially.

Okay. And so how confident are you that reservoir description margins remain above 20% in the first quarter?

I would say we're pretty confident

Yes. And, Chase, as Dick said earlier, I think we see a bit of a replay from last year where we may have trough margins Q1, trough revenues Q2, or maybe not, depending on, as Ole said, the size of the breakup in Canada. One of the downside of giving guidance on a quarterly basis is, I think we're one of the few companies that do that. We have confidence that we know what our business is going to track for the next 90 days out, where a lot of companies will not give that guidance for the pure reason is their businesses are not known enough for them to be able to make that projection. So, for us, the projection that we give in our history will bear this out, that usually the guidance that we give is either smack on or a little bit on the light side.

Okay. All right. Last one for me is, I've gotten a lot of questions around the dividend and the sustainability of the dividend through the downturn. It sounds like that you guys are defending it and so I guess I get the question about, what is your comfort level and when we look at leverage metrics and we think about the dividend?

Just a little background for those who are not necessarily up to speed on it, our covenant metrics for our bank facility, 2.5 times EBITDA is our debt limit. But remember, that's not necessarily a GAAP EBITDA number. They are your normal customary and usual pro forma adjustments to that.

So we're seeing, when we look out through the rest of this year, we're not coming close to that 2.5 times. So we don't see a need to go to our bank group to increase that ratio. Because if we do, it means our pricing grid is going to higher. So we'll have to pay more in interest for the amount of debt that we have outstanding. We're not interested in doing that. So we're going to manage the business to stay below that 2.5 times and we'll be able to protect the dividend at the same time.

Okay. And so just to be clear, if you were to remain at what you guys do for the first quarter in EBITDA, you would not -- through 2016, you would not come close to the 2.5 times covenant? Is that fair?

That's right. So you could use that as a stress test. Remember what Chris said we're doing on Friday, we're paying down debt. We generate free cash, so we have the ability to pay down debt as well. That dramatically impacts that ratio. So don't think of that ratio as being only one variable in it. For us, they're two. We can pay down debt.

Chase, to your point, if you apply the stress test, you could get up to $350 million of room on the borrowing side for our revolver. So will not -- even if you use that stress test, we'll not approach those limits.

Awesome. Great to hear. Thanks, fellows.

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

Good morning, guys.

Good morning, Blake

I wanted to touch on a couple of themes within the segments that have been highlighted in the last couple of earnings releases. Starting with reservoir description and the digital rock characterization, all of this is highlighted. What does it mean commercially to Core Labs, just to be clear? Is this protecting your coring share?

Is it enhancing the need or desire for clients to core in areas where they may have abandoned taking new core? Is it driving a need to redefine cores that are already polled and is all of that -- are you telling us that may be offset in erosion or some of the erosion or what had been a static kind of coring contribution to your overall reservoir description segment?

This is Monty. The digital rock characterization service that we're offering is a very high-tech in-depth microscopic look into the small samples of rock which can come from a core or can come from, in some cases, from cuttings. And we look at those and can give the customer a quick determination of some basic characteristics that they are looking for to let them know about the reservoir they've drilled into. This is not a replacement for a detailed in-depth core analysis where we're looking at flow under reservoir conditions. It doesn't replace the high-tech core analysis that we're doing. What it does, is gives them a quick look at what they have got, which is important for their programs to continue on or deviate into other areas.

This has been well-received. It's a growing service. It is also a nicely profitable service. It's a very good margin business for us. We're expanding. We've expanded in US, South America, we mentioned Canada in the press release. We're in the Middle East in Abu Dhabi. We're looking at further expansion in the Middle East at this time. We're talking to a customer about that and that probably will be a first or second-quarter announcement. We're then looking -- we've got coverage in the Far East.

So it's something that's catching on and the way that we have done it, which base our methodologies -- you have got to have an ability to develop programs based on real knowledge. Meaning the millions of feet of real core that we have processed and that we know what we're seeing when we look at these things with a high resolution CAT scan. That comparison gives us a unique ability and we've made the most of it, which it's a very nice new product for us and we're very happy with the growth and the profitability of it.

A little bit more color on the reservoir description side. We're seeing definitely a decrease in the amount of rock being cut with low commodity prices. Our reservoir fluids business is holding quite nicely.

Okay. That's great. And thanks, Monty. That's exactly what I was looking for in terms of the descriptive of where this is really applied.

Switching over to the production enhancement segment. The last couple of quarters really highlighting some charged excesses and very high volumes. I just want to be clear that I think we all understand that the content per well is increasing in terms of your charge franchise. Would you say that the material you are selling per stage is also gaining in intensity?

Well, the charges is where the technology in this business lies, in the perforating end of the business. And we've done extremely well in charge, production charge sales, charge development with the new charges, we're constantly coming up with new technology. And that part of the business is doing very well compared for the more hardware parts of the business, which is a lower technology, not that it's not important. It's just not got the technical levels and there's more competition in that area. So we're gaining share, we believe, in the charge part due to technology.

Okay. Thanks for that. And just, if I can sneak one quick one in on the charge side -- excuse me, on the severance side in the reservoir description business. How much would you characterize as being a pure kind of need for scale or reduction versus the shift to automation and multi-skilling and the weighting of that? And thanks for the time. I'll hang up and listen

Blake, both of those are going to certainly come into play. We certainly have seen productivity gains from automation worldwide, both on the rocks and the fluid side, also with the multi-skilling programs in there. But just from the sheer amount of work that we're not seeing on the rock side, we need further reductions and we'll scale to that level and hopefully get there by the end of the first quarter.

(Operator Instructions)

The next question comes from Quirijn Mulder of ING. Please go ahead.

Good morning, folks. Quirijn from Amsterdam. A couple of questions. My first question is about the decremental margin of 65%. Is also the incremental margin then 65% or should we look at it differently? That's my question for Richard. And then my question for David is, your estimate about a 3.1% depletion rate, I do not exactly understand that because if the US is producing less and the US is in difficult high depletion area, including Gulf of Mexico, but especially shale, how do you come then to a 3.1%?

Go ahead, Dick. You go first on the decrementals.

On the incremental side, think about a recovery. We'll have incremental revenues but we will not be adding cost at the beginning of a recovery. And in previous recoveries, we have had incrementals in that range and we've talked about that in the past, that we're not aware of any reason why that would not repeat itself. Because we'll not add cost but we'll have incremental revenues and for us to create that incremental test in a laboratory environment, it's really the cost of the consumables. So the chemicals, the glassware, the gases that are used to create the test results, that's really our only cost. So we'd expect incrementals to mirror that on the upside of a cycle.

And Q1, the new net decline curve rate worldwide, we had originally used a 2.5% net for several years. But when you look at adding in substantial amounts of high decline curve rate net from the US, essentially you have using a, around the world, a 2.5% net on about 73 million barrels and a 7.8% net on about 9 million barrels out of the US. When you average weight that in, that brings you to a new global net decline curve rate of about 3.1%. So it's up 60 basis points from what we used about a year ago.

Okay. Thank you.

Okay, Q.

The final questioner today will be Darren Gacicia of KLR Group. Please go ahead

Good morning. I wanted to ask, reservoir description, always known it to be a business that much more development versus exploration oriented. So when I think about the kind of guide down and high single-digits, where does that come from? Is it people shifting mix to the lower end of the pricing book? Does it come from a reduced -- does [delve] activity directly correlate to it?

Because it seems like once you're in a field, you're sticky. So I'm just trying to understand a more granular mechanics of where business kind of falls off, when that starts turning to the downside? So maybe I can understand how things went back up on the upside.

Good observation there, Darren. Certainly you are correct, reservoir description is very much more engaged in the development and maintenance, production maintenance of fields worldwide and tied into enhanced oil recovery projects. What we're finding is that a lot of the maintenance CapEx that usually is plowed into fields worldwide has significantly -- our projection is that will be significantly down when we look at the first quarter, second quarter of next year.

One of the other things, Darren, remember, is there's less development (technical difficulty) underway. So those are good projects for us and we're seeing some of those being pushed to the right and waiting for the right (technical difficulty) to make them work.

So when the maintenance goes down, is that generally lower calorie business versus maybe some of the more leading edge things at the higher end of your price book?

No. That's pretty much spread out throughout the price book. It's just an incremental job that generates high incremental margins. So, when you lose that work, of course, the decrementals, until you get the costs out, are going to be pretty biting.

When you think of that cost, are we talking about closing roof line type of changes or people? Because it strikes me that if you have a V-shape recovery starting in the second half, there may be a lag in terms of when activity comes, but activity may come back within a 12-month to 18-month period. How do you manage around that considering you're trying to cut costs at the front end of the forecast, if you will?

Correct. No roof line closures contemplated. It will just be in a high-grading of talent. We're certainly going to keep the capacity to go ahead and ramp back up when the V-shape does occur. Monty?

We also, Darren, we use some furlough. We talked about this on a few calls. We have a furlough mechanism that we use, when appropriate, and what this does is puts people, a certain amount of time off without pay. So we can use that in the US and in Canada.

We use that system so that the people don't lose their jobs. They are just working nine days instead of 10, or four days instead of five, whatever the furlough mechanism that's needed. Or sometimes, there'll be a week or two weeks at a time depending on what works for the employee. So we use that, as well, to try and maintain our structure and our technology, which is in our people.

That's smart. One last nitpick question. With regard to the covenants and the calculation of EBITDA, Dick, you'd mentioned there's a couple of standard adjustments. You may not be able to get super granular and numerically, but can you give me a little bit more of an overview of what goes into those adjustments just as we may think about trying to run that map in our models? How do we want to think about that?

They tend to be your non-cash items.

Got you. Thank you for your time. I really appreciate it.

Okay, Darren. Andrew, we'll take one more question

Thanks very much. We have that question from John Daniel from Simmons & Company. Please go ahead.

Thanks for squeezing me in. Dave, real quick, on your expectations of the second half recovery in your operations, is that based more on your view that oil prices are moving higher in the second half, thus activity follows? Or at this point, do you have specific customers telling you that they have deferred near-term but they're picking up definitively in the back half of year?

A little bit of both. I would say more weighted towards we're a scientific company. We just look at the laws of physics and thermodynamics. We know this crude oil market has to balance. That firms up pricing, leads to price increases. So I would say, we would weight more towards the natural balancing of the markets in pricing and we do have some large clients that are looking to commence some development projects during the second half of 2016. So it's a blending of both. I would weight it 60% to price stability and increasing and 40% from client input that those projects will take place.

Fair enough. Okay. And then, Dick, just one for you on the margins. Hopefully, you can answer this. Assuming we do see the sequential recovery in the back half of the year, at what point do you think we could see your margins, segment margins, return to the Q4 2015 levels? Could that be a 2016 event or is that more 2017?

If you do have the recovery in the second half of 2016, which tends to be gathering a view that's what is going to happen, you can begin to see those margins expand sequentially as we get into the second half of the year.

Yes, because our incrementals coming out of that, because we have cut costs, will certainly be higher than the decrementals going in. And history will bear that out

Right. I'm just curious if at this point you have the confidence, if you will, to get to the Q4 levels again this year?

If it plays out like we think will balance in the crude oil markets, certainly a distinct possibility

Okay. Thank you very much, gentlemen.

Okay, John.

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

Thank you, Andrew. Good job. In summary, Core's operations continue to position the Company for lower activity levels in the first half of 2016, and we know these challenges await. However, we have never been better operationally or technologically positioned to help our clients maintain and expand their existing production bases.

We remain uniquely focused and are the most technologically advanced reservoir optimization company in all the oilfield services sector. 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 shareholder via dividends and opportunistic share repurchases.

In closing, we'd like to thank all of our shareholders and the analysts that follow Core and as already noted by Monty Davis, the Executive Management of Core and the Board of Directors of Core Laboratories, give a special thanks to our worldwide employees that have made these results possible. We are proud to be associated with their continuing achievements. 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.