Free Cash Flow, V-Shaped Recovery, Decline Curves, Balance Coming 2H 2016
- EPS $0.37, ex-FX
- FCF $43.2 million – share count 42.5 million
- Paid $23.3 million in dividends, lowered debt by $24.8 million
- Projects Q2 2016 to be the bottom of “V-Shaped” recovery
- Revenues 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%
Core Lab Business Segment Results
- Reservoir Description – revenues of $101.5 million were down 11.5% from the fourth quarter. Operating earnings of $18.7 million yielded operating margins of 18.4%.
- Production Enhancement – revenues for the first quarter of $44.1 million were down 22% from Q4 compared to the North American rig count, which was down 35%. Operating earnings of $4.5 million yielded operating margins of 10.1%.
- Reservoir Management – earned revenue of $8 million in Q1 and operating margins of 6.8%.
Healthy Dose of Free Cash Flow
In its Q1 conference call Core Laboratories CEO David Demshur pointed out that the company’s free cash flow for the first quarter nearly tripled net income. “Core converted over $0.28 of every 2016 first quarter revenue dollar into free cash flow, leading all oilfield service companies,” Demshur said in today’s earnings call.
Core Lab Chief Accounting Officer Chris Hill said, “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 companies’ 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 ten of the last 14 years.”
Core produced return on invested capital of 27%. “Producing an industry-leading ROIC has not happened by chance,” Demshur emphasized.
Core returned $23 million to shareholders through its 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,” Demshur said.
Core CFO Dick Bergmark said that 2Q 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 $400 million bank revolving credit facility remains available as we continue to be … in full compliance with terms and conditions of that facility. All operational guidance excludes any foreign currency translations, shares repurchased other than those we’ve already disclosed, and any further restructuring or similar expenses, and does assume an effective tax rate of 14%,” Bergmark said.
Demshur referenced the company’s decision to close its operations in Venezuela in 2013. “A real-time concern for investors is the exposure of companies to the Venezuelan market,” Demsur said. “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 Mexico operations over a decade ago.
“Core’s internal risk assessment process determined that long-term risks clearly outweighed long-term value for the Venezuelan market. With 100s of millions of dollars of past write-downs and with over billions of dollars of write-downs to come, we believe that Core made the right and correct decision, protecting long-term return on invested capital goals.”
Oil Supply and Decline Curves – Balance Coming 2H 2016
Core believe 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 a day in March of 2015, and has since fallen by over 600,000 barrels per day, owing to high decline curve rates associated with tight oil reservoirs. Offsetting these sharp production declines have been additions 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 bore 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 the 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 some 20 basis points from earlier estimates. Applying a 3.3% net decline curve rate to the current worldwide crude oil production base of about 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 to the decline curve.”
Conference Call Q&A
Q: Have you noticed any discernible changes in demand for certain products as we’ve gone from the back half of 2015 and saw another dip in oil prices in early 2016? Has there been any shift in certain product lines or certain markets?
CLB: From a macro 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 fluid work revolving around increasing daily production and increasing the 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’ve seen.
Q: You have really no competition in fluid analysis, is that correct?
CLB: Correct. And margins there are indeed better.
Q: Are you getting direct indications from E&Ps that they are getting ready to get more active? Or are in the process of getting more active? And can they turn things around from an activity level that quickly, such that you’re going to have higher revenues in the third quarter?
CLB: What we’re thinking as the year progresses is that it will be the normal seasonal patterns.
So we’re not saying that there is an increase in activity yet from what we expect to be higher oil prices. That will come. What we’re saying is just as the year rolls out that we’re expecting Q3 will be better than Q2, just as it has 12 out of the last 14 years.
Q: 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 assertive use of the technology. Is it combined to biggest and best of breed? Or is it becoming broader than that right now with other resource holders using this technology?
CLB: 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, for instance in the deepwater Gulf of Mexico where you’re 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, being the users. And once you get onshore you find the EOGs, the Pioneer Natural Resources, the Conchos are heavy users, and that is now spreading to some of the smaller independents as well.
Q: I’m curious as to what your views are with regard to the threshold oil price and timeline required to grow U.S. oil output significantly, call it 500,000 barrels per day or higher?
CLB: We believe at 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 of maybe six more months before we start to add toward that 500,000 barrels per day of growth.
Q: You touched 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 seemed as though offshore services and products were somewhere in the ballpark of 40% of 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?
CLB: 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 oil worldwide has fallen from somewhere in the 60%s probably to the low 50%s.
Q: And 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?
CLB: Yes, it 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’re using the information to boost not only daily production, but to make sure they increase ultimate estimated recovery from those fields.
Q: With the seemingly pickup in the number of E&Ps transacting properties, properties changing hands, including the number of private equity shops, does that – how much of an opportunity would that represent to you in terms of being able to characterize and help the buyers of some of these properties understand what they’re buying?
CLB: Because in the Reservoir Management we are seeing more private equity folks than we have seen in quite a while, and it’s for those datasets. 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 of plays all over North America and in the international arena, more of the activity is 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 the price they’re going to sell that for, but we can tell them what the best plays are, and then they’ve got to decide the valuations.
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 in terms of picking up.
Q: 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, correct me if that’s incorrect. 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?
CLB: Usually, the canary in the coal mine is the Reservoir Description group. So we would see the delta take place because we haven’t had that much of a downshift internationally, that would have to be North America to where we would see the delta on the uptick. And it could happen commensurately with production enhancement as you get either recompletions, refracs or the completion of some of the DUCs.
Q: And have you seen any signs of the DUC inventory starting to be drawn down yet?
CLB: Yes, I would that that’s not a material at this point, but actually the DUC count, let’s just say that background DUCs is about 1,500 and right now there’s probably a little over 4,000. We’re starting to see that get chiseled away.
Q: 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? How many of the 2000 fields that you’re targeting, Reservoir Description are on now? And are more oil companies now insourcing work or outsourcing work to Core Labs? And then similarly on the Production Enhancement segment, what are market share trends like in North America and international?
CLB: If you look at Reservoir Description, the last count we had is were active on about 1,250 fields. We still have commitments to do work in those fields, although some of that work flow may have slowed down or been postponed for a period of time. On more of an acute side — well, before we leave Reservoir Description, we are seeing some of the majors do more of their work in-house, because they are at lower levels of work. So if we cede 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.
Q: This is the first quarter where we haven’t seen share buybacks in a long time, where you’re using the free cash flow after the dividend to pay down debt. And now your leverage ratio is over half a turn within the covenant. So what is the level that you guys, could you just remind us, are comfortable with? And when could we expect you to return back to the market to buy back shares before the end of the year?
CLB: What we’re doing right now is behaving similar to what we did in 2008/2009, where we actually back then 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’ll continue to pay the dividend. 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’re not saying we’ve suspended the program, we’ve just said currently we’re going to pay the dividend and pay down debt.
Q: When we look at the V bottom, can you help us maybe understand what the upward slope of the V may look like from a rig count, oil price, and then ultimately production perspective? The downslope of the V has been very steep, very long, but obviously there’s going to be a lot of constraints to re-ramp production given the deep cuts that have occurred primarily in North America. I’m just hoping to maybe get some color into how this V, or the upward slope of this V unfolds in your crystal ball with respect to domestic, international rig counts, spending levels activity and maybe offer you an opportunity to hedge a little bit here in what, in this outlook if there’s anything that can derail the outlook of a V-shaped recovery as we head into the back half of the year.
CLB: 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, for 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 upslope of the V-shape. Internationally, activity levels have been down but not anywhere near as sharply as they had been in North America. So really the controlling factor on that upside is going to be the price of crude and the response in activity levels in North America. So other than that, I don’t think we can get more granular.
Q: So I guess a lot of the focus is in U.S. production and activity. But in light of the failed meetings really recently in Doha and the rhetoric from Russia and Saudi that they can increase their output, there’s obviously challenges ongoing in Libya and other places in North Africa, but how do you think about the potential for further production increases out of OPEC and other major players? And what could that possibly do to the V-shape 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?
CLB: 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 back end of that is you have peace that breaks out everywhere, and you get Libyan production back, and those that are off the 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.
Q: Maybe some color on how you guys think about the stage count per well dynamics? I know there’s a general trend obviously up. Do you think that trend has stalled, given spending constraints? Do you see stage count per well accelerating and maintain the same trajectory? I’m just trying to get a feel for how that curve may look in a recovery scenario for oil prices.
CLB: We still think they increase. You have some fairly sophisticated operators that are now driving 12,000-foot laterals and using 60 stages. We talked to this two and three years ago, to the amazement of folks. And so we still see that continuing. So longer laterals longer laterals, more stages, higher degrees of profit. That is the recipe for success.