© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good afternoon. My name is Chantelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Ensign Energy Fourth Quarter Results Conference Call. [Operator Instructions] Bob Geddes, President and Chief Operating Officer, you may begin your conference.
Thanks, Chantelle. Good afternoon, everyone. Thank you for joining us. With us today, we have our executive management team consisting of Ed Kautz, President of U.S. and Latin American Operations; Mike Gray, Vice President and CFO; Michael Nuss, EVP U.S. and Latin American Operations; and Tom Connors, EVP Canada and International East Operations.Before we get going too far, just want to say that Michael Nuss will be managing most of the call today on the notes. Mr. Kautz will be retiring July 1 after close to 25 years with the company. Ed, as you know well, has been instrumental in helping build our U.S. platform into what it is today. He's contributed to over 50% of the revenue for the entire company. So Mike will be talking to the U.S. and Latin American operations on this call. So just to expand on that, though, Mike will be expanding his role as of July 1 to look after the entire U.S. business, consisting mostly of our growing assets but also our directional drilling, well servicing and testing lines of business. Mike Nuss will continue to look after, of course, the Latin America and South American businesses as well. So fourth quarter 2017, no question, the worst is behind this sector as all our year-over-year metrics reflect the strengthening in drilling and well servicing business climate worldwide, supported by a more solid $60 WTI environment. That being said, we started to see some bifurcation in certain markets, mostly driven by geopolitical issues. The U.S., where we do over half our business, we saw regulatory obstacles reduced through 2017. All while in our overregulated Canadian market, we saw oil and gas companies trimmed budgets, reflecting their reduced cash flows, the result of necessary product discounts caused by infrastructure and tax issues.In our other areas of business, in 2017, we saw a stabilized Australia activity worth noting, while Ensign is arguably the newest fleet in Australia with 30% of the country's suite. We enjoyed over 50% market share for active rigs running.In 2017, Argentina is playing out according to plan as our investment in adding 2,000-horsepower rigs into the Neuquén area is serving us well. All these rigs are on long-term contracts. We just recently installed our Edge operating system and controls on one of the rigs down there. In 4 months, the rig was drilling record wells in the area and doing it consistently. While we operate in Venezuela, we only have a few rigs operating, all of which are with the mix of the companies. Mike Nuss will expand in a little more detail on that later.Our Oman business operates about 3 of the 8 rigs in the country on a daily basis. These 3 rigs are tied up on long-term contracts out into 2020.As you know, Ensign operates a fleet of 170 high-spec drill rigs with a high concentration in the most active areas of the U.S., Canada, South America, Australia and Oman market. In 2017, the company added 3 new build ADR drilling rigs to its drilling fleet in the Canada and U.S. markets and modified 8 of our U.S. ADR 1500S to super-spec rigs, all of which are committed to long-term contracts. The company also added 1 new build well servicing rig into the U.S., along rich horizontal completion rigs. Of the 70 rigs in our fleet, 70% are Tier 1 type ADR rigs of varying horsepower. 70 of those are AC ADR type Tier 1 rigs, all capable of having our Ensign Edge Controls installed on them, and 41 of those 70 are the high-demand ADR 1500S. 8 of these are what the industry calls super spec. Super spec, quite defined, is 3 pumps, [ 4 gems ] flocking capabilities, 7,500 psi and an extended racking capacity to 2.5-mile laterals.Dovetailing nicely with our drilling rigs is our directional drilling business and our newly created well side technology business line. After the well is drilled, we have our testing business, and the wells service businesses come on to location after the rig has completed its work to help maximize our revenue opportunity with every wellbore drilled.2017 also was a groundbreaking year for Ensign. We saw Ensign commercialize its new state-of-the-art Edge Controls systems. The Edge system lays the ground for more complex directional guidance advisory and provides a platform for evolving applications. We brought the Edge Controls from concept commercialization in less than 2 years and did that completely with organic internal resources on a small, agile, tactical development and testing. Rigs with Edge Controls are now attracting 25,000 to 30,000 a month [ piece ] for the enhanced controls platform. And in almost all cases, the operator is being charged for install cost.We are also adding a trail of developing apps like ROP Optimizer and [ FuelMizer ], to name a few, which can be downloaded onto any of our rigs with the Edge operating system. This platform operates -- I'm sorry, this platform opens a world of applications that will generate incremental revenue opportunities. Today, we have our Edge Controls systems on 24 of our rigs in North America and Argentina. We have plans to implement the Edge Controls on most our other rigs around the world over the next few years as the market demand continues to develop.With that, I'll turn it over to CFO, Mike Gray, for more a detailed summary of the year, followed by area summaries from Ed, Mike, Tom and then a Q&A afterwards. Thank you. Over to you Mike.
Thanks, Bob. I'll start with the usual disclaimer. Our discussion may include forward-looking statements based upon current expectations that involve a number of business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political, economic and market conditions; crude oil and natural gas prices; foreign currency fluctuations; weather conditions; the company's defense of lawsuits; and ability of oil and natural gas companies to pay accounts receivable balances and raise capital; or other unforeseen conditions, which could impact the use of the services supplied by the company.The modest price recovery of crude and oil and natural gas prices resulted in increased demand for oilfield services in the fourth quarter of 2017 compared to the fourth of 2016. Operating days were up in the fourth quarter of 2017 with Canadian operations experiencing 30% increase; the United States operations, a 48% increase; and international operations showing an 8% decrease in operating days compared to the fourth quarter of 2016. For the years ended December 31, 2017, operating days were up with the Canadian operations experiencing a 50% increase; United States operations, a 53% increase; and international operations showing a 7% decrease in operating days compared to the year ended December 31, 2016.Adjusted EBITDA for the fourth quarter of 2017 was $54.8 million, 6% higher than adjusted EBITDA of $51.7 million in the fourth quarter of 2016. Adjusted EBITDA for the year ended December 31, 2017, was $201.8 million, a 9% increase compared to adjusted EBITDA of $185.2 million generated in the year ended December 31, 2016. The 2017 increase in adjusted EBITDA can be attributed primarily to increased demand for oilfield services caused by a modest price recovery of crude oil and natural gas commodity prices compared to the same period for the prior year.The company generated revenue of $270 million in the fourth quarter of 2017, a 15% increase compared to revenue of $234 million generated in the fourth quarter of the prior year. For the year ended December 31, 2017, the company generated revenues of $1,000.7 million, a 16% increase compared to revenue of $859.7 million generated in the prior year.Gross margin decreased to $63.3 million, 26.1% of revenue, net of third party, for the fourth quarter of 2017 compared to gross margin of $63.7 million, 31.2% of revenue, net of third party, for the fourth quarter of 2016. The 1% decrease in overall margin from that of the prior year was a result of nominal shortfall revenue earned in the fourth quarter of 2017 compared to $5 million in the fourth quarter of 2016. The reduction in shortfall revenue was offset by increased levels of operating activity in the fourth quarter of 2017 versus the fourth quarter of 2016. Gross margin increased to $241 million; 27.6% of revenue, net of third party, for the year-end 2017 versus that of the corresponding period in 2016 was a direct result of increased demand for oilfield services, resulting in higher equipment utilization rate, which was offset by lower revenue rates and $1.3 million in shortfall revenue being earned compared to $17.1 million in 2016.Depreciation expense in the year was $325.8 million, 7% lower than $349.9 million for the prior year. Depreciation was lower this year compared with that of last year due to certain operating assets now being fully depreciated, in which case no further depreciation expense is required on such assets.G&A expense in the fourth quarter of 2017 was 30% lower than that of the fourth quarter of 2016. General -- G&A expense for the year ended December 31, 2017, was 25% lower than the year ended December 31, 2016. The decrease in G&A expense resulted from the company's continued initiatives to reduce costs.Total debt, net of cash balances, increased by $7.6 million or 1% in the fourth quarter of 2017 from $700 million on September 30, 2017, to $707.6 million at December 31, 2017, and increased $19.9 million or 3% from the year ended December 31, 2016, from $687 million of that of the prior year.Net purchases of property and equipment for the fourth quarter of 2017 totaled $25.2 million compared to net purchases of $2.8 million in the corresponding period of 2016. Net purchases of property and equipment during the fiscal year ended 2017 totaled $117.7 million compared to net purchases of $29.1 million in the corresponding period 2016. The company added 3 new ADR drilling rigs and 1 service rig in 2017. Those rigs were partially assembled from equipment that were part of the rig build program that the company halted in 2014 to preserve the balance sheet in a declining market. On that note, I'll turn it back to you Bob.
Thanks, Mike. So let's go to the other Mike for a summary of the 2017 highlights in our U.S. and Latin American business, along with some outlook into how we feel the 2018 year is shaking up. Over to you Mike.
Okay. Thanks, Bob, and good afternoon, everyone. I'll start out with the U.S. United States recorded $459.5 million in revenue in 2017, comprising of over 40% of the total revenues from the company. That was a 36% increase of $338 million revenue recorded in 2016. U.S. well service fleet also recorded a 36% increase year-over-year in operations and also saw a 25% increase quarter-over-quarter. U.S. drilling rig utilization ended up at right around 60% end of the fourth quarter 2017 to 63% increase from the 30% utilization in the fourth quarter 2016. Through 2017, we super spec-ed an additional 8 of our ADR 1500s and also added a new build ADR 1500 with our state-of-the-art Edge Controls and rig operating system. We now have a fleet of 20 super-spec rigs operating in the Permian, all contracted. Our directional business in the U.S. is currently focused in the Rocky Mountains and is running 5 to 7 jobs daily. We tend to focus our directional drilling on more turnkey work where we can easily integrate the operation and generate higher returns in an IPM-type model. We are also starting to see quarter-over-quarter growth in our frac flowback business unit as fracking utilization ramps back up.The company's 3 main operating areas in the United States: the Rockies, California and the Permian Basin have all seen increases in activity in the second half of 2017. As of December of '17, there are 10 rigs running in the Rockies, 11 in California and 19 in the Permian. Of these rigs, over half are on longer-term contracts, and about 1/3 of the active rigs are on guaranteed contracts going out as far as 2020. There is still a somewhat tighter market in the West Coast and Rockies. However, pricing increases in the Permian for high-spec walking rigs are putting spot rates in the plus-or-minus $23,000 to $25,000 range with the Edge -- Ensign Edge Controls product suite.Moving over to Latin America. Ensign's international division operates a total of 16 rigs in Latin America with approximately 50% to 60% utilization on any given day. The company operates 8 rigs in Argentina while running between 50% and 60% utilization, continuing to focus on the Neuquén gas play working for international major oil companies. As I'm sure most of you are aware, we guaranteed 4 of $7.50 per million unconventional gas pricing continues to drive Neuquén investment. Ensign also has 8 rigs in Venezuela, of which we're running 40% to 50% activity. Here, we're continuing to manage our accounts receivable and which -- in a challenging geopolitical environment. We have strategically moved our contracts to mix of companies to segregate our accounts receivable challenges. And for clarity, a mix of company is made up of partnership between a national oil company owns 60% and the IOC which owns 40%.And with that, I'll turn it back to you, Bob.
Thanks, Mike. So we move to Canada and international business unit. Tom Connors looks after both of those, the Canadian and international business unit. Tom will fill us in on the significant events in 2017 for each of these business units over 12 months and what we've been seeing in the areas for the first part of 2018. Over to you, Tom.
Good afternoon, everyone, and I'll start with Canadian drilling. And Ensign maintained the utilization premium of 39% in the quarter versus an industry average of 34.3%. Our fleet of 1500s, 1000s and 850s continues to provide performance capabilities demanded by our customers in a competitive market, and in many cases, are now further enhanced by our Edge technology platform, which is expanding our capability and revenue-generation opportunities.These contracts roll over on to new contracts. Rates continues to improve, particularly for higher spec rates and deeper classes, while rates for these specific classes continued to improve from the trough in 2016. The overall average rate increase for the entire fleet was somewhat flat with a modest increase in Q4 versus the same quarter in 2016, excluding the impact of any shortfall payments.Late in November and early December, the impact of a deteriorating gas market and higher differentials have begun to delay the start of winter drilling programs for cost reductions and levels of activity that were previously anticipated. Corresponding activity in Q1 look similar to activity in Q1 2017 with perhaps slightly slower activity in March on a year-over-year basis.On our directional drilling business, directional had a similar Q4 to the same period last year and was negatively impacted by startup costs and preparation for a more active Q1 in 2018. Q1 continues to be relatively active quarter as the 2 services truly become integrated.In our well servicing business, Canadian well servicing activity in the quarter was slightly lower than the previous year, but as the general market -- sorry, as the general market slowed down into the Christmas break.Attracting crews for short-term work remains a challenge. However, rates have been improving slowly and steadily, which is a trend we continue to expect for the remainder of 2018.Our testing business has had challenges with rates and activity for the previous 2 years. But beginning in Q4 of 2017, we began to see improved rates and increasing levels of activity, which is a trend we'll expect to continue again through 2018.Our rental business -- our rental rates and activity continued to improve in Q4. We expect a relatively flat to modest growth in 2018 versus 2017 as the market for ancillary services around the drilling rigs show tighter[indiscernible] for certain assets.Our overall outlook for the Canadian business. We expect overall industry activity in Canada in 2018 to remain fairly flat with similar or slightly less days than 2017. While demand for deeper higher-spec rig types remains relatively healthy, average price for the overall fleet is expected to remain fairly flat with somewhat potentially modest growth to the upside as some rigs roll over on to new contracts.Our Australian business. As Bob alluded to, we are the largest drilling contractor in Australia and with 50% of days with 30% of the fleet. While activity remained flat through 2017, we are anticipating a slight improvement in drilling days with an approximate increase of 10% to 15% in activity in 2018 due to demand for drilling related to domestic gas supply. Pricing has also stabilized and is beginning to improve, particularly for equipment and personnel with demonstrated performance capability. While pricing is expected to improve, the overall increase for the fleet average will be modest due to the longer-term nature of most contracts in the area.And in our MENA business, which -- activity bottomed to 3 rigs. As Bob alluded to earlier, in Oman, in 2017, with those rigs remaining on long-term contracts with slightly improved rates over 2017. The outlook continues to improve as the demand for existing rigs improve with some anticipated or active open tenders that may be potentially awarded that will increase the active rig count in the region late in 2018 or early 2019.And with that, I'll turn it back to you Bob.
Thanks, Tom. So we'll turn back to the operator for Q&A.
[Operator Instructions] Your first question comes from the line of Ben Owens with RBC Capital Markets.
I have a question about the account receivable in Venezuela. You guys mentioned in the press release that you were assuming even collections over a 5-year period. Is that because it's structured as kind of a promissory note that dates back over 5 years?
No. So what we've done is -- Sure. So what we've done is looked at sort of how long it's been for us to actually collect the balance. And most likely, it looks like it's going to be about a 5-year period. So there's no disputes on the invoices that we have with PDVSA. It's more of just the collections U.S. dollars. We do collect these throughout the year from them. So we took the approach that it's really sort of a source of financing for the PDVSA therefore its expectable over the next 5 years.
Okay, got it. I appreciate that. Switching gears a little bit. You guys talked about leading-edge day rates in the Permian of around $23,000 to $25,000 a day, and then you mentioned that included the Ensign Edge system. Just curious how much of that day rate was being contributed by the Edge Controls system.
Sure, sure. No. Good question. So, Ben, as any new technology rolls out, the adaptation by the operator always starts off building along the way. So I would say that you probably think of it as $1,000 a day, somewhere in that range. Maybe it's not just $15,000, but probably more like $1,000 a day. But as we have the platform now to add -- I touched on a few apps, the [ FuelMizer ], the ROP optimizer, things like that. These are apps that we're building with another party that should be able to push out to any of our rigs, and those will be extra incremental apps. if the operator wants to turn them on, they'll probably be charged out at $300 to $400 a day type of thing.
Okay, got it. Last question for me. I think you guys mentioned total of 40 rigs running in your 3 main markets in the U.S. currently. Just kind of curious on would you guys have a line of sight through the first quarter, second quarter on any other further rig activations coming in the U.S.?
Yes. Mike, do you want to talk to that a little bit where we're seeing some increased demand and maybe talk to California Rockies and the Permian a little bit?
Yes. I mean, there's -- I think there will be some mid- to late second quarter increased demand in all 3 areas, and we have some additional product. California is probably the best area where it's just sitting on the ground ready to go. The other 2 areas will -- depending on what people are looking for, some that would have upgrades and refurbishments, but there's other potential plays where we still have existing assets that would be fit as is.
[Operator Instructions] Your next question comes from Jon Morrison with CIBC Capital Markets.
Can you talk about your pricing outlook in Canada? And do your comments on the tightness in the AC 1500 triple market in the U.S. hold in Canada? Or would you expect pricing for even the leading-edge rigs to be fairly flat from here on out?
Yes. I think that it's a good question. I think that -- I mean, what you're seeing is the super-spec rigs in the Permian leave the charge on the mid-20 rigs. In Canada, because -- I mean, that market -- and Tom could talk to it perhaps a little bit. That market is running 80% utilization. So those rigs are in a strong market where you can move things a little bit. Tom, do you want to explain on the Canadian market a little bit on the 1500s, particularly?
Yes. Just following on Bob's comments, if you look at the cost of rig in Kansas currently running somewhat 80% utilization, so it does have a little bit more pricing traction. And then particularly you start drilling in and bundling in things like Edge and again allows you to charge for that and get incremental revenue over and above the day rates. So as those rigs roll off contract and on to new ones, we have them signing into higher rates, and we expect to see some movement. But I would say if you look at the average for the overall fleet, you still have a lot of singles and doubles in other categories, which are moving as well. But I would say the increase looks more modest. But certainly, traction for that portion of the fleet is still relatively healthy for Canada and the rates not a lot different than the U.S. market. Not quite moving at the same pace as the Permian but still fairly healthy for that class of rig.
So given that commentary, it would be fair to say that you're not looking at redeploying any of your deeper higher-spec Canadian rigs to the U.S. at this stage.
Well, it's a good question. We've seen some of the competitors -- I believed, we've moved a few in the U.S. quite early on. I would say that our current client base is filling our needs for the asset base we have currently in Canada. It's always an option. But right now, it's -- we have no definite plans to move any rigs from Canada down into the U.S., so we have them all contracted. We don't have any available. As Tom pointed out, day rates are starting to move into the low 20s. And that's the rig in Canada. And currency-agnostic, it's starting to be similar to what we've seen in the U.S.
When you think about contracts rollover in the U.S. fleet and the momentum you've mentioned on the pricing side, would you expect your U.S. revenue per operating day to migrate higher in the next few quarters? I'm just trying to get a sense of whether there's anything in Q4 that put that number to be artificially high and we shouldn't be thinking about that being sustainable or expendable go forward?
Yes. I -- there's nothing special in the fourth quarter, Jon, that -- on a sequential quarter basis that would lead one to believe that it's not repeatable. I mean, we're seeing, Mike and his team down in the U.S. turning our contracts. We signed 6-month contracts in the U.S. Some guys jump up on the table saying, "Sign the 2-year contract." But given how it works, you sign a longer-term contract, you're getting less than the day rate.
Bob, does the tightness in the high-spec market in the U.S. right now make you contemplate doing new builds? And how far apart is leading-edge pricing and contract duration opportunities that you're getting today away from where you would need to see it to go and build more ADRs at this point?
Yes. I think there's 2 things happening, Jon. In the Permian, we're seeing the rate of pace of increase slowed down. We're also seeing our clients, the people that own our clients looking more towards the yield than they are towards barrel per day increases. But I would say that the -- basically on the new build, we need to see probably closer to $30,000 a day before a $20 million to $25 million new build starts to become attractive again. And there's a little bit of space between those 2 numbers right now.
The next one is probably for Mike Nuss. Can you give a regional update on what you're seeing in California right now? Obviously, there's large concerns about Lat Am heavy volumes potentially falling off given what's going on in Venezuela, but yet we're capacity-constrained in Canada. So do you see any potential for that being a bright spot for activity in the coming year? And are your customers having any conversations about getting ready for a more active '18?
Yes. I think in -- with the oil prices in the 60s that works more favorably in California, so we are seeing increased demand and also better stability of what we do have running. So we are activating another couple rigs, so that area looks pretty solid.
Okay. Would you expect it to ramp up much more meaningfully from where we are today?
I don't know exactly what you mean by meaningful. I think there'll be some increased activity, but I think it'll be somewhat conservative. If you just look at the client base out there, there's still quite a few independents. And the clients out there are somewhat of a conservative nature still, so I think there'll be increases, but I don't know that they'll be overly robust at this time. I think it'll be conservative growth.
Okay. Just in terms of the Argentine and Middle Eastern tendering opportunities, can you give more color on the size of those tenders and whether those opportunities would require new builds and what your appetite is to build more rigs and put them in those markets at this point?
Yes. In Latin America, of course, I mean, outside of Venezuela, Argentina is -- it seems to be quite a steady market. I don't think that we're after putting in new rigs in the market. I don't think the market is demanding that right now. In the Middle East, Middle East is kind of an interesting animal. Oman, which we know very well of course. All these Middle Eastern areas come out for new build contracts every year. They award a few them. And basically, the prices that they're willing to pay, there just seems to be a big spread still between that. So we're not seeing a lot of people take that up. I mean, you're seeing some consolidation in the business. You probably saw that this morning in the Oman area but still a very tough market over there. But the Oman market is a market that we've done very well and showing technology with our smaller ADRs. And Tom and his team are working on some new opportunities attracting -- I wouldn't say new builds, but fairly new rigs that could be deployed into the area and make the margin that we would expect of them.
The next question is for Mike Gray. How do you think about rightsizing the write-downs that you took in Venezuela? And is it fair to assume that if you look at the total PP&E and receivables that you can infer a lot in the country based on what you put out in the release that your total cap on the country is around $50 million?
Yes. That number would be correct. As for any of the write-down, we still think the amounts collectible the time value of the money over the next 5 years. I mean, the big thing for us is more when PDVSA goes back to work and start paying invoices and we are collecting bolivars, but it's more of the U.S. dollars flowing in that is slowing down and big reason for the discount over the 5 years.
Okay. And is it fair to think about the receivables being a combination of mix and PDVSA?
No. The discount we took was strictly on PDVSA. The remainder is the mix of the companies of which we do not foresee any issues on the collections.
Okay. Last one, just for me, your comments on Venezuela are obviously more cautious than past quarters, which makes a ton of sense. Is your line of sight that you have right now, just based on what the mix of companies are telling you, is going to look like the next few months? Or do you have visibility that extends beyond that?
Mike Gray, do you want to take that?
Sure. I think the visibility is a little more caution just with the sanctions that came out and people trying to understand how the sanctions are going to be sort of applied. But for the most part, I think the visibility is kind of as expected and similar to what we've had sort of in prior quarters.
There are no further questions at this time. I will now turn the call back over to Bob Geddes.
Thanks, Chantelle. So to wrap up our comments in the 2017 year, I just want to say that Ensign has always been a steward of our shareholders' equity and has despite how tough the business has been managed to continue to pay our shareholders with the dividends since 1995. We continue to define that as we integrate more of our advanced Ensign Edge Controls on our rigs. And when that is coupled with our optimization team, we define a more collaborative environment developing.With that, we find that we are, in most cases, negotiating rigs and new contracts rather than being subjective to the 3 bids and the buy process. As we look into the year ahead, we're definitely seeing strong demand continuing for our Tier 1 and super-spec-ed rigs solidly into the mid-20s as we pointed out.The utilization on the fleet, we're generally expecting a 5% to 10% year-over-year increase in operating days as our premium fleet yields continues strong demand.All other lines of business, we're also seeing strengthening business as we move through '18. As previously mentioned, our CapEx guidance for 2018 remains in the $65 million range, top rate to maintain the high-spec fleet through 2018. Notwithstanding, I'll point out that Ensign, over the past 10 years, a decade in which we've had the financial crisis wreak havoc and the commodity prices in the oil and gas market fall apart, we generated $1.30 EBITDA for every $1 of CapEx invested. So I leave that. Thanks for joining us today. We look forward to sharing our first quarter 2018 results with you in about 3 months. Thank you again.
This concludes today's conference call. You may now disconnect.